METHODS AND SYSTEMS FOR OPTIMIZING THE STORAGE OF CARBON IN SUBTERRANEAN MAFIC AND ULTRAMAFIC ROCK FORMATIONS

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority under 35 U.S.C. § 119 to U.S. Provisional Patent Application Ser. No. 63/459,774, titled “Methods For Storing Carbon In Subterranean Mafic And Ultramafic Rock Formations” and filed on Apr. 17, 2023, the entire contents of which are hereby incorporated herein by reference. This application also claims priority under 35 U.S.C. § 119 to U.S. Provisional Patent Application Ser. No. 63/459,775, titled “Horizontal Drilling Operations In Mafic And Ultramafic Subterranean Rock Formations For Storage Of Carbon” and filed on Apr. 17, 2023, the entire contents of which are hereby incorporated herein by reference.

TECHNICAL FIELD

The present disclosure relates to optimizing the carbon dioxide (CO₂) storage potential of mafic (e.g., basaltic) and/or ultramafic rock formations. More particularly, the present disclosure is directed to optimized field development methods for permanently storing carbon in subterranean basaltic and ultramafic rock formations, including horizontal wellbores, using a mineralization process.

BACKGROUND

Storing CO₂ in underground rock formations generally requires that the storage is permanent over a timeframe of centuries. Obtaining this goal generally requires that the CO₂ is either (1) permanently contained as a gas or supercritical fluid in a subterranean storage formation that is overlain by an impermeable formation capable of preventing the CO₂ from buoyantly migrating upward or (2) permanently precipitated as a solid deposit in a subterranean storage formation via chemical reaction with that formation (a.k.a. mineralization).

The process of subterranean CO₂ mineralization can occur by moving a water/CO₂ mixture through basaltic and/or ultramafic rock formations through the use of wells penetrating that formation. This process of subterranean CO₂ mineralization is presently undertaken only using non-horizontal wells. A water/CO₂ mixture is generally injected into a subterranean formation via one well or a set of wells. As the water/CO₂ mixture moves through the formation, reactions can occur with the formation's mineral content, resulting in carbonate minerals being deposited as a solid on the contacted surfaces of the formation. The reactions continue so long as CO₂ is available in the injected water. Ultimately, the CO₂-depleted water may be produced to surface via producing wells where it is reinfused with CO₂ in preparation for reinjection. Maximizing the carbon storage potential of such a process requires not only a keen understanding of the rate that carbon can be deposited in a storage formation, but also prudent plans for well placement, well design, water volume throughput, and monitoring methods of the in-situ mineralization process.

The cost of deploying such a process can be heavily influenced by the type of wells being used. Developing a full-scale carbon mineralization project using only non-horizontal wells may sometimes be necessary, but can require large volumes of metal pipes for their construction and for individually connecting the wells at the surface to centralized fluid processing facilities. Additionally, constructing an individual non-horizontal well for each fluid injection or production site in the subterranean storage formation can require significant drilling rig time. All this can significantly impact overall project costs. Thus, any method that can reduce the number of wells drilled for a subterranean carbon mineralization project can also potentially reduce the overall project cost by requiring fewer total metal pipes and less total rig time. Such a method may be the use of horizontal wellbores.

Within the storage formation, a single horizontal well can be used to inject or produce fluid at multiple sites, thereby reducing the number of wells drilled from surface. Drilling and completing a single horizontal well requires drilling more distance, installing more metal pipes, and using more ancillary well services than the construction of a single non-horizontal well. Thus, construction of a single horizontal well generally costs more than construction of a single non-horizontal well. However, a single horizontal well has the potential to perform the task of multiple non-horizontal wells. Which, for a full field development, can reduce project-level costs.

SUMMARY

In general, in one aspect, the disclosure relates to a system for implementing subterranean carbon mineralization. The system may include a fluid injection well subsystem that includes an injection wellbore that traverses and is in fluid communication with a subterranean rock formation comprising a group consisting of a mafic rock formation, an ultramafic rock formation, and a combination thereof. The fluid injection well subsystem may also include a pumping system configured to pump a pressurized fluid into the injection wellbore, where the pressurized fluid comprises carbon dioxide. The fluid injection well subsystem may further include a fluid injection completion system disposed at an injection range along the injection wellbore, where the fluid injection completion system is configured to control an injection rate of the pressurized fluid from the injection range of the injection wellbore into an active storage zone within the subterranean rock formation. The system may also include a fluid production well subsystem that includes a production wellbore that traverses and is in fluid communication with the subterranean rock formation. The fluid production well subsystem may also include a fluid production completion system disposed at a production range along the production wellbore, where the fluid production completion system is configured to control an inflow rate of production fluid from the active storage zone within the subterranean rock formation into the production range of the production wellbore. The system may further include a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation, where the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization.

In another aspect, the disclosure relates to a method for implementing subterranean carbon mineralization. The method may include injecting a pressurized fluid into an injection wellbore, where the pressurized fluid comprises carbon dioxide and an additional fluid, where the injection wellbore traverses and is in fluid communication with a subterranean rock formation comprising one of a group consisting of a mafic rock formation, an ultramafic rock formation, and a combination thereof. The method may also include controlling, using a fluid injection completion system, an injection location and an injection rate of the pressurized fluid from the injection wellbore to an active storage zone within the subterranean rock formation. The method may further include controlling, using a fluid production completion system, a production location and an inflow rate for a production fluid from the active storage zone within the subterranean rock formation into a production wellbore, where the production fluid comprises the additional fluid of the pressurized fluid without the carbon dioxide. The method may also include determining, using measuring equipment, that the carbon storage potential of the active storage zone is depleted. The method may further include abandoning the injection wellbore.

In yet another aspect, the disclosure relates to a method for identifying a subterranean volume to facilitate carbon mineralization. The method may include obtaining measurements of parameters associated with a subterranean rock formation that includes a group consisting of a mafic rock formation, an ultramafic rock formation, and a combination thereof, where the measurements are collected by measuring equipment. The method may also include evaluating the measurements. The method may further include identifying, based on evaluating the measurements, an active storage zone within the subterranean rock formation to facilitate the carbon mineralization.

These and other aspects, objects, features, and embodiments will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings illustrate only example embodiments and are therefore not to be considered limiting in scope, as the example embodiments may admit to other equally effective embodiments. The elements and features shown in the drawings are not necessarily to scale, emphasis instead being placed upon clearly illustrating the principles of the example embodiments. Additionally, certain dimensions or positions may be exaggerated to help visually convey such principles. In the drawings, reference numerals designate like or corresponding, but not necessarily identical, elements.

FIG. 1 shows a system with which example embodiments can be used according to certain example embodiments.

FIG. 2 shows a system diagram of a controller of the field system of FIG. 1 according to certain example embodiments.

FIG. 3 shows a computing device in accordance with certain example embodiments.

FIGS. 4A and 4B show an arrangement of a field system of four wellbores using a well placement strategy according to certain example embodiments.

FIGS. 5 through 8 show the progression of field systems using a field development strategy based on the arrangement shown in FIGS. 4A and 4B according to certain example embodiments.

FIGS. 9 through 12 show the progression of field systems using another field development strategy based on five wellbores in a grouping according to certain example embodiments.

FIG. 13 shows an arrangement of a field system using a well placement strategy in the form of a semi-line-drive well pattern according to certain example embodiments.

FIGS. 14 through 16 show the progression of field systems using a field development strategy based on the arrangement shown in FIG. 13 according to certain example embodiments.

FIG. 17 shows an arrangement of a field system using a well placement strategy in the form of a line-drive flow pattern according to certain example embodiments.

FIGS. 18 through 20 show the progression of field systems using a field development strategy based on the arrangement shown in FIG. 17 according to certain example embodiments.

FIG. 21 shows an arrangement of a field system using another well placement strategy according to certain example embodiments.

FIG. 22 shows a sectional view of part of a subsystem that includes an injection wellbore that may be used with the field system of FIG. 21 according to certain example embodiments.

FIG. 23 shows an arrangement of a field system using yet another well placement strategy according to certain example embodiments.

FIG. 24 shows a sectional view of part of a subsystem that includes a production wellbore that may be used with the field system of FIG. 23 according to certain example embodiments.

FIG. 25 shows an arrangement of a field system using still another well placement strategy according to certain example embodiments.

FIGS. 26 and 27 show sectional views of part of subsystems that include injection wellbores that may be used with the field system of FIG. 25 according to certain example embodiments.

FIG. 28 shows an arrangement of a field system using yet another well placement strategy according to certain example embodiments.

FIG. 29 shows a sectional view of part of a subsystem that includes a production wellbore that may be used with the field system of FIG. 28 according to certain example embodiments.

FIGS. 30 through 32 show sectional views of part of subsystems that include production wellbores that may be used in various field systems according to certain example embodiments.

FIG. 33 shows a flowchart of a method for implementing subterranean carbon mineralization according to certain example embodiments.

FIG. 34 shows a flowchart of a method for identifying a subterranean volume to facilitate carbon mineralization according to certain example embodiments.

DETAILED DESCRIPTION

The example embodiments discussed herein are directed to systems, apparatus, methods, and devices for carbon storage in subterranean mafic and ultramafic rock formations. Specifically, example embodiments may be directed to using carbon mineralization for storing carbon in subterranean mafic and ultramafic rock formations. Example embodiments may use land-based wellbores and/or subsea wellbores. Example embodiments may be designed to comply with certain standards and/or requirements. Optimized field developments for storing carbon in basaltic and/or ultramafic rock formations can be achieved using horizontal and/or non-horizontal wells combined with appropriate monitoring of the in-situ mineralization process via measurements above, at, and/or below the Earth's surface.

The use of the terms “about”, “approximately”, and similar terms applies to all numeric values, whether or not explicitly indicated. These terms generally refer to a range of numbers that one of ordinary skill in the art would consider as a reasonable amount of deviation to the recited numeric values (i.e., having the equivalent function or result). For example, this term may be construed as including a deviation of ±10 percent of the given numeric value provided such a deviation does not alter the end function or result of the value. Therefore, a value of about 1% may be construed to be a range from 0.9% to 1.1%. Furthermore, a range may be construed to include the start and the end of the range. For example, a range of 10% to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein. Similarly, a range of between 10% and 20% (i.e., range between 10%-20%) includes 10% and also includes 20%, and includes percentages in between 10% and 20%, unless explicitly stated otherwise herein.

A “subterranean formation” refers to practically any volume under a surface. For example, it may be practically any volume under a terrestrial surface (e.g., a land surface), practically any volume under a seafloor, etc. Each subsurface volume of interest may have a variety of characteristics, such as petrophysical rock properties, reservoir fluid properties, reservoir conditions, hydrocarbon properties, or any combination thereof. For example, each subsurface volume of interest may be associated with one or more of: temperature, porosity, salinity, permeability, water composition, mineralogy, hydrocarbon type, hydrocarbon quantity, reservoir location, pressure, etc. Those of ordinary skill in the art will appreciate that the characteristics are many, including, but not limited to: shale gas, shale oil, tight gas, tight oil, tight carbonate, carbonate, vuggy carbonate, unconventional formation (e.g., a permeability of less than 25 millidarcy (mD) such as a permeability of from 0.000001 mD to 25 mD), diatomite, geothermal, mineral, etc. The terms “formation”, “subsurface formation”, “hydrocarbon-bearing formation”, “reservoir”, “subsurface reservoir”, “subsurface area of interest”, “subsurface region of interest”, “subsurface volume of interest”, and the like may be used synonymously. The term “subterranean formation” is not limited to any description or configuration described herein.

A “well” or a “wellbore” refers to a single hole, usually cylindrical, that is drilled into a subsurface volume of interest. A well or a wellbore may be drilled in one or more directions. For example, a well or a wellbore may be or include a vertical well, a horizontal well, a deviated well, and/or other type of well. A well or a wellbore may be drilled in the subterranean formation for exploration and/or recovery of resources. A plurality of wells (e.g., tens to hundreds of wells) or a plurality of wellbores are often used in a field depending on the desired outcome.

A well or a wellbore may be drilled into a subsurface volume of interest using practically any drilling technique and equipment known in the art, such as geosteering, directional drilling, etc. Drilling the well may include using a tool, such as a drilling tool that includes a drill bit and a drill string. Drilling fluid, such as drilling mud, may be used while drilling in order to cool the drill tool and remove cuttings. Other tools may also be used while drilling or after drilling, such as measurement-while-drilling (MWD) tools, seismic-while-drilling tools, wireline tools, logging-while-drilling (LWD) tools, or other downhole tools. After drilling to a predetermined depth, the drill string and the drill bit may be removed, and then the casing, the tubing, and/or other equipment may be installed according to the design of the well. The equipment to be used in drilling the well may be dependent on the design of the well, the subterranean formation, the hydrocarbons, and/or other factors.

A well may include a plurality of components, such as, but not limited to, a casing, a liner, a tubing string, a sensor, a packer, a screen, a gravel pack, artificial lift equipment (e.g., an electric submersible pump (ESP)), and/or other components. If a well is drilled offshore, the well may include one or more of the previous components plus other offshore components, such as a riser. A well may also include equipment to control fluid flow into the well, control fluid flow out of the well, or any combination thereof. For example, a well may include a wellhead, a choke, a valve, and/or other control devices. These control devices may be located on the surface, in the subsurface (e.g., downhole in the well), or any combination thereof. In some embodiments, the same control devices may be used to control fluid flow into and out of the well. In some embodiments, different control devices may be used to control fluid flow into and out of a well. In some embodiments, the rate of flow of fluids through the well may depend on the fluid handling capacities of the surface facility that is in fluidic communication with the well. The equipment to be used in controlling fluid flow into and out of a well may be dependent on the well, the subsurface region, the surface facility, and/or other factors. Moreover, sand control equipment and/or sand monitoring equipment may also be installed (e.g., downhole and/or on the surface). A well may also include any completion hardware that is not discussed separately. The term “well” may be used synonymously with the terms “borehole,” “wellbore,” or “well bore.” The term “well” is not limited to any description or configuration described herein.

As defined herein, a vertical wellbore shall be a wellbore (or portion thereof) that has no more than a 15° deviation from an absolute vertical orientation. Further, a non-horizontal wellbore shall be defined as a wellbore (or portion thereof) has no more than a 60° deviation from an absolute vertical orientation. In addition, a horizontal wellbore shall be defined as a wellbore (or portion thereof) has no more than a 30° deviation from an absolute horizontal orientation.

It is understood that when combinations, subsets, groups, etc. of elements are disclosed (e.g., combinations of components in a composition, or combinations of steps in a method), that while specific reference of each of the various individual and collective combinations and permutations of these elements may not be explicitly disclosed, each is specifically contemplated and described herein. By way of example, if an item is described herein as including a component of type A, a component of type B, a component of type C, or any combination thereof, it is understood that this phrase describes all of the various individual and collective combinations and permutations of these components. For example, in some embodiments, the item described by this phrase could include only a component of type A.

In some embodiments, the item described by this phrase could include only a component of type B. In some embodiments, the item described by this phrase could include only a component of type C. In some embodiments, the item described by this phrase could include a component of type A and a component of type B. In some embodiments, the item described by this phrase could include a component of type A and a component of type C. In some embodiments, the item described by this phrase could include a component of type B and a component of type C. In some embodiments, the item described by this phrase could include a component of type A, a component of type B, and a component of type C.

In some embodiments, the item described by this phrase could include two or more components of type A (e.g., A1 and A2). In some embodiments, the item described by this phrase could include two or more components of type B (e.g., B1 and B2). In some embodiments, the item described by this phrase could include two or more components of type C (e.g., C1 and C2). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type A (A1 and A2)), optionally one or more of a second component (e.g., optionally one or more components of type B), and optionally one or more of a third component (e.g., optionally one or more components of type C).

In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type B (B1 and B2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type C). In some embodiments, the item described by this phrase could include two or more of a first component (e.g., two or more components of type C (C1 and C2)), optionally one or more of a second component (e.g., optionally one or more components of type A), and optionally one or more of a third component (e.g., optionally one or more components of type B).

When used in certain systems (e.g., for certain subsea field operations), example carbon storage in subterranean mafic and ultramafic rock formations can be designed to comply with certain standards and/or requirements. Examples of entities that set such standards and/or requirements can include, but are not limited to, the Society of Petroleum Engineers, the American Petroleum Institute (API), the International Standards Organization (ISO), the Bureau of Safety and Environmental Enforcement (BSEE), the International Association of Classification Societies (IACS), and the Occupational Safety and Health Administration (OSHA).

If a component of a figure is described but not expressly shown or labeled in that figure, the label used for a corresponding component in another figure may be inferred to that component. Conversely, if a component in a figure is labeled but is not described, the description for such component may be substantially the same as the description for the corresponding component in another figure. The numbering scheme for the various components in the figures herein is such that each component is a three-digit number or a four-digit number, and corresponding components in other figures have the identical last two digits. For any figure shown and described herein, one or more of the components may be omitted, added, repeated, and/or substituted. Accordingly, embodiments shown in a particular figure should not be considered limited to the specific arrangements of components shown in such figure.

Further, a statement that a particular embodiment (e.g., as shown in a figure herein) does not have a particular feature or component does not mean, unless expressly stated, that such embodiment is not capable of having such feature or component. For example, for purposes of present or future claims herein, a feature or component that is described as not being included in an example embodiment shown in one or more particular drawings is capable of being included in one or more claims that correspond to such one or more particular drawings herein.

Example embodiments of carbon storage in subterranean mafic and ultramafic rock formations will be described more fully hereinafter with reference to the accompanying drawings, in which example embodiments of carbon storage in subterranean mafic and ultramafic rock formations are shown. Carbon storage in subterranean mafic and ultramafic rock formations may, however, be embodied in many different forms and should not be construed as limited to the example embodiments set forth herein. Rather, these example embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of carbon storage in subterranean mafic and ultramafic rock formations to those of ordinary skill in the art. Like, but not necessarily the same, elements (also sometimes called components) in the various figures are denoted by like reference numerals for consistency.

Terms such as “first”, “second”, “primary,” “secondary,” “above”, “below”, “inner”, “outer”, “distal”, “proximal”, “end”, “top”, “bottom”, “upper”, “lower”, “side”, “width,”, “height”, “depth”, “length”, “left”, “right”, “front”, “rear”, and “within”, when present, are used merely to distinguish one component (or part of a component or state of a component or orientation of a component) from another. This list of terms is not exclusive. Such terms are not meant to denote a preference or a particular orientation, and they are not meant to limit embodiments of carbon storage in subterranean mafic and ultramafic rock formations. In the following detailed description of the example embodiments, numerous specific details are set forth in order to provide a more thorough understanding of the invention. However, it will be apparent to one of ordinary skill in the art that the invention may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

FIG. 1 shows a system 100 with which example embodiments can be used according to certain example embodiments. FIG. 2 shows a system diagram of a controller 104 of the field system 100 of FIG. 1 according to certain example embodiments. The system 100 of FIG. 1 includes a fluid injection well subsystem 140, a fluid production well subsystem 180, a monitoring subsystem 190, one or more users 151, and a network manager 119. The fluid injection well subsystem 140 includes one or more carbon dioxide sources 141, one or more other fluid sources 144, one or more pumping systems 145, one or more controllers 204, and one or more injection wellbores 142, and piping 109. The fluid production well subsystem 180 includes one or more production fluid receivers 181, one or more pumping systems 185, one or more controllers 104, one or more production wellbores 182, and the piping 109. The monitoring subsystem 190 includes measuring equipment 160 and one or more controllers 104. In certain example embodiments, an objective of some or all of the system 100 is to implement subterranean carbon mineralization.

Each injection wellbore 142 of the fluid injection well subsystem 140 is configured to inject a pressurized fluid 143 (also sometimes called an injection fluid 143 herein) into one or more active storage zones 111 within a subterranean formation 110. In this way, each injection wellbore 142 traverses some or all of the subterranean rock formation 110. Also, each injection wellbore 142 is in fluid communication with the subterranean rock formation 110. The fluid injection well subsystem 140 may have any number (e.g., one, two, five, ten, twenty, one hundred) of injection wellbores 142. In this case, there are X injection wellbores 142 (injection wellbore 142-1 through injection wellbore 142-X). Multiple injection wellbores 142 may be drilled from the same pad or different pads. An injection wellbore 142 may be drilled for the sole purpose of storing carbon according to certain example embodiments. Alternatively, an injection wellbore 142 may have been drilled for a different purpose (e.g., production of hydrocarbons, extraction of water, saltwater disposal, geothermal) and later converted for use as an injection wellbore 142 according to certain example embodiments.

In some cases, an injection wellbore 142 may be held idle for a period of time rather than being used to inject the pressurized fluid 143 into an active storage zone 111 within a subterranean formation 110 (also sometimes called a subterranean rock formation 110 herein). An injection wellbore 142 that is put idle may later resume being used to inject the pressurized fluid 143 into an active storage zone 111. In addition, or in the alternative, an injection wellbore 142 may be converted to a production wellbore 182 (discussed below) at a point in time or for a period of time to extract production fluid 183 from an active storage zone 111 within a subterranean formation 110. An injection wellbore 142 that is converted to a production wellbore 182 may subsequently be converted back to an injection wellbore 142.

Within an injection wellbore 142 are one or more fluid injection completion systems 148 (FICSs 148). For example, in this case, injection wellbore 142-1 has M FICSs 148 (FICS 148-1-1 through FICS 148-1-M). The distance between the first FICS 148-1 (e.g., FICS 148-1-1) and last FICS 148-1 (e.g., FICS 148-1-M) of the injection wellbore 142-1 may be referred to as the injection range of the FICS 148-1. As another example, in this case, injection wellbore 142-X has N FICSs 148 (FICS 148-X-1 through FICS 148-X-N). The distance between the first FICS 148-X (e.g., FICS 148-X-1) and last FICS 148-X (e.g., FICS 148-X-N) of the injection wellbore 142-X may be referred to as the injection range of the FICS 148-X.

Each FICS 148 of an injection wellbore 142 of the fluid injection well subsystem 140 is located at a point in the injection wellbore 142 that is adjacent to one or more active storage zones 111 within the subterranean formation 110. In some cases, an active storage zone 111 may be a formation layer within the subterranean formation 110. Alternatively, an active storage zone 111 may be a subset of a formation layer within the subterranean formation 110. As yet another alternative, an active storage zone 111 may be a target volume of space within the subterranean formation 110 that may overlap with multiple formation layers. Each FICS 148 of the fluid injection well subsystem 140 may be configured to adjust the injection range along the injection wellbore 142 based on the detection of the mineralized carbon in the active storage zone 111 within the subterranean rock formation 110 by the monitoring subsystem 190.

The part of the injection wellbore 142 (and so also the FICS 148 within that part of the injection wellbore 142) may be oriented vertically, horizontally, and or have some other orientation relative to an active storage zone 111. Each FICS 148 of an injection wellbore 142 of the fluid injection well subsystem 140 is configured to control the injection rate of the pressurized fluid 143 that flows from the injection wellbore 142 into the active storage zone 111 (or one or more portions thereof) of the subterranean rock formation 110. In some cases, a FICS 148 may be manipulated (e.g., opened, closed) passively (e.g., based on pressure differentials and local components that operate based on exceeding a threshold pressure differential, based on an amount of time). In addition, or in the alternative, a FICS 148 may be manipulated actively (e.g., using a controller (e.g., controller 204, controller 104), one or more sensor devices and/or other types of measuring equipment 160, and/or other external components).

In some cases, a FICS 148 may be integrated with (e.g., may be a sub within) a tubing string 149 inserted into the injection wellbore 142. For example, the FICSs 148-1 of injection wellbore 142-1 are integrated with tubing string 149-1. As another example, the FICSs 148-X of injection wellbore 142-X are integrated with tubing string 149-X. The location of a FICS 148 along the tubing string 149 may be designed to coincide with one or more active storage zones 111 of the subterranean rock formation 110. In some cases, the tubing string 149 may be moved further into the injection wellbore 142 and/or some distance out of the injection wellbore 142 over time to use a FICS 148 with respect to different active storage zones 111 (or portions thereof) of the subterranean rock formation 110.

Each FICS 148 may have any of a number of configurations and/or features. For example, a FICS 148 may be or include an autonomous self-regulating injection control valve (ASRICV). For example, a ASRICV may include a chamber disposed within the cavity, where the chamber is bounded by a chamber wall, where the chamber wall has a second flow orifice that traverses therethrough, and where the first flow orifice and the second flow orifice are aligned with each other. In such a case, the ASRICV may also include a sleeve movably disposed within the chamber, where the sleeve has an open position and a plurality of closed positions, and where the sleeve partially covers the first flow orifice and the second flow orifice when in one of the plurality of closed positions. Further, in such a case, the ASRICV may include an actuator disposed within the chamber and in communication with the sleeve, where the actuator is configured to move the sleeve between the open position and the plurality of closed positions, and where the actuator is configured to operate automatically based on conditions in the wellbore. More information about ASRICVs may be found, for example, in U.S. patent application Ser. No. 18/530,316 titled “Autonomous Self-Regulating Injection Control Valve (ASRICV)” and filed on Dec. 6, 2023, the entire contents of which are hereby incorporated herein by reference. When an injection wellbore 142 has multiple FICSs 148, the configuration of one FICS 148 may be the same as, or different than, the configuration of one or more of the other FICSs 148.

The subterranean rock formation 110 may include one or more formation layers (e.g., shale, sand) that are located below ground level 112. The subterranean rock formation 110 may have within its volume one or more active storage zones 111. An active storage zone 111 may have certain characteristics (e.g., include of a mafic rock formation, include an ultramafic rock formation, include a combination of mafic and ultramafic rock formations) that are conducive to reacting with at least part (e.g., carbonic acid) of the pressurized fluid 143 as the pressurized fluid 143 passes therethrough from an injection wellbore 142 to a production wellbore 182.

The pressurized fluid 143 is formed by mixing carbon dioxide that originates from one or more of the carbon dioxide sources 141 and one or more other fluids (e.g., water) that originate from one or more of the other fluid sources 144. For example, the pressurized fluid 143 may be a weak carbonic acid that forms when carbon dioxide is dissolved in water. As another example, the pressurized fluid 143 may be a CO₂ -enriched aqueous solution. In such cases, the CO₂ -enriched aqueous solution may react with exposed rock surfaces of the subterranean rock formation to form mineralized carbon in solid form when the pressurized fluid 143 is injected via the fluid injection well subsystem (e.g., using a FICS 148) from the injection range into the active storage zone 111 within the subterranean rock formation. Further, removal of the CO₂ -enriched aqueous solution from the pressurized fluid 143 via reaction with exposed rock surfaces in the storage zone 111 results in transition fluid 144, where the transition fluid 144 mixes with formation fluid in the active storage zone 111 within the subterranean rock formation 110 to form production fluid 183 as the transition fluid 144 flows toward the production range along the production wellbore 182. In some cases, production of the production fluid 183 from the subterranean rock formation 110 at the production location along the production wellbore 182 allows for additional injection of the injection fluid 143 into the subterranean rock formation 110 at the injection location along the injection wellbore 142. The pressurized fluid 143 is transported to one or more of the injection wellbores 142 through piping 109 using one or more of the pumping systems 145. Examples of a pressurized fluid 143 may include, but are not limited to, a carbonic acid (e.g., a weak carbonic acid) and liquid carbon dioxide.

The pressurized fluid 143 may be in a liquid state. In addition, or in the alternative, the pressurized fluid 143 may be in a gaseous state and/or a solid state. In some cases, the composition and/or properties of the pressurized fluid 143 can be subject to environmental variations (e.g., as controlled by the pumping systems 145) and/or time-varying changes. The piping 109 may include multiple pipes, ducts, headers, elbows, joints, sleeves, collars, and similar components that are coupled to each other (e.g., using coupling features such as mating threads or flanged connections) to establish a network for transporting the pressurized fluid 143, including components thereof, within the fluid injection well subsystem 140 of the system 100. Each component of the piping 109 may have an appropriate size (e.g., inner diameter, outer diameter) and be made of an appropriate material (e.g., steel, PVC) to safely and efficiently handle the pressure, temperature, flow rate, and other characteristics of the pressurized fluid 143 (including components thereof) and/or the production fluid 183 (including components thereof) that pass therethrough. In some cases, as when the pressurized fluid 143 (including components thereof) and/or the production fluid 183 (including components thereof) include one or more solids, then the piping 109 may be more generally considered part of a conveyance system that may include components such as, but not limited to, a conveyor belt, trucks, and mining equipment.

There may be a number of valves placed in-line with the piping 109 at various locations in the fluid injection well subsystem 140 to control the flow of the pressurized fluid 143 (including components thereof) that flow through the piping 109. A valve may have one or more of any of a number of configurations, including but not limited to a guillotine valve, a ball valve, a gate valve, a butterfly valve, a pinch valve, a needle valve, a plug valve, a diaphragm valve, and a globe valve. A valve can be used for control action and have a trim characteristic that describes the nature of the control action in the overall process. Typical examples can include, but are not limited to, equal-percentage, linear, and quick-opening. Each of control action valves can determine the nature of the flow response relative to the %-open position of the valve and is intended to achieve desired control system response characteristics. One valve may be configured the same as or differently compared to another valve in the system 100. Also, one valve may be controlled (e.g., manually, automatically by a controller 104) the same as or differently compared to another valve in the system 100. In some cases, a valve can be a general term for one or more other forms of control elements, including but not limited to adjustable speed drive motor controllers, blowers, fans, and pumps.

Each carbon dioxide source 141 may hold, contain, or include one or more forms (e.g., a pure gas, a diluted gas, a pure liquid, a diluted liquid) of carbon dioxide. Examples of a carbon dioxide source 141 may include, but are not limited to, a tank, a pipeline, an exhaust outlet, and a processing plant. Each carbon dioxide source 141 may be configured to deliver the carbon dioxide through some of the piping 109 to mix with the other fluids to form the pressurized fluid 143. A carbon dioxide source 141 can include one or more of a number of components that may move and/or process the carbon dioxide, including but not limited to a motor, a pump, a compressor, piping 109, a valve, a controller (e.g., one of the controllers 204), a power source, a power supply, an energy storage device, a sensor device or other type of measuring equipment 160, a heater, a cooling unit, an ignitor (e.g., a sparkplug), an ignition transformer, a protective relay, and an electrical cable.

Each other fluid source 144 may hold, contain, or include one or more compounds that may mix with the carbon dioxide that originates from the carbon dioxide sources 141. Such other compounds that originate from an other fluid source 144 may be in liquid form, in gaseous form, and/or in solid form. Examples of such other compounds (or portions thereof) that originate from an other fluid source 144 may include, but are not limited to, water (e.g., surface water, production fluid 183, brackish water) and steam. Examples of an other fluid source 144 may include, but are not limited to, a tank, a pipeline, a lake, a river, an ocean, an exhaust outlet, one or more of the production fluid receivers 181, and a processing plant.

Each other fluid source 144 may be configured to deliver the compound through some of the piping 109 to mix with the carbon dioxide to form the pressurized fluid 143. An other fluid source 144 can include one or more of a number of components that may move and/or process the compounds, including but not limited to a motor, a pump, a compressor, piping 109, a valve, a controller (e.g., one of the controllers 204), a power source, a power supply, an energy storage device, a sensor device or other type of measuring equipment 160, an ignitor (e.g., a sparkplug), an ignition transformer, a protective relay, and an electrical cable.

Each of the one or more pumping systems 145 is configured to deliver the pressurized fluid 143 to one or more of the injection wellbores 142 through some of the piping 109. A pumping system 145 may include one or more of a number of components, including but not limited to one or more controllers 204, a motor, a pump, a compressor, a fan, a blower, piping 109, a valve, one or more controllers, a power source, a power supply, an energy storage device, a sensor device or other type of measuring equipment 160, a protective relay, and an electrical cable. If a pumping system 145 lacks its own local controller 204, that pumping system 145 may be controlled by a controller 204 of another pumping system 145 and/or a controller 104 of the monitoring subsystem 190. The pumping system 145 of the fluid injection well subsystem 140 may be controlled to adjust the injection rate of the injection fluid 143 based on the detection of the mineralized carbon in the subterranean rock formation 110 by the monitoring subsystem 190.

When a pumping system 145 includes a controller 204, the controller 204 may control some or all aspects of the fluid injection well subsystem 140. The controller 204 may be substantially similar to a controller 104 of the monitoring subsystem 190, as described below. For example, a controller 204 of the pumping system 145 (or the fluid injection well subsystem 140 more generally) may include one or more components and/or similar functionality to some or all of a controller 104. Alternatively, the controller 204 may include one or more of a number of features in addition to, or altered from, the features of a controller 104. As described herein, control and/or communication with the controller 204 may include communicating with one or more other components of the system 100 and/or another system. In such a case, the controller 204 may facilitate such control and/or communication. The controller 204 may be considered a type of computer device, as discussed below with respect to FIG. 3.

Each production wellbore 182 of the fluid production well subsystem 180 is configured to produce or otherwise extract a production fluid 183 (also sometimes called a production fluid 183 herein) from one or more active storage zones 111 within the subterranean formation 110. In this way, each production wellbore 182 traverses some or all of the subterranean rock formation 110. Also, each production wellbore 182 is in fluid communication with the subterranean rock formation 110.

In some cases, the fluid production well subsystem 180 is among multiple fluid production well subsystems that are configured substantially the same as each other. In such cases, the fluid production completion system 188 of each of the fluid production well subsystems 180 may be configured to control the inflow rate of the production fluid 183 from the active storage zone 111 within the subterranean rock formation 110 into the production range of the production wellbore 182 of each of the fluid production well subsystems 180. Further, each of the fluid production well subsystems 180 may operate based on measurements made by the monitoring subsystem 190 to control the inflow rate of the production fluid 183 so as to maximize the carbon storage potential of the active storage zone 111 within the subterranean rock formation 110 via carbon mineralization.

The fluid production well subsystem 180 may have any number (e.g., one, two, five, ten, twenty, one hundred) of production wellbores 182. In this case, there are Y production wellbores 182 (production wellbore 182-1 through production wellbore 182-Y). Multiple production wellbores 182 may be drilled from the same pad or different pads. A production wellbore 182 may be drilled for the sole purpose of storing carbon according to certain example embodiments. Alternatively, a production wellbore 182 may have been drilled for a different purpose (e.g., production of hydrocarbons, extraction of water, saltwater disposal, geothermal) and later converted for use as a production wellbore 182 according to certain example embodiments.

In some cases, a production wellbore 182 may be held idle for a period of time rather than being used to extract the production fluid 183 from one or more active storage zones 111 within the subterranean formation 110. A production wellbore 182 that is put idle may later resume being used to extract production fluid 183 from an active storage zone 111 within a subterranean formation 110. In addition, or in the alternative, a production wellbore 182 may be converted to an injection wellbore 142 at a point in time or for a period of time to inject pressurized fluid 143 into an active storage zone 111 within a subterranean formation 110. A production wellbore 182 that is converted to an injection wellbore 142 may subsequently be converted back to a production wellbore 182.

Within a production wellbore 182 are one or more fluid production completion systems 188 (FPCSs 188). For example, in this case, production wellbore 182-1 has A FPCSs 188 (FPCS 188-1-1 through FPCS 188-1-A). The distance between the first FPCS 188-1 (e.g., FPCS 188-1-1) and last FPCS 188-1 (e.g., FPCS 188-1-A) of the production wellbore 182-1 may be referred to as the production range of the production wellbore 182-1. As another example, in this case, production wellbore 182-Y has B FPCSs 188 (FPCS 188-Y-1 through FPCS 188-Y-B). The distance between the first FPCS 188-Y (e.g., FPCS 188-Y-1) and last FPCS 188-Y (e.g., FPCS 188-Y-B) of the production wellbore 182-Y may be referred to as the production range for the production wellbore 182-Y.

Each FPCS 188 of a production wellbore 182 of the fluid production well subsystem 180 is located at a point in the production wellbore 182 that is adjacent to one or more active storage zones 111 within the subterranean formation 110. The part of the production wellbore 182 (and so also the FPCS 188 within that part of the production wellbore 182) may be oriented vertically, horizontally, and or have some other orientation relative to an active storage zone 111. Each FPCS 188 of a production wellbore 182 of the fluid production well subsystem 180 is configured to control the inflow rate (also sometimes called the production rate or extraction rate herein) of the production fluid 183 that flows into the production wellbore 182 from an active storage zone 111 (or one or more portions thereof) of the subterranean rock formation 110.

In certain example embodiments, a FPCS 188 of the fluid production well subsystem 180 may be configured to adjust the production range along the production wellbore 182 based on the detection of the mineralized carbon in the active storage zone 111 within the subterranean rock formation 110 by the monitoring subsystem 190. In some cases, a FPCS 188 may be manipulated (e.g., opened, closed) passively (e.g., based on pressure differentials and local components that operate based on exceeding a threshold pressure differential, based on an amount of time). In addition, or in the alternative, a FPCS 188 may be manipulated actively (e.g., using a controller (e.g., controller 304, controller 104), one or more sensor devices and/or other types of measuring equipment 160, and/or other external components).

In some cases, a FPCS 188 may be integrated with (e.g., may be a sub within) a tubing string 249 inserted into the production wellbore 182. For example, the FPCSs 188-1 of production wellbore 182-1 are integrated with tubing string 249-1. As another example, the FPCSs 188-Y of production wellbore 182-Y are integrated with tubing string 249-Y. The location of a FPCS 188 along the tubing string 249 may be designed to coincide with one or more active storage zones 111 of the subterranean rock formation 110. In some cases, the tubing string 249 may be moved further into the production wellbore 182 and/or some distance into the production wellbore 182 over time to use a FPCS 188 with respect to different active storage zones 111 (or portions thereof) of the subterranean rock formation 110. Each FPCS 188 may have any of a number of configurations and/or features. For example, a FPCS 188 may be or include an ASRICV, as discussed above. When a production wellbore 182 has multiple FPCSs 188, the configuration of one FPCS 188 may be the same as, or different than, the configuration of one or more of the other FPCSs 188.

The production fluid 183 is formed by mixing the remainder of the pressurized fluid 143 (after the carbon dioxide is removed and remains in the active storage zone 111) with fluids, solids, and/or gases that naturally occur in the active storage zone 111 of the subterranean rock formation 110. The production fluid 183 is transported from one or more of the production wellbores 182 to one or more of the production fluid receivers 181 through piping 109 using one or more of the pumping systems 185. For example, the pumping system 185 of the fluid production well subsystem 180 may be configured to adjust the production rate of the production fluid 183 based on the detection of the mineralized carbon in the active storage zone 111 within the subterranean rock formation 110 by the monitoring subsystem 190. Examples of a production fluid 183 may include, but are not limited to, formation water, formation solids, partially-CO₂-depleted transition fluid 144, and fully-CO₂-depleted transition fluid 144.

The production fluid 183 may be in a liquid state. In addition, or in the alternative, the production fluid 183 may be in a gaseous state and/or a solid state. In some cases, the composition and/or properties of the production fluid 183 can be subject to environmental variations (e.g., as controlled by the pumping systems 185) and/or time-varying changes. The piping 109 of the fluid production well subsystem 180 may be substantially the same as the piping 109 of the fluid injection well subsystem 140 discussed above. Each component of the piping 109 may have an appropriate size (e.g., inner diameter, outer diameter) and be made of an appropriate material (e.g., steel, PVC) to safely and efficiently handle the pressure, temperature, flow rate, and other characteristics of the production fluid 183 (including components thereof) that pass therethrough.

There may be a number of valves (as discussed above) placed in-line with the piping 109 at various locations in the fluid production well subsystem 180 to control the flow of the production fluid 183 (including components thereof) that flow through the piping 109. One valve may be configured the same as or differently compared to another valve in the fluid production well subsystem 180. Also, one valve may be controlled (e.g., manually, automatically by a controller 104) the same as or differently compared to another valve in the fluid production well subsystem 180. In some cases, a valve can be a general term for one or more other forms of control elements, including but not limited to adjustable speed drive motor controllers, blowers, fans, and pumps.

Each production fluid receiver 181 may hold, contain, or include some or all of the production fluid 183 produced from the formation wellbores 182. Examples of a production fluid receiver 181 may include, but are not limited to, a tank, a vessel, piping 109, the atmosphere, and a processing plant. Each production fluid receiver 181 may include one or more of a number of components that may move and/or process the production fluid 183, including but not limited to a motor, a pump, a compressor, piping 109, a valve, a controller (e.g., one of the controllers 104), a power source, a power supply, an energy storage device, a sensor device or other type of measuring equipment 160, a separator, a filter, a heater, cooling equipment, a protective relay, and an electrical cable.

Each of the one or more pumping systems 185 of the fluid production well subsystem 180 is configured to deliver the production fluid 183 from one or more of the production wellbores 182 to the production fluid receivers 181 through some of the piping 109. A pumping system 185 may include one or more of a number of components, including but not limited to one or more controllers 104, a motor, a pump, a compressor, a fan, a blower, piping 109, a valve, one or more controllers, a sensor device or other type of measuring equipment 160, a protective relay, and an electrical cable. If a pumping system 185 lacks its own local controller, that pumping system 185 may be controlled by a controller 104 of another pumping system 185 and/or a controller 104 of the monitoring subsystem 190.

When a pumping system 185 includes a controller 104, the controller 104 may control some or all aspects of the fluid production well subsystem 180. The controller 104 may be substantially similar to a controller 104 of the monitoring subsystem 190, as described below. For example, a controller 104 of the pumping system 185 (or the fluid production well subsystem 180 more generally) may include one or more components and/or similar functionality to some or all of a controller 104. Alternatively, the controller 104 may include one or more of a number of features in addition to, or altered from, the features of a controller 104. As described herein, control and/or communication with the controller 104 may include communicating with one or more other components of the system 100 and/or another system. In such a case, the controller 104 may facilitate such control and/or communication. The controller 104 may be considered a type of computer device, as discussed below with respect to FIG. 3.

The monitoring subsystem 190 of the system 100 may be configured to monitor activity (e.g., carbon mineralization) within one or more of the active storage zones 111 within the subterranean rock formation 110. In addition, or in the alternative, the monitoring subsystem 190 of the system 100 may be configured to monitor, influence, and/or control one or more of the components (e.g., the fluid injection well subsystem 140, the fluid production well subsystem 180), including portions thereof, of the system 100. For example, the fluid injection well subsystem 140 and the fluid production well subsystem 180 may operate based on measurements made by the monitoring subsystem 190 (e.g., specifically, by the measuring equipment 160 thereof) to control the injection rate of the pressurized fluid 143 and the inflow rate of the production fluid 183 so as to maximize carbon storage potential of the subterranean rock formation 110 via carbon mineralization.

The monitoring functions of the monitoring subsystem 190 may be performed by the measuring equipment 160. In such cases, one or more of the controllers 104 of the monitoring subsystem 190 may be used to control operation of the measuring equipment 160 and/or processing of the measurements made by the measuring equipment 160. The measuring equipment 160 may be any devices, components, apparatuses, and/or systems that are configured to assess or contribute to assessing one or more of the active storage zones 111 within the subterranean rock formation 110. For example, the measuring equipment 160 of the monitoring subsystem 190 may be configured to detect mineralized carbon in solid form that forms on the exposed rock surfaces of one or more of the active storage zones 111 within the subterranean rock formation.

Examples of the measuring equipment 160 may be or include electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, fluid chemistry monitoring (e.g., water chemistry monitoring), and CO₂ content monitoring. As a result, measurements made by the measuring equipment 160 may be derived from the type (e.g., electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, fluid chemistry monitoring, CO₂ content monitoring) of equipment.

When the measuring equipment 160 includes the capability of electromagnetic monitoring, the measurements may include periodic electromagnetic monitoring surveys that may provide insight into the rate of carbon mineralization occurring in one or more of the active storage zones 111 within the subterranean rock formation 110 and/or a distribution of mineralized carbon on exposed rock surfaces of the active storage zones 111 within the subterranean rock formation 110. In such cases, the periodic electromagnetic monitoring surveys may be conducted from the Earth's surface (e.g., ground level 112 when the system 100 is land-based), the injection wellbore 142, the production wellbore 182, an aircraft flying above the Earth's surface, some other point, or any combination thereof.

Electromagnetic monitoring techniques may be used to monitor subsurface electrical conductivity. The mineralization process may permanently capture carbon by depositing it locked in a carbonate mineral structure on the available surfaces of subterranean basaltic or ultramafic formations. The accumulation of these carbonate minerals may gradually change the electrical conductivity of the storage formation rock. Sufficient changes in the conductivity of the active storage zone 111 within the subterranean rock formation 110 may eventually result in detectable changes in bulk conductivity. Periodic surveys may provide insight into carbonate deposition rate and distribution.

When the measuring equipment 160 includes magnetic monitoring, depending on the chemical composition of an active storage zone 111 for carbon storage, the mineralization process may result in the accumulation or depletion of magnetic minerals. Periodic magnetic measurements taken from wellbores (e.g., injection wellbore 142, production wellbore 182), at the Earth's surface (e.g., ground level 112) or via aircraft, may be used to track the spatial and intensity changes in the bulk magnetization of the active storage zone 111. This information may indicate the extent to which the mineralization process is occurring.

When the measuring equipment 160 includes gravity monitoring, the measurements may include periodic gravity monitoring surveys to provide insight into the rate of carbon mineralization occurring in one or more active storage zones 111 within the subterranean rock formation 110 and/or the distribution of the mineralized carbon on exposed rock surfaces in one or more active storage zones 111 within the subterranean rock formation 110. In such cases, the periodic gravity monitoring surveys may be conducted from the Earth's surface (e.g., ground level 112 when the system 100 is land-based), the injection wellbore 142, the production wellbore 182, some other point, or any combination thereof.

The mineralization process is generally a combination of reactions that initially dissolves minerals from a rock face within an active storage zone 111 and subsequently deposits those minerals and carbon as a combined carbonate structure on the same rock face, but not necessarily in the same location within the active storage zone 111. This may result in a distribution of sites where mass additions and/or subtractions are occurring within the active storage zone 111. Sufficient departures from the original mass distribution of the active storage zone 111 may be detected via gravimetric measurements taken from wellbores (e.g., injection wellbore 142, production wellbore 182) and at the Earth's surface (e.g., ground level 112). Periodic measurements, beyond that taken prior to injection of the pressurized fluid 143, may be used to track the spatial and intensity changes in the gravity field of the active storage zone 111, thereby indicating the extent to which the mineralization process is occurring.

When the measuring equipment 160 includes interferometric synthetic aperture radar (InSAR) monitoring, the measurements may include periodic interferometric synthetic aperture radar surveys of Earth's surface to provide insight into the pressure distribution within the subterranean rock formation 110. InSAR monitoring is a satellite-based technology that may provide a measure of deformation of the Earth's surface relative to a baseline survey. In this case, the baseline may be before the start of injecting the pressurized fluid 143. Deformation in the Earth's surface during the mineralization process may suggest where fluid pressure is increasing or decreasing relative to the formation's pre-injection pressure distribution. Significant pressure departures may indicate the presence of permeability barriers in the active storage zone 111 within the subterranean rock formation 110. How permeability barriers change with time may suggest where carbonate deposition (e.g., due to mineralization) is occurring or where permeability barriers are being broken down to allow access to new mineralization sites within the storage formation.

When the measuring equipment 160 includes seismic monitoring, the measurements may include surveys to provide insight into how carbon mineralization within one or more active storage zones 111 within the subterranean rock formation 110 is altering fluid flow paths via an initiation of new fractures and/or an extension of existing fractures within the active storage zones 111 within the subterranean rock formation 110. Monitoring for seismic events may be performed using geophones at the Earth's surface (e.g., ground level 112) or in dedicated monitoring wells. A three-dimensional map of such events may provide insight into the changing dynamics of the carbon storage properties within the active storage zone 111 within the subterranean rock formation 110. Small seismic (a.k.a. microseismic) events may occur during the mineralization process as a result of rocks shifting, new fractures initiating, or existing fractures extending. All of these events may be driven by changes in the pressure distribution of the active storage zone 111. Understanding the distribution and timing of microseismic events may assist in determining where and why changes in the pressure distribution are occurring, which, in turn, may be used to better understand changes in the fluid flow pattern within the active storage zone 111.

When the measuring equipment 160 includes fluid chemistry monitoring, the measurements may include data from the injection fluid 143 that enters one or more active storage zones 111 within the subterranean rock formation 110 via the injection wellbore 142 and/or from the production fluid 183 that exits one or more active storage zones 111 within the subterranean rock formation 110 via the production wellbore 182. Such data may provide insight into factors that may include, but are not limited to, the rate of carbon mineralization within one or more active storage zones 111 within the subterranean rock formation 110, the distribution of mineralized carbon within one or more active storage zones 111 within the subterranean rock formation 110, and fluid flow patterns within one or more active storage zones 111 within the subterranean rock formation 110.

When the measuring equipment 160 includes water chemistry monitoring, the returning water (e.g., the produced fluid 183) produced in the mineralization process may bear remnant chemicals indicative of the mineralization reaction and leaching of the storage formation rock in the active storage zone 111. The produced water (e.g., produced fluid 183) may also bear remnant CO₂ that has not reacted with the storage formation in the active storage zone 111. Comparing the chemical composition of produced water from multiple production wellbores 182 may provide insight into where and how the mineralization reactions are occurring. Combined with other monitoring techniques, the fluid flow pattern within the storage formation of the active storage zone 111 may also be indicated, thereby allowing informed decisions to be made in terms of modifying that flow pattern within the active storage zone 111.

In some cases, the measuring equipment 160 may include one or more sensor devices. A sensor device may include one or more sensors that measure one or more parameters (e.g., pressure, flow rate, temperature, humidity, fluid content, voltage, current, porosity, permeability). Examples of a sensor of a sensor device may include, but are not limited to, a temperature sensor, a flow sensor, a pressure sensor, a pressure differential sensor, a gas spectrometer, a voltmeter, an ammeter, a seismograph, an infrared sensor, a fiber-optic cable, and a camera. A sensor device may be integrated with or measure a parameter associated with one or more components of the system 100. For example, a sensor device may be configured to measure a parameter (e.g., flow rate, pressure, temperature, volume, fluid content) associated with the pressurized fluid 143.

As another example, a sensor device may be configured to measure a parameter (e.g., flow rate, pressure, temperature, volume, fluid content) associated with the production fluid 183. As yet another example, a sensor device may be configured to measure a parameter (e.g., flow rate, distribution of mineralized carbon, rate of carbon mineralization) associated with one or more of the active storage zones 111 within the subterranean rock formation 110. When a sensor device and/or other part of the measuring equipment 160 includes its own controller (e.g., a controller 104 or portions thereof), then the sensor device and/or other part of the measuring equipment 160 may be considered a type of computer device, as discussed below with respect to FIG. 3.

Each controller 104 of the monitoring subsystem 190 is configured to control and/or obtain and process measurements made by some or all of the measuring equipment 160. A controller 104 may be communicably coupled to one or more of the other controllers 104 of the monitoring subsystem 190, some or all of the measuring equipment 160 of the monitoring subsystem 190, the network manager 119, one or more of the users 151 (including associated user systems 155), the fluid injection well subsystem 140 (including portions thereof), the fluid production well subsystem 180 (including portions thereof), and any other components of the system 100. Interaction between a controller 104 and any of these other components of the system 100 may be facilitated by communication links 105 and/or power transfer links 187.

Each communication link 105 may include wired (e.g., Class 1 electrical cables, Class 2 electrical cables, electrical connectors, Power Line Carrier, RS485) and/or wireless (e.g., Wi-Fi, Zigbee, visible light communication, cellular networking, Bluetooth, Bluetooth Low Energy (BLE), ultrawide band (UWB), WirelessHART, ISA100) technology. A communication link 105 may transmit signals (e.g., communication signals, control signals, data) between each controller 104, some or all of the measuring equipment 160 of the monitoring subsystem 190, the network manager 119, one or more of the users 151 (including associated user systems 155), the fluid injection well subsystem 140 (including portions thereof), the fluid production well subsystem 180 (including portions thereof), and any other components of the system 100. When a communication link 105 includes wired technology, the communication link 105 may be sized (e.g., 28 gauge, 32gauge) in a manner suitable for the amount (e.g., 10 mV, 1.0 V) and type (e.g., alternating current, direct current) of signal (e.g., communication, control, data) transferred therethrough.

Each power transfer link 187 may include one or more electrical conductors, which may be individual or part of one or more electrical cables. In some cases, as with inductive power, power may be transferred wirelessly using power transfer links 187. A power transfer link 187 may transmit power between each controller 104, some or all of the measuring equipment 160 of the monitoring subsystem 190, the network manager 119, one or more of the users 151 (including associated user systems 155), the fluid injection well subsystem 140 (including portions thereof), the fluid production well subsystem 180 (including portions thereof), and any other components of the system 100. Each power transfer link 187 may be sized (e.g., 12 gauge, 18 gauge, 4 gauge) in a manner suitable for the amount (e.g., 480V, 24V, 120V) and type (e.g., alternating current, direct current) of power transferred therethrough.

As mentioned above, the monitoring subsystem 190 may include one or more controllers 104. A controller 104 performs a number of functions that include obtaining and sending data, evaluating data, following protocols, running algorithms, and sending commands. A controller 104 may include one or more of a number of components. FIG. 2 shows a system diagram the includes a number of components that a controller 104 may have. For example, components of a controller 104 may include, but are not limited to, an analysis module 250, a control engine 206, a communication module 207, a timer 235, a power module 230, a storage repository 231, a hardware processor 221, memory 222, a transceiver 224, an application interface 226, and an optional security module 223. The various components of a controller 104 may be centrally located. In addition, or in the alternative, some of the components of a controller 104 may be located remotely from (e.g., in the cloud, at an office building) one or more of the other components of the controller 104.

The storage repository 231 may be a persistent storage device (or set of devices) that stores software and data used to assist the controller 104 in communicating with one or more other components of a system, such as the users 151 (including associated user systems 155), the network manager 119, the measuring equipment 160, the fluid injection well subsystem 140 (including portions thereof), the fluid production well subsystem 180 (including portions thereof), and any other component of the system 100 of FIG. 1 above. In one or more example embodiments, the storage repository 231 stores one or more protocols 232, one or more algorithms 233, and stored data 234.

The protocols 232 of the storage repository 231 may be any procedures (e.g., a series of method steps) and/or other similar operational processes that the control engine 206 of the controller 104 follows based on certain conditions at a point in time. The protocols 232 may include any of a number of communication protocols that are used to send and/or obtain data between the controller 104 and other components of a system (e.g., the system 100). Such protocols 232 used for communication may be a time-synchronized protocol. Examples of such time-synchronized protocols may include, but are not limited to, a highway addressable remote transducer (HART) protocol, a wireless HART protocol, and an International Society of Automation (ISA) 100 protocol. In this way, one or more of the protocols 232 may provide a layer of security to the data transferred within a system (e.g., system 100). Other protocols 232 used for communication may be associated with the use of Wi-Fi, Zigbee, visible light communication (VLC), cellular networking, BLE, UWB, and Bluetooth.

The algorithms 233 may be any formulas, mathematical models, forecasts, simulations, and/or other similar tools that the control engine 206 of the controller 104 uses to reach a computational conclusion. For example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in determining a target injection rate of the pressurized fluid 143. As another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in controlling a portion (e.g., the pumping system 145) of the fluid injection well subsystem 140 so that the target injection rate of the pressurized fluid 143 from the injection range of an injection wellbore 142 into an active storage zone 111 within the subterranean rock formation 110 is achieved.

As yet another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in determining a target inflow rate of the production fluid 183. As still another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in controlling a portion (e.g., the pumping system 185) of the fluid production well subsystem 180 so that the target inflow rate of the production fluid 183 from an active storage zone 111 within the subterranean rock formation 110 into the production range of a production wellbore 182 is achieved.

As yet another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in determining a rate of carbon mineralization occurring in an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time. As still another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in determining a distribution of carbon mineralization occurring in an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time.

As yet another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in determining a pressure distribution within an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time. As still another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 in determining how carbon mineralization occurring in an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time alters fluid flow paths (e.g., for transition fluid 144) via initiation of new fractures or an extension of existing fractures within the active storage zone 111 within the subterranean rock formation 110.

As yet another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 to determine an optimal composition, temperature, pressure, and/or other parameter associated with the pressurized fluid 143 (including components thereof, such as the carbon dioxide) injected into an active storage zone 111 within the subterranean rock formation 110. As still another example, one or more algorithms 233 may be used, in conjunction with one or more protocols 232, to assist the controller 104 to determine the characteristics (e.g., entry point, path, depth) of one or more subsequent wellbores (e.g., injection wellbores 142, production wellbores 182) for purposes of well planning and well placement strategies.

Stored data 234 may be any data associated with the various equipment (e.g., the measuring equipment 160, the pumping system 145 of the fluid injection well subsystem 140, the pumping system 185 of the fluid production well subsystem 180, the one or more carbon dioxide sources 141), including associated components, of the system 100, the pressurized fluid 143, the transition fluid 144, the production fluid 183, the subterranean rock formation 110 (including active storage zones 111 and other zones (e.g., depleted storage zones) thereof), the user systems 155, the network manager 119, the measuring equipment 160, measurements made by the measuring equipment 160, threshold values, target values, tables, results of previously run or calculated algorithms 233, updates to protocols 232 and/or algorithms 233, user preferences, and/or any other suitable data. Such data may be any type of data, including but not limited to historical data, present data, and future data (e.g., forecasts). The stored data 234 may be associated with some measurement of time derived, for example, from the timer 235.

Examples of a storage repository 231 may include, but are not limited to, a database (or a number of databases), a file system, cloud-based storage, a hard drive, flash memory, some other form of solid-state data storage, or any suitable combination thereof. The storage repository 231 may be located on multiple physical machines, each storing all or a portion of the protocols 232, the algorithms 233, and/or the stored data 234 according to some example embodiments. Each storage unit or device may be physically located in the same or in a different geographic location.

The storage repository 231 may be operatively connected to the control engine 206. In one or more example embodiments, the control engine 206 includes functionality to communicate with the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, and any other components in the system 100. More specifically, the control engine 206 sends information to and/or obtains information from the storage repository 231 in order to communicate with the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140, the fluid production well subsystem 180, and any other components of the system 100. As discussed below, the storage repository 231 may also be operatively connected to the communication module 207 in certain example embodiments.

In certain example embodiments, the control engine 206 of the controller 104 controls the operation of one or more components (e.g., the communication module 207, the timer 235, the transceiver 224) of the controller 104. For example, the control engine 206 may activate the communication module 207 when the communication module 207 is in “sleep” mode and when the communication module 207 is needed to send data obtained from another component (e.g., a controller 304, a controller 204, the measuring equipment 160) in the system 100. In addition, the control engine 206 of the controller 104 may control the operation of one or more other components (e.g., a controller 304, a controller 204, the measuring equipment 160), or portions thereof, of the system 100.

The control engine 206 of the controller 104 may communicate with and/or control one or more other components of the system 100. For example, the control engine 206 may use one or more protocols 232 to facilitate communication with the measuring equipment 160 to obtain data (e.g., measurements of various parameters, such as temperature, pressure, and flow rate), whether in real time or on a periodic basis and/or to instruct the measuring equipment 160 to take a measurement. The control engine 206 may use measurements of parameters taken by the measuring equipment 160 to perform one or more steps in maximizing the amount of carbon mineralization within an active storage zone 111 within the subterranean rock formation 110 using one or more protocols 232 and/or one or more algorithms 233.

The control engine 206 of the controller 104 may use one or more algorithms 233, one or more protocols 232, stored data 234, the communication module 207, and/or other components of the controller 104 to perform its functions. For example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine a target injection rate of the pressurized fluid 143. As another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to control a portion (e.g., the pumping system 145) of the fluid injection well subsystem 140 so that the target injection rate of the pressurized fluid 143 from the injection range of an injection wellbore 142 into an active storage zone 111 within the subterranean rock formation 110 is achieved.

As yet another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine a target inflow rate of the production fluid 183. As still another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to control a portion (e.g., the pumping system 185) of the fluid production well subsystem 180 so that the target inflow rate of the production fluid 183 from an active storage zone 111 within the subterranean rock formation 110 into the production range of a production wellbore 182 is achieved.

As yet another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine a rate of carbon mineralization occurring in an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time. As still another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine a distribution of carbon mineralization occurring in an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time.

As yet another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine a pressure distribution within an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time. As still another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine how carbon mineralization occurring in an active storage zone 111 within the subterranean rock formation 110 at a point in time and/or over time alters fluid flow paths (e.g., for transition fluid 144) via initiation of new fractures or an extension of existing fractures within the active storage zone 111 within the subterranean rock formation 110.

As yet another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine an optimal composition, temperature, pressure, and/or other parameter associated with the pressurized fluid 143 (including components thereof, such as the carbon dioxide) injected into an active storage zone 111 within the subterranean rock formation 110. As still another example, the control engine 206 may use one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207 to determine the characteristics (e.g., entry point, path, depth) of one or more subsequent wellbores (e.g., injection wellbores 142, production wellbores 182) for purposes of well planning and well placement strategies.

The control engine 206 may generate and process data associated with control, communication, and/or other signals sent to and obtained from the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. In certain embodiments, the control engine 206 of the controller 104 may communicate with one or more components of a system external to the system 100. For example, the control engine 206 may interact with an inventory management system by ordering replacements for components or pieces of equipment (e.g., a valve, a motor) within the system 100 that has failed or is failing. As another example, the control engine 206 may interact with a contractor or workforce scheduling system by arranging for the labor needed to replace a component or piece of equipment in the system 100. In this way and in other ways, the controller 104 is capable of performing a number of functions beyond what could reasonably be considered a routine task.

In certain example embodiments, the control engine 206 may include an interface that enables the control engine 206 to communicate with the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. For example, if a user system 155 operates under IEC Standard 62386, then the user system 155 may have a serial communication interface that will transfer data to the controller 104. Such an interface may operate in conjunction with, or independently of, the protocols 232 used to communicate between the controller 104 and the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100.

The control engine 206 (or other components of the controller 104) may also include one or more hardware components and/or software elements to perform its functions. Such components may include, but are not limited to, a universal asynchronous receiver/transmitter (UART), a serial peripheral interface (SPI), a direct-attached capacity (DAC) storage device, an analog-to-digital converter, an inter-integrated circuit (I2C), and a pulse width modulator (PWM).

The analysis module 250 of the controller 104 of the monitoring subsystem 190 may be configured to receive, process (e.g., organize, filter, format), and/or analyze the data received from the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. The analysis of the various data by the analysis module 250 may be used to control the operation of the fluid injection well subsystem 140 (e.g., controlling one or more parameters associated with the pressurized fluid 143), the operation of the fluid production well subsystem 180 (e.g., controlling one or more parameters associated with the production fluid 183), the operation of the measuring equipment 160, and/or the operation of any other component of the system 100 using one or more algorithms 233, one or more protocols 232, stored data 234, and the communication module 207.

In certain example embodiments, the analysis module 250 of the controller 104 is configured to identify one or more active storage zones 111 (e.g., including a range of depths, a range of coordinates) within a subterranean rock formation 110 that may be considered optimal for storing carbon dioxide using carbon mineralization. In addition, or in the alternative, the analysis module 250 of the controller 104 may be configured to recommend a well pattern plan (e.g., a 4-spot well pattern, a 5-spot well pattern, a semi-line-drive well pattern, a line-drive well pattern), including the number of stages and the location(s) of each stage, to be used for a particular active storage zone 111 within the subterranean rock formation 110.

In some cases, the analysis module 250 of the controller 104 may be configured to analyze the flow of fluids (e.g., pressurized fluid 143, transition fluid 144, production fluid 183) within an active storage zone 111. In such cases, the analysis module 250 may be configured to analyze the interaction of the fluids with the formation rock in an active storage zone 111 in a manner that maximizes the contact area between the fluids and the rock, with the desired outcome being the deposition of the largest amount of carbonate minerals at the largest number of mineralization reaction sites possible within the active storage zone 111.

In addition to developing construction plans and developing, initiating, monitoring, and adjusting fluid flow plans for wellbores (e.g., production wellbores 182, injection wellbores 142) with respect to one or more active storage zones 111 within the subterranean rock formation 110, the analysis module 250 of the controller 104 may be configured to maximize the carbon storage potential of a rock formation within an active storage zone 111 by, for example, monitoring the carbonate deposition process throughout the process life cycle. To fully understand how the mineralization process is progressing within the rock within an active storage zone 111, the analysis module 250 may utilize information provided by the monitoring equipment 160 using one or multiple monitoring techniques that the monitoring equipment 160 is capable of achieving.

In certain example embodiments, the analysis module 250 may use such information yielded from such techniques used by the monitoring equipment 160 to understanding how much and where carbonate is being deposited within an active storage zone 111. With such information, analysis module 250 may develop and provide specific steps that may be taken to control the overall mineralization process in such a way as to maximize the amount of permanently stored carbon in an active storage zone 111. Recommendations made by the analysis module 250 may include, but are not limited to, injection rates for pressurized fluid 143, chemical composition and form of the pressurized fluid 143, inflow rates of production fluid 183, settings and/or design of a FICS 148, settings and/or design of a FPCS 188, and future well placements (e.g., number of wellbores, types of wellbores, orientation (e.g., horizontal, vertical, non-vertical) of each wellbore, entry point of each wellbore) in the subterranean rock formation 110. The analysis module 250 may be configured to continually obtain data and evaluate the field operation in real time.

The communication module 207 of the controller 104 determines and implements the communication protocol (e.g., from the protocols 232 of the storage repository 231) that is used when the control engine 206 communicates with (e.g., sends signals to, obtains signals from) the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. In some cases, the communication module 207 accesses the stored data 234 to determine which communication protocol is used to communicate with another component of the system 100. In addition, the communication module 207 may identify and/or interpret the communication protocol of a communication obtained by the controller 104 so that the control engine 206 may interpret the communication. The communication module 207 may also provide one or more of a number of other services with respect to data sent from and obtained by the controller 104. Such services may include, but are not limited to, data packet routing information and procedures to follow in the event of data interruption.

The timer 235 of the controller 104 may track clock time, intervals of time, an amount of time, and/or any other measure of time. The timer 235 may also count the number of occurrences of an event, whether with or without respect to time. Alternatively, the control engine 206 may perform a counting function. The timer 235 is able to track multiple time measurements and/or count multiple occurrences concurrently. The timer 235 may track time periods based on an instruction obtained from the control engine 206, based on an instruction obtained from a user 151, based on an instruction programmed in the software for the controller 104, based on some other condition (e.g., the occurrence of an event) or from some other component, or from any combination thereof. In certain example embodiments, the timer 235 may provide a time stamp for each packet of data obtained from another component (e.g., the measuring equipment 160) of the system 100.

The power module 230 of the controller 104 obtains power from a power supply (e.g., AC mains) and manipulates (e.g., transforms, rectifies, inverts) that power to provide the manipulated power to one or more other components (e.g., the timer 235, the control engine 206) of the controller 104, where the manipulated power is of a type (e.g., alternating current, direct current) and level (e.g., 12V, 24V, 120V) that may be used by the other components of the controller 104. In some cases, the power module 230 may also provide power to some or all of the measuring equipment 160.

The power module 230 may include one or more of a number of single or multiple discrete components (e.g., transistor, diode, resistor, transformer) and/or a microprocessor. The power module 230 may include a printed circuit board, upon which the microprocessor and/or one or more discrete components are positioned. In addition, or in the alternative, the power module 230 may be a source of power in itself to provide signals to the other components of the controller 104. For example, the power module 230 may be or include an energy storage device (e.g., a battery). As another example, the power module 230 may be or include a localized photovoltaic power system.

The hardware processor 221 of the controller 104 executes software, algorithms (e.g., algorithms 233), and firmware in accordance with one or more example embodiments. Specifically, the hardware processor 221 may execute software on the control engine 206 or any other portion of the controller 104, as well as software used by the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. The hardware processor 221 may be an integrated circuit, a central processing unit, a multi-core processing chip, SoC, a multi-chip module including multiple multi-core processing chips, or other hardware processor in one or more example embodiments. The hardware processor 221 may be known by other names, including but not limited to a computer processor, a microprocessor, and a multi-core processor.

In one or more example embodiments, the hardware processor 221 executes software instructions stored in memory 222. The memory 222 includes one or more cache memories, main memory, and/or any other suitable type of memory. The memory 222 may include volatile and/or non-volatile memory. The memory 222 may be discretely located within the controller 104 relative to the hardware processor 221. In certain configurations, the memory 222 may be integrated with the hardware processor 221.

In certain example embodiments, the controller 104 does not include a hardware processor 221. In such a case, the controller 104 may include, as an example, one or more field programmable gate arrays (FPGA), one or more insulated-gate bipolar transistors (IGBTs), and/or one or more integrated circuits (ICs). Using FPGAs, IGBTs, ICs, and/or other similar devices known in the art allows the controller 104 (or portions thereof) to be programmable and function according to certain logic rules and thresholds without the use of a hardware processor. Alternatively, FPGAs, IGBTs, ICs, and/or similar devices may be used in conjunction with one or more hardware processors 221.

The transceiver 224 of the controller 104 may send and/or obtain control and/or communication signals. Specifically, the transceiver 224 may be used to transfer data between the controller 104 and the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. The transceiver 224 may use wired and/or wireless technology. The transceiver 224 may be configured in such a way that the control and/or communication signals sent and/or obtained by the transceiver 224 may be obtained and/or sent by another transceiver that is part of a user 151 (including an associated user system 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. The transceiver 224 may send and/or obtain any of a number of signal types, including but not limited to radio frequency signals.

When the transceiver 224 uses wireless technology, any type of wireless technology may be used by the transceiver 224 in sending and obtaining signals. Such wireless technology may include, but is not limited to, Wi-Fi, Zigbee, VLC, cellular networking, BLE, UWB, and Bluetooth. The transceiver 224 may use one or more of any number of suitable communication protocols (e.g., ISA100, HART) when sending and/or obtaining signals.

Optionally, in one or more example embodiments, the security module 223 secures interactions between the controller 104, the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. More specifically, the security module 223 authenticates communication from software based on security keys verifying the identity of the source of the communication. For example, user software may be associated with a security key enabling the software of a user system 155 to interact with the controller 104. Further, the security module 223 may restrict receipt of information, requests for information, and/or access to information.

When there are multiple controllers 104 (e.g., one controller 104 for communicating with and/or controlling the fluid injection well subsystem 140, another controller 104 for communicating with and/or controlling the fluid production well subsystem 180, yet another controller 104 for managing the measurements made by the measuring equipment 160 relative to one or more of the active storage zones 111 within the subterranean rock formation 110), each controller 104 may operate independently of each other. Alternatively, one or more of the controllers 104 may work cooperatively with each other. As yet another alternative, one of the controllers 104 may control some or all of one or more other controllers 104 in the system 100. Each controller 104 may be considered a type of computer device, as discussed below with respect to FIG. 3.

The controller 104 may further be configured to employ a self-learning function by adjusting one or more algorithms 233 and/or one or more protocols 232 using recent data. For example, the control engine 206 of the controller 104, through the use of one or more protocols 232 and/or algorithms 233, may implement machine learning as a way to evolve over time with new data and associated changes that may result from the new data. The control engine 206 may use, for example, supervised learning, unsupervised learning, semi-supervised learning, and/or reinforcement learning, as those terms are known in the art of machine learning. In this case, these types of machine learning are effective with sufficient data (e.g., measurements from measuring equipment 160, other data obtained from one or more of the data sources (e.g., one or more of the carbon dioxide sources 141, the controller 204 of the fluid injection well subsystem 140, the controller 304 of the fluid production well subsystem 180)) and use of algorithms 233 and/or protocols 232 that automatically build mathematical models using sample data-also known as “training data”.

The learning algorithms 233 that may be used and trained by the control engine 206 may include, but are not limited to, instance-based learning algorithms, artificial neural network algorithms, deep learning algorithms, and ensemble algorithms. Instance-based learning algorithms typically build up a database of example data and compare new data to the database using a similarity measure in order to find the best match and make a prediction. For this reason, instance-based methods are also called winner-take-all methods and memory-based learning. Focus may be put on the representation of the stored instances and similarity measures used between instances. Instance-based algorithms may be computationally expensive for very large datasets since they save all training instances/data points and are sensitive to data noise.

Artificial neural networks may be fairly similar to the human brain. For example, artificial neural networks may be made up of artificial neurons, take in multiple inputs, and produce specific outputs. Artificial neural networks may be an enormous subfield comprised of a large number of neural network architectures and hundreds of algorithms and variations for different types of problems. Artificial neural networks may be biologically inspired computational simulations for certain specific tasks like clustering, classification, or pattern recognition.

Deep learning algorithms may be a modern update to artificial neural networks by building much larger and more complex neural networks. With deep learning, many methods may be applied to very large datasets. Various architectures may be applied for deep learning algorithms. Deep learning may have a high computational cost because much of its development requires advanced processing, storage hardware, and ML platforms/APIs.

Ensemble algorithm methods may be models composed of multiple weaker models that are independently trained and whose predictions are combined in some way to make the overall prediction. Various combination techniques (e.g., averaging, max voting, bagging/bootstrapping (sampling subsets of original complete dataset), boosting) may be applied. Unlike other standard ensemble methods where models are trained in isolation, the boosting technique may employ an iterative approach, training models in succession, with each new model being trained to correct the errors made by the previous ones. Models may be added sequentially until no further improvements may be made.

A user 151 may be any person or entity that interacts, directly or indirectly, with the system 100. Examples of a user 151 may include, but are not limited to, a business owner, an engineer, an operator, a data analyst, a company representative, a geologist, a consultant, a drilling engineer, a government employee, a regulatory agent, a contractor, and a manufacturer's representative. A user 151 may use one or more user systems 155, which may include a display (e.g., a GUI). A user system 155 of a user 151 may interact with (e.g., send data to, obtain data from) one or more of the controllers 104 of the monitoring subsystem 190 and/or some other component of the system 100 via an application interface and using the communication links 105. A user 151 may also interact directly with the one or more of the controllers 104 of the monitoring subsystem 190 and/or some other component of the system 100 through a user interface (e.g., keyboard, mouse, touchscreen).

The network manager 119 is a device or component that controls all or a portion (e.g., a controller 104 of the monitoring subsystem 190, a communication network, the pumping system 145 of the fluid injection well subsystem 140) of the system 100. The network manager 119 may be substantially similar to a controller 104, as described above. For example, the network manager 119 may include a controller that has one or more components and/or similar functionality to some or all of a controller 104. Alternatively, the network manager 119 may include one or more of a number of features in addition to, or altered from, the features of a controller 104. As described herein, control and/or communication with the network manager 119 may include communicating with one or more other components of the same system 100 or another system. In such a case, the network manager 119 may facilitate such control and/or communication. The network manager 119 may be called by other names, including but not limited to a master controller, a network controller, and an enterprise manager. The network manager 119 may be considered a type of computer device, as discussed below with respect to FIG. 3.

The users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and any other components of the system 100 may interact with the controller 104 using the application interface 226. Specifically, the application interface 226 of the controller 104 obtains data (e.g., information, communications, instructions, updates to firmware) from and sends data (e.g., information, communications, instructions) to the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100. Examples of an application interface 226 may be or include, but are not limited to, an application programming interface, a web service, a data protocol adapter, some other hardware and/or software, or any suitable combination thereof. Similarly, the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100 may include an interface (similar to the application interface 226 of the controller 104) to obtain data from and send data to the controller 104 in certain example embodiments.

In addition, as discussed above with respect to a user system 155 of a user 151, the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100 may include a user interface. Examples of such a user interface may include, but are not limited to, a graphical user interface, a touchscreen, a keyboard, a monitor, a mouse, some other hardware, or any suitable combination thereof.

The controller 104, the users 151 (including associated user systems 155), the measuring equipment 160, the network manager 119, the fluid injection well subsystem 140 (including the controller 204), the fluid production well subsystem 180 (including the controller 304), and/or any other components of the system 100 may use their own system or share a system in certain example embodiments. Such a system may be, or contain a form of, an Internet-based or an intranet-based computer system that is capable of communicating with various software. A computer system includes any type of computing device and/or communication device, including but not limited to the controller 104. Examples of such a system may include, but are not limited to, a desktop computer with a Local Area Network (LAN), a Wide Area Network (WAN), Internet or intranet access, a laptop computer with LAN, WAN, Internet or intranet access, a smart phone, a server, a server farm, an android device (or equivalent), a tablet, smartphones, and a personal digital assistant (PDA). Such a system may correspond to a computer system as described below with regard to FIG. 3.

Further, as discussed above, such a system may have corresponding software (e.g., user system software, carbon dioxide source software, controller software). The software may execute on the same or a separate device (e.g., a server, mainframe, desktop personal computer (PC), laptop, PDA, television, cable box, satellite box, kiosk, telephone, mobile phone, or other computing devices) and may be coupled by the communication network (e.g., Internet, Intranet, Extranet, LAN, WAN, or other network communication methods) and/or communication channels, with wire and/or wireless segments according to some example embodiments. The software of one system may be a part of, or operate separately but in conjunction with, the software of another system within the system 100.

FIG. 3 illustrates one embodiment of a computing device 318 that implements one or more of the various techniques described herein, and which is representative, in whole or in part, of the elements described herein pursuant to certain example embodiments. For example, a controller 104 (including components thereof, such as a control engine 206, a hardware processor 221, a storage repository 231, a power module 230, and a transceiver 224) may be considered a computing device 318. Computing device 318 is one example of a computing device and is not intended to suggest any limitation as to scope of use or functionality of the computing device and/or its possible architectures. Neither should the computing device 318 be interpreted as having any dependency or requirement relating to any one or combination of components illustrated in the example computing device 318.

The computing device 318 includes one or more processors or processing units 314, one or more memory/storage components 315, one or more input/output (I/O) devices 316, and a bus 317 that allows the various components and devices to communicate with one another. The bus 317 represents one or more of any of several types of bus structures, including a memory bus or memory controller, a peripheral bus, an accelerated graphics port, and a processor or local bus using any of a variety of bus architectures. The bus 317 includes wired and/or wireless buses.

The memory/storage component 315 represents one or more computer storage media. The memory/storage component 315 includes volatile media (such as random access memory (RAM)) and/or nonvolatile media (such as read only memory (ROM), flash memory, optical disks, magnetic disks, and so forth). The memory/storage component 315 includes fixed media (e.g., RAM, ROM, a fixed hard drive, etc.) as well as removable media (e.g., a Flash memory drive, a removable hard drive, an optical disk, and so forth).

One or more I/O devices 316 allow a user 151 to enter commands and information to the computing device 318, and also allow information to be presented to the user 151 and/or other components or devices. Examples of input devices 316 include, but are not limited to, a keyboard, a cursor control device (e.g., a mouse), a microphone, a touchscreen, and a scanner. Examples of output devices include, but are not limited to, a display device (e.g., a monitor or projector), speakers, outputs to a lighting network (e.g., DMX card), a printer, and a network card.

Various techniques are described herein in the general context of software or program modules. Generally, software includes routines, programs, objects, components, data structures, and so forth that perform particular tasks or implement particular abstract data types. An implementation of these modules and techniques are stored on or transmitted across some form of computer readable media. Computer readable media is any available non-transitory medium or non-transitory media that is accessible by a computing device. By way of example, and not limitation, computer readable media includes “computer storage media”.

“Computer storage media” and “computer readable medium” include volatile and non-volatile, removable and non-removable media implemented in any method or technology for storage of information such as computer readable instructions, data structures, program modules, or other data. Computer storage media include, but are not limited to, computer recordable media such as RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which is used to store the desired information and which is accessible by a computer.

The computer device 318 (also sometimes called a computer system 318) is connected to a network (not shown) (e.g., a LAN, a WAN such as the Internet, cloud, or any other similar type of network) via a network interface connection (not shown) according to some example embodiments. Those skilled in the art will appreciate that many different types of computer systems exist (e.g., desktop computer, a laptop computer, a personal media device, a mobile device, such as a cell phone or personal digital assistant, or any other computing system capable of executing computer readable instructions), and the aforementioned input and output means take other forms, now known or later developed, in other example embodiments. Generally speaking, the computer system 318 includes at least the minimal processing, input, and/or output means necessary to practice one or more embodiments.

Further, those skilled in the art will appreciate that one or more elements of the aforementioned computer device 318 is located at a remote location and connected to the other elements over a network in certain example embodiments. Further, one or more embodiments is implemented on a distributed system having one or more nodes, where each portion of the implementation (e.g., the monitoring subsystem 190) is located on a different node within the distributed system. In one or more embodiments, the node corresponds to a computer system. Alternatively, the node corresponds to a processor with associated physical memory in some example embodiments. The node alternatively corresponds to a processor with shared memory and/or resources in some example embodiments.

Example embodiments may be directed to the combined use of well placement strategies and mineralization process monitoring techniques for the purpose of maximizing the amount of captured carbon per bulk volume of rock within the subterranean rock formation 110 being accessed. Well placement strategies and mineralization process monitoring techniques may be employed independently or jointly according to certain example embodiments. Depending on the chemical and structural nature of the subterranean rock formation 110, different well placement strategies may be deployed to maximize the interaction between the accessible surface area (e.g., one or more active storage zones 111) of the subterranean rock formation 110 and the pressurized fluid 143 (e.g., mixture of water and CO₂). This, in turn, may assist in maximizing the amount of carbonate minerals deposited in a given volume of rock (e.g., one or more active storage zones 111) of the subterranean rock formation 110.

FIGS. 4A and 4B show an arrangement of a field system 499 of four wellbores using a well placement strategy according to certain example embodiments. Specifically, FIG. 4A shows a perspective view of the field system 499, and FIG. 4B shows a top view of the field system 499. Referring to the description above with respect to FIGS. 1 through 3, the field system 499 of FIGS. 4A and 4B show a four-spot well pattern (one injection wellbore 442 and three production wellbores 482 (production wellbore 482-1, production wellbore 482-2, and production wellbore 482-3)) drilled into a subterranean rock formation 410.

The injection range of the injection wellbore 442 is located in the active storage zone 411 within the subterranean rock formation 410. Also, the production ranges of production wellbore 482-1, production wellbore 482-2, and production wellbore 482-3 are also located in the active storage zone 411 within the subterranean rock formation 410. In this case, the injection wellbore 442 is surrounded by the three production wellbores 482, which are substantially equally spaced around the injection wellbore 442 in the active storage zone 411.

In this way, the production ranges of the production wellbores 482 of the fluid production well subsystems (e.g., similar to the fluid production well subsystem 180) may be arranged substantially equidistantly from each other relative to the injection range of the injection wellbore 442. Further, as in this example, the production ranges of the production wellbores 482 of the fluid production well subsystems may bound the active storage zone 411 within the subterranean rock formation 410.

A pressurized fluid 443 (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 442, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 442, and into the active storage zone 411. As the pressurized fluid 443 travels through the active storage zone 411 toward one of the production wellbores 482, the pressurized fluid 443 converts to a transition fluid 444 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid 443 is deposited on the accessible internal surfaces of the rock.

The transition fluid 444 mixes with formation fluids naturally occurring in the active storage zone 411 within the subterranean rock formation 410 to form production fluid 483 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 411 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the production wellbores 482. Initially, the active storage zone 411 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 443 and the transition fluid 444 through the active storage zone 411 may be controlled via the balance of inflow rates of one or more of the production wellbores 482. When the rock formation of the active storage zone 411 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid 483 are balanced among the production wellbores 482 and are substantially equal in sum to the injection rate of the pressurized fluid 443 from the injection wellbore 442, the flow pattern of the transition fluid 444 may be substantially similar to what is shown in FIGS. 4A and 4B.

Unbalancing the inflow rates of the production fluid 483 into the production wellbores 482 from the active storage zone 411 (also sometimes referred to as the withdrawal rates of the production fluid 483 from the active storage zone 411 into the production wellbores 482) may be used as necessary to shift the flow pattern within the active storage zone 411 if the fluid permeability of the rock is not homogeneous within the active storage zone 411.

FIGS. 5 through 8 show the progression of field systems using a field development strategy (in this case, using multiple 4-spot well patterns) based on the arrangement shown in FIGS. 4A and 4B according to certain example embodiments. Specifically, the field system 599 of FIG. 5 includes a total of four wellbores. The field system 699 of FIG. 6 adds two wellbores to the field system 599 of FIG. 5. The field system 799 of FIG. 7 adds four wellbores to the field system 699 of FIG. 6. The field system 899 of FIG. 8 adds six wellbores to the field system 799 of FIG. 7. While this example covers 4 stages using multiple 4-spot wall patterns, alternative embodiments may use fewer than 4 stages or more than 4 stages.

Referring to the description above with respect to FIGS. 1 through 4B, the field system 599 of FIG. 5 shows the initial development stage of a four-spot well pattern (one injection wellbore 542 and three production wellbores 582 (production wellbore 582-1, production wellbore 582-2, and production wellbore 582-3)) drilled into a subterranean rock formation 510, including an active storage zone 511. The injection range of the injection wellbore 542 is located in the active storage zone 511 within the subterranean rock formation 510. Also, the production ranges of production wellbore 582-1, production wellbore 582-2, and production wellbore 582-3 are also located in the active storage zone 511, forming its boundary, within the subterranean rock formation 510. In this case, the injection wellbore 542 is surrounded by the three production wellbores 582, which are substantially equally spaced around the injection wellbore 542 in the active storage zone 511.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 542, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 542, and into the active storage zone 511. As the pressurized fluid travels through the active storage zone 511 toward one of the production wellbores 582, the pressurized fluid converts to a transition fluid 544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 544 mixes with formation fluids naturally occurring in the active storage zone 511 within the subterranean rock formation 510 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 511 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the production wellbores 582. Initially, the active storage zone 511 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 544 through the active storage zone 511 may be controlled via the balance of inflow rates of one or more of the production wellbores 582. When the rock formation of the active storage zone 511 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid are balanced among the production wellbores 582 and are substantially equal in sum to the injection rate of the pressurized fluid from the injection wellbore 542, the flow pattern of the transition fluid 544 may be substantially similar to what is shown in FIG. 5.

Unbalancing the inflow rates of the production fluid into the production wellbores 582 from the active storage zone 511 (also sometimes referred to as the withdrawal rates of the production fluid from the active storage zone 511 into the production wellbores 582) may be used as necessary to shift the flow pattern within the active storage zone 511 if the fluid permeability of the rock is not homogeneous within the active storage zone 511. The mineralization process is performed within the active storage zone 511 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zone 511.

At this point, as shown in FIG. 6, the active storage zone 511 becomes a depleted storage zone 613, and so a new section of virgin rock formation (a new active storage zone 611) within the subterranean rock formation 510 is identified and targeted for the mineralization process using example embodiments. Under the field system 699 of FIG. 6, the injection wellbore 542 of the field system 599 of FIG. 5 becomes an abandoned wellbore 662 since the active storage zone 511 of FIG. 5 is now designated as a depleted storage zone 613. Specifically, the active storage zone 511 of FIG. 5 becomes a depleted storage zone 613 in FIG. 6 within the subterranean rock formation 510 when a substantially maximum amount of carbonate minerals has been deposited on accessible internal surfaces of rock within the active storage zone 511. Also, the fluid injection well subsystem of the injection wellbore 542 becomes abandoned when the active storage zone 511 becomes the depleted storage zone 613 within the subterranean rock formation 510.

In addition, with the identification of the new active storage zone 611 that is adjacent to the depleted storage zone 613, example embodiments are used to identify an entry point and path for a new (added) injection wellbore 642 and a new (added) production wellbore 682. Once new injection wellbore 642 and new production wellbore 682 are drilled, being paired together to help form active storage zone 611, the configuration of FIG. 6 results. In the new pattern forming the new active storage zone 611, production wellbore 582-1 and production wellbore 582-2 continue to be used as production wellbores. In addition, production wellbore 582-3 from FIG. 5 is converted to an idle wellbore 663. A fluid production well subsystem (e.g., similar to the fluid production well subsystem 180) may become idle when the active storage zone 511 becomes a depleted storage zone 613 within the subterranean rock formation 510. In this example, the fluid production well subsystem of production wellbore 582-3 becomes idle (is converted to an idle wellbore 663) because the active storage zone 511 becomes a depleted storage zone 613.

The injection range of the injection wellbore 642 is located in the active storage zone 611 within the subterranean rock formation 510. Also, the production ranges of production wellbore 582-1, production wellbore 582-2, and production wellbore 682 are located along the outer perimeter of the active storage zone 611 within the subterranean rock formation 510. In this case, the injection wellbore 642 is surrounded by the three production wellbores (production wellbore 582-1, production wellbore 582-2, and production wellbore 682), which are substantially equally spaced around the injection wellbore 642 in the active storage zone 611.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 642, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 642, and into the active storage zone 611. As the pressurized fluid travels through the active storage zone 611 toward one of the three production wellbores that define the boundary of the active storage zone 611, the pressurized fluid converts to a transition fluid 544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 544 mixes with formation fluids naturally occurring in the active storage zone 611 within the subterranean rock formation 510 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 611 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the three production wellbores that define the boundary of the active storage zone 611. Initially, the active storage zone 611 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 544 through the active storage zone 611 may be controlled via the balance of inflow rates of one or more of the three production wellbores that define the boundary of the active storage zone 611.

If the pressurized fluid injected into the injection wellbore 642 and out the fluid injection completion system at the injection range into the active storage zone 611 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbore 542 of FIG. 5, then the characteristics of the transition fluid 544 flowing through the active storage zone 611 and/or the characteristics of the production fluid that flows into the production wellbores may differ from the characteristics of the production fluid of FIG. 5. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zone 611.

The mineralization process is performed within the active storage zone 611 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zone 611. At this point, as shown in FIG. 7, the active storage zone 611 of FIG. 6 becomes a depleted storage zone 713.

Further, two new sections of virgin rock formation (a new active storage zone 711-1 and a new active storage zone 711-2) within the subterranean rock formation 510 are identified and targeted for the mineralization process using example embodiments. Under the field system 799 of FIG. 7, the injection wellbore 642 of the field system 699 of FIG. 6 becomes an abandoned wellbore 762 since the active storage zone 611 of FIG. 6 is now designated as a depleted storage zone 713.

In addition, with the identification of the new active storage zone 711-1 and the new active storage zone 711-2 that are adjacent to the depleted storage zone 613, example embodiments are used to identify an entry point and path for new (added) injection wellbores 742 and new (added) production wellbores 782. Once new injection wellbore 742-1 and new production wellbore 782-1 are drilled, being paired together to help form active storage zone 711-1, and once new injection wellbore 742-2 and new production wellbore 782-2 are drilled, being paired together to help form active storage zone 711-2, the configuration of FIG. 7 results. In the new pattern forming the new active storage zone 711-1, production wellbore 582-1 and production wellbore 582-3 (converted back from the idle wellbore 663 of FIG. 6) continue to be used as production wellbores. Specifically, the fluid production well subsystem (e.g., similar to the fluid production well subsystem 180) is reverted to a fluid production subsystem after being idle when the production wellbore 582-3 borders a new active storage zone 711-2 within the subterranean rock formation 510. In addition, production wellbore 682 from FIG. 6 is converted to an idle wellbore 763.

The injection range of the new injection wellbore 742-1 is located in the new active storage zone 711-1 within the subterranean rock formation 510. Also, the production ranges of production wellbore 582-1, production wellbore 582-3, and new production wellbore 782-1 are located along the outer perimeter of the active storage zone 711-1 within the subterranean rock formation 510. In this case, the injection wellbore 742-1 is surrounded by the three production wellbores (production wellbore 582-1, production wellbore 582-3, and production wellbore 782-1), which are substantially equally spaced around the injection wellbore 742-1 in the active storage zone 711-1.

In the new pattern forming the new active storage zone 711-2, production wellbore 582-2 and production wellbore 582-3 continue to be used as production wellbores. The injection range of the new injection wellbore 742-2 is located in the new active storage zone 711-2 within the subterranean rock formation 510. Also, the production ranges of production wellbore 582-2, production wellbore 582-3, and new production wellbore 782-2 are located along the outer perimeter of the active storage zone 711-2 within the subterranean rock formation 510. In this case, the injection wellbore 742-2 is surrounded by the three production wellbores (production wellbore 582-2, production wellbore 582-3, and production wellbore 782-2), which are substantially equally spaced around the injection wellbore 742-2 in the active storage zone 711-2.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 742-1, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 742-1, and into the active storage zone 711-1. As the pressurized fluid travels through the active storage zone 711-1 toward one of the three production wellbores that define the boundary of the active storage zone 711-1, the pressurized fluid converts to a transition fluid 544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 544 mixes with formation fluids naturally occurring in the active storage zone 711-1 within the subterranean rock formation 510 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 711-1 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the three production wellbores that define the boundary of the active storage zone 711-1. Initially, the active storage zone 711-1 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 544 through the active storage zone 711-1 may be controlled via the balance of inflow rates of one or more of the three production wellbores that define the boundary of the active storage zone 711-1.

At some point (e.g., simultaneously, subsequently, previously, overlapping), a pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 742-2, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 742-2, and into the active storage zone 711-2. The pressurized fluid used with injection wellbore 742-2 may be the same as, or different than, the pressurized fluid used with injection wellbore 742-1 discussed above. As the pressurized fluid travels through the active storage zone 711-2 toward one of the three production wellbores that define the boundary of the active storage zone 711-2, the pressurized fluid converts to a transition fluid 544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 544 mixes with formation fluids naturally occurring in the active storage zone 711-2 within the subterranean rock formation 510 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 711-2 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the three production wellbores that define the boundary of the active storage zone 711-2. Initially, the active storage zone 711-2 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 544 through the active storage zone 711-2 may be controlled via the balance of inflow rates of one or more of the three production wellbores that define the boundary of the active storage zone 711-2. The rate of saturation of active storage zone 711-1 may be the same as or different than the saturation rate of active storage zone 711-2.

If the pressurized fluid injected into the injection wellbore 742-1 and out the fluid injection completion system at the injection range into the active storage zone 711-1 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbore 542 of FIG. 5, and/or if the pressurized fluid injected into the injection wellbore 742-2 and out the fluid injection completion system at the injection range into the active storage zone 711-2 differs from the pressurized fluid used with the injection wellbores of FIG. 5 or 6, then the characteristics of the transition fluid 544 flowing through the active storage zone 711-1 and/or active storage zone 711-2 and/or the characteristics of the production fluid that flows into the production wellbores may differ from the characteristics of the production fluid of FIG. 5 or 6. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zone 711-1 and the active storage zone 711-2.

The mineralization process is performed (e.g., simultaneously, sequentially, overlapping) within the active storage zone 711-1 and the active storage zone 711-2 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted in each active storage zone 711. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within each active storage zone 711. At this point, as shown in FIG. 8, the active storage zone 711-1 and the active storage zone 711-2 of FIG. 7 become depleted storage zone 813-1 and depleted storage zone 813-2, respectively.

Further, three new sections of virgin rock formation (a new active storage zone 811-1, a new active storage zone 811-2, and a new active storage zone 811-3) within the subterranean rock formation 510 are identified and targeted for the mineralization process using example embodiments. Under the field system 899 of FIG. 8, the injection wellbore 742-1 of the field system 799 of FIG. 7 becomes an abandoned wellbore 862-1 since the active storage zone 711-1 of FIG. 7 is now designated as a depleted storage zone 813-1, and the injection wellbore 742-2 of the field system 799 of FIG. 7 becomes an abandoned wellbore 862-2 since the active storage zone 711-2 of FIG. 7 is now designated as a depleted storage zone 813-2.

In addition, with the identification of the new active storage zone 811-1 that is adjacent to the depleted storage zone 813-1, the new active storage zone 811-2 that is adjacent to the depleted storage zone 813-2, and the new active storage zone 811-3 that is adjacent to the depleted storage zone 713, example embodiments are used to identify an entry point and path for new (added) injection wellbores 842 and new (added) production wellbores 882. Once new injection wellbore 842-1 and new production wellbore 882-1 are drilled, being paired together to help form active storage zone 811-1, once new injection wellbore 842-2 and new production wellbore 882-2 are drilled, being paired together to help form active storage zone 811-2, and once new injection wellbore 842-3 and new production wellbore 882-3 are drilled, being paired together to help form active storage zone 811-3, the configuration of FIG. 8 results.

In the new pattern forming the new active storage zone 811-1, production wellbore 582-3 and production wellbore 782-1 continue to be used as production wellbores. The injection range of the new injection wellbore 842-1 is located in the new active storage zone 811-1 within the subterranean rock formation 510. Also, the production ranges of production wellbore 782-1, production wellbore 582-3, and new production wellbore 882-1 are located along the outer perimeter of in the active storage zone 811-1 within the subterranean rock formation 510. In this case, the injection wellbore 842-1 is surrounded by the three production wellbores (production wellbore 782-1, production wellbore 582-3, and production wellbore 882-1), which are substantially equally spaced around the injection wellbore 842-1 in the active storage zone 811-1.

In the new pattern forming the new active storage zone 811-2, production wellbore 582-2 and production wellbore 782-2 continue to be used as production wellbores. The injection range of the new injection wellbore 842-2 is located in the new active storage zone 811-2 within the subterranean rock formation 510. Also, the production ranges of production wellbore 582-2, production wellbore 782-2, and new production wellbore 882-2 are located along the outer perimeter of the active storage zone 811-2 within the subterranean rock formation 510. In this case, the injection wellbore 842-2 is surrounded by the three production wellbores (production wellbore 582-2, production wellbore 782-2, and production wellbore 882-2), which are substantially equally spaced around the injection wellbore 842-2 in the active storage zone 811-2.

In the new pattern forming the new active storage zone 811-3, production wellbore 582-1 and production wellbore 682 continue to be used as production wellbores. The injection range of the new injection wellbore 842-3 is located in the new active storage zone 811-3 within the subterranean rock formation 510. Also, the production ranges of production wellbore 582-1, production wellbore 682, and new production wellbore 882-3 are located along the outer perimeter of the active storage zone 811-3 within the subterranean rock formation 510. In this case, the injection wellbore 842-3 is surrounded by the three production wellbores (production wellbore 582-1, production wellbore 682, and production wellbore 882-3), which are substantially equally spaced around the injection wellbore 842-3 in the active storage zone 811-3.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 842-1, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 842-1, and into the active storage zone 811-1. As the pressurized fluid travels through the active storage zone 811-1 toward one of the three production wellbores that define the boundary of the active storage zone 811-1, the pressurized fluid converts to a transition fluid 544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 544 mixes with formation fluids naturally occurring in the active storage zone 811-1 within the subterranean rock formation 510 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 811-1 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the three production wellbores that define the boundary of the active storage zone 811-1. Initially, the active storage zone 811-1 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 544 through the active storage zone 811-1 may be controlled via the balance of inflow rates of one or more of the three production wellbores that define the boundary of the active storage zone 811-1.

At some point (e.g., simultaneously, subsequently, previously, overlapping), a pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 842-2, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 842-2, and into the active storage zone 811-2. The pressurized fluid used with injection wellbore 842-2 may be the same as, or different than, the pressurized fluid used with injection wellbore 842-1 discussed above. As the pressurized fluid travels through the active storage zone 811-2 toward one of the three production wellbores that define the boundary of the active storage zone 811-2, the pressurized fluid converts to a transition fluid 544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 544 mixes with formation fluids naturally occurring in the active storage zone 811-2 within the subterranean rock formation 510 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 811-2 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the three production wellbores that define the boundary of the active storage zone 811-2. Initially, the active storage zone 811-2 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 544 through the active storage zone 811-2 may be controlled via the balance of inflow rates of one or more of the three production wellbores that define the boundary of the active storage zone 811-2. The rate of saturation of active storage zone 811-1 may be the same as or different than the saturation rate of active storage zone 811-2.

Further, at some point (e.g., simultaneously, subsequently, previously, overlapping), a pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 842-3, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 842-3, and into the active storage zone 811-3. The pressurized fluid used with injection wellbore 842-3 may be the same as, or different than, the pressurized fluid used with injection wellbore 842-1 and/or injection wellbore 842-2 discussed above. As the pressurized fluid travels through the active storage zone 811-3 toward one of the three production wellbores that define the boundary of the active storage zone 811-3, the pressurized fluid converts to a transition fluid 544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 544 mixes with formation fluids naturally occurring in the active storage zone 811-3 within the subterranean rock formation 510 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 811-3 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the three production wellbores that define the boundary of the active storage zone 811-3. Initially, the active storage zone 811-3 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 544 through the active storage zone 811-3 may be controlled via the balance of inflow rates of one or more of the three production wellbores that define the boundary of the active storage zone 811-3. The rate of saturation of active storage zone 811-1 may be the same as or different than the saturation rate of active storage zone 811-2, which may be the same as or different than the saturation rate of active storage zone 811-3.

If the pressurized fluid injected into the injection wellbore 842-1 and out the fluid injection completion system at the injection range into the active storage zone 811-1 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbore 542 of FIG. 5, and/or if the pressurized fluid injected into the injection wellbore 842-2 and out the fluid injection completion system at the injection range into the active storage zone 811-2 differs from the pressurized fluid used with the injection wellbores of FIG. 5 or 6, and/or if the pressurized fluid injected into the injection wellbore 842-3 and out the fluid injection completion system at the injection range into the active storage zone 811-3 differs from the pressurized fluid used with the injection wellbores of FIGS. 5, 6, or 7, then the characteristics of the transition fluid 544 flowing through the active storage zone 811-1, the active storage zone 811-2, and/or the active storage zone 811-3 and/or the characteristics of the production fluid that flows into the production wellbores may differ from the characteristics of the production fluid of FIGS. 5, 6, or 7. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zone 811-1, the active storage zone 811-2, and the active storage zone 811-3.

The mineralization process is performed (e.g., simultaneously, sequentially, overlapping) within the active storage zone 811-1, the active storage zone 811-2, and the active storage zone 811-3 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted in each active storage zone 811. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within each active storage zone 811.

Throughout this sequence in this example, no wellbore is abandoned unless it is surrounded by rock whose carbon storage potential is depleted (e.g., unless it is in the middle of a depleted storage zone (e.g., depleted storage zone 613)). In alternative embodiments, as when the wellbores shown in FIGS. 5 through 8 are substantially vertical sections, an injection wellbore (e.g., injection wellbore 542) that is later surrounded by rock whose carbon storage potential is depleted may avoid becoming abandoned (e.g., may be temporarily converted to idle status, may continue producing) by moving its fluid injection completion system (e.g., fluid injection completion system 148) to another location along the injection wellbore to continue to be utilized, either as an injection wellbore or a production wellbore, in another formation layer (e.g., having mafic rock, having ultramafic rock) of the subterranean rock formation 510 that may be used as an active storage zone.

Further, the lateral spacing of wellbores may be significantly greater (e.g., at least by an order of magnitude) than the thickness of the formation layer having the storage formation rock (e.g., mafic rock, ultramafic rock) through which fluid (e.g., pressurized fluid, transition fluid) is flowing. In such cases, a well pattern made up of non-horizontal wellbores (e.g., of any deviation from vertical that is ≤60°) may generate an overall fluid flow pattern that differs little from one generated by a well pattern using vertical wellbores (e.g., of any deviation from vertical that is ≤15°). The flow pattern local to a wellbore may be impacted by its deviation from vertical, but the far-field flow pattern between wellbores may be relatively unaffected. This may be true for (1) high well spacing to formation thick ratios and/or (2) a system where displaced and displacing fluids are of similar viscosity and density.

FIGS. 9 through 12 show the progression of field systems using another field development strategy based on five wellbores in a grouping according to certain example embodiments. Specifically, the field system 999 of FIG. 9 includes a total of five wellbores. The field system 1099 of FIG. 10 adds three wellbores to the field system 999 of FIG. 9. The field system 1199 of FIG. 11 adds five wellbores to the field system 1099 of FIG. 10. The field system 1299 of FIG. 12 adds five wellbores to the field system 1199 of FIG. 11. While this example covers 4 stages using multiple 5-spot wall patterns, alternative embodiments may use fewer than 4 stages or more than 4 stages.

Referring to the description above with respect to FIGS. 1 through 8, the field system 999 of FIG. 9 shows the initial development stage of a five-spot well pattern (one injection wellbore 942 and four production wellbores 982 (production wellbore 982-1, production wellbore 982-2, production wellbore 982-3, and production wellbore 982-4)) drilled into a subterranean rock formation 910, including an active storage zone 911. The injection range of the injection wellbore 942 is located in the active storage zone 911 within the subterranean rock formation 910. Also, the production ranges of production wellbore 982-1, production wellbore 982-2, production wellbore 982-3, and production wellbore 982-4 are also located in the active storage zone 911, forming its boundary, within the subterranean rock formation 910. In this case, the injection wellbore 942 is surrounded by the four production wellbores 982, which are substantially equally spaced around the injection wellbore 942 in the active storage zone 911.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 942, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 942, and into the active storage zone 911. As the pressurized fluid travels through the active storage zone 911 toward one of the production wellbores 982, the pressurized fluid converts to a transition fluid 944 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 944 mixes with formation fluids naturally occurring in the active storage zone 911 within the subterranean rock formation 910 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 911 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the production wellbores 982. Initially, the active storage zone 911 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 944 through the active storage zone 911 may be controlled via the balance of inflow rates of one or more of the production wellbores 982. When the rock formation of the active storage zone 911 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid are balanced among the production wellbores 982 and are substantially equal in sum to the injection rate of the pressurized fluid from the injection wellbore 942, the flow pattern of the transition fluid 944 may be substantially similar to what is shown in FIG. 9.

Unbalancing the inflow rates of the production fluid into the production wellbores 982 from the active storage zone 911 (also sometimes referred to as the withdrawal rates of the production fluid from the active storage zone 911 into the production wellbores 982) may be used as necessary to shift the flow pattern within the active storage zone 911 if the fluid permeability of the rock is not homogeneous within the active storage zone 911. The mineralization process is performed within the active storage zone 911 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zone 911.

In comparing the five-spot well configuration of FIG. 9 with the four-spot well configuration of FIG. 5 above, if using the identical spacing between production wellbores (e.g., production wellbores 582, production wellbores 982), the active storage zone 911 of the five-spot well configuration is approximately 230% larger than the active storage zone 511 of the four-spot well configuration. This translates to a significantly larger potential for implementing the mineralization process. The use of four production wellbores rather than three production wellbores to a single injection wellbore may allow for greater control of the inter-wellbore flow pattern via the individual withdrawal rates of the production wellbores.

Once the active storage zone 911 is depleted, as shown in FIG. 10, the active storage zone 911 becomes a depleted storage zone 1013, and so a new section of virgin rock formation (a new active storage zone 1011) within the subterranean rock formation 910 is identified and targeted for the mineralization process using example embodiments. Under the field system 1099 of FIG. 10, the injection wellbore 942 of the field system 999 of FIG. 9 becomes an abandoned wellbore 1062 since the active storage zone 911 of FIG. 9 is now designated as a depleted storage zone 1013.

In addition, with the identification of the new active storage zone 1011 that is adjacent to the depleted storage zone 1013, example embodiments are used to identify an entry point and path for a new (added) injection wellbore 1042 and two new (added) production wellbores 1082 (production wellbore 1082-1 and production wellbore 1082-2). Once new injection wellbore 1042 and new production wellbores 1082 are drilled, being paired together to help form active storage zone 1011, the configuration of FIG. 10 results. In the new pattern forming the new active storage zone 1011, production wellbore 982-1 and production wellbore 982-4 continue to be used as production wellbores. In addition, production wellbore 982-2 and production wellbore 982-3 from FIG. 9 is converted to idle wellbore 1063-2 and idle wellbore 1063-3, respectively. The injection range of the injection wellbore 1042 is located in the active storage zone 1011 within the subterranean rock formation 910. Also, the production ranges of production wellbore 982-1, production wellbore 982-4, production wellbore 1082-1, and production wellbore 1082-2 are located along the outer perimeter of the active storage zone 1011 within the subterranean rock formation 910. In this case, the injection wellbore 1042 is surrounded by the four production wellbores (production wellbore 982-1, production wellbore 982-4, production wellbore 1082-1, and production wellbore 1082-2), which are substantially equally spaced around the injection wellbore 1042 in the active storage zone 1011.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 1042, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 1042, and into the active storage zone 1011. As the pressurized fluid travels through the active storage zone 1011 toward one of the four production wellbores that define the boundary of the active storage zone 1011, the pressurized fluid converts to a transition fluid 944 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 944 mixes with formation fluids naturally occurring in the active storage zone 1011 within the subterranean rock formation 910 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1011 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the four production wellbores that define the boundary of the active storage zone 1011. Initially, the active storage zone 1011 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 944 through the active storage zone 1011 may be controlled via the balance of inflow rates of one or more of the four production wellbores that define the boundary of the active storage zone 1011.

If the pressurized fluid injected into the injection wellbore 1042 and out the fluid injection completion system at the injection range into the active storage zone 1011 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbore 942 of FIG. 9, then the characteristics of the transition fluid 944 flowing through the active storage zone 1011 and/or the characteristics of the production fluid that flows into the production wellbores may differ from the characteristics of the production fluid of FIG. 9. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B may generally apply to the active storage zone 1011.

The mineralization process is performed within the active storage zone 1011 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zone 1011. At this point, as shown in FIG. 11, the active storage zone 1011 of FIG. 10 becomes a depleted storage zone 1113.

Further, two new sections of virgin rock formation (a new active storage zone 1111-1 and a new active storage zone 1111-2) within the subterranean rock formation 910 is identified and targeted for the mineralization process using example embodiments. Under the field system 1199 of FIG. 11, the injection wellbore 1042 of the field system 1099 of FIG. 10 becomes an abandoned wellbore 1162 since the active storage zone 1011 of FIG. 10 is now designated as a depleted storage zone 1113.

In addition, with the identification of the new active storage zone 1111-1 and the new active storage zone 1111-2 that are adjacent to the depleted storage zone 1013 and the depleted storage zone 1113, respectively, example embodiments are used to identify an entry point and path for new (added) injection wellbores 1142 and new (added) production wellbores 1182. Once new injection wellbore 1142-1, new production wellbore 1182-1, and new production wellbore 1182-2 are drilled, being paired together to help form active storage zone 1111-1, and once new injection wellbore 1142-2 and new production wellbore 1182-3 are drilled, being paired together with new production wellbore 1182-2 to help form active storage zone 1111-2, the configuration of FIG. 11 results. In the new pattern forming the new active storage zone 1111-1, production wellbore 982-4 and production wellbore 1082-1 continue to be used as production wellbores, and in the new pattern forming the new active storage zone 1111-2, production wellbore 982-3 and production wellbore 1082-1 continue to be used as production wellbores. In addition, production wellbore 982-1 and production wellbore 1082-2 from FIG. 10 are converted to idle wellbore 1163-2 and idle wellbore 1163-1, respectively. The status of idle wellbore 1063-2 from FIG. 10 is unchanged.

The injection range of the new injection wellbore 1142-1 is located in the new active storage zone 1111-1 within the subterranean rock formation 910. Also, the production ranges of production wellbore 982-4, production wellbore 1082-1, new production wellbore 1182-1, and new production wellbore 1182-2 are located along the outer perimeter of the active storage zone 1111-1 within the subterranean rock formation 910. In this case, the injection wellbore 1142-1 is surrounded by the four production wellbores (production wellbore 982-4, production wellbore 1082-1, production wellbore 1182-1, and production wellbore 1182-2), which are substantially equally spaced around the injection wellbore 1142-1 in the active storage zone 1111-1.

In the new pattern forming the new active storage zone 1111-2, production wellbore 982-3 and production wellbore 982-4 continue to be used as production wellbores. The injection range of the new injection wellbore 1142-2 is located in the new active storage zone 1111-2 within the subterranean rock formation 910. Also, the production ranges of production wellbore 982-3, production wellbore 982-4, new production wellbore 1182-2, and new production wellbore 1182-3 are located along the outer perimeter of the active storage zone 1111-2 within the subterranean rock formation 910. In this case, the injection wellbore 1142-2 is surrounded by the four production wellbores (production wellbore 982-3, production wellbore 982-4, production wellbore 1182-2, and production wellbore 1182-3), which are substantially equally spaced around the injection wellbore 1142-2 in the active storage zone 1111-2.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 1142-1, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 1142-1, and into the active storage zone 1111-1. As the pressurized fluid travels through the active storage zone 1111-1 toward one of the four production wellbores that define the boundary of the active storage zone 1111-1, the pressurized fluid converts to a transition fluid 944 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 944 mixes with formation fluids naturally occurring in the active storage zone 1111-1 within the subterranean rock formation 910 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1111-1 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the four production wellbores that define the boundary of the active storage zone 1111-1. Initially, the active storage zone 1111-1 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 944 through the active storage zone 1111-1 may be controlled via the balance of inflow rates of one or more of the four production wellbores that define the boundary of the active storage zone 1111-1.

At some point (e.g., simultaneously, subsequently, previously, overlapping), a pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 1142-2, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 1142-2, and into the active storage zone 1111-2. The pressurized fluid used with injection wellbore 1142-2 may be the same as, or different than, the pressurized fluid used with injection wellbore 1142-1 discussed above. As the pressurized fluid travels through the active storage zone 1111-2 toward one of the four production wellbores that define the boundary of the active storage zone 1111-2, the pressurized fluid converts to a transition fluid 944 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 944 mixes with formation fluids naturally occurring in the active storage zone 1111-2 within the subterranean rock formation 910 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1111-2 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the four production wellbores that define the boundary of the active storage zone 1111-2. Initially, the active storage zone 1111-2 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 944 through the active storage zone 1111-2 may be controlled via the balance of inflow rates of one or more of the four production wellbores that define the boundary of the active storage zone 1111-2. The rate of saturation of the active storage zone 1111-1 may be the same as or different than the saturation rate of the active storage zone 1111-2.

If the pressurized fluid injected into the injection wellbore 1142-1 and out the fluid injection completion system at the injection range into the active storage zone 1111-1 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbore 942 of FIG. 9, and/or if the pressurized fluid injected into the injection wellbore 1142-2 and out the fluid injection completion system at the injection range into the active storage zone 1111-2 differs from the pressurized fluid used with the injection wellbores of FIG. 9 or 10, then the characteristics of the transition fluid 944 flowing through the active storage zone 1111-1 and/or active storage zone 1111-2 and/or the characteristics of the production fluid that flows into the production wellbores may differ from the characteristics of the production fluid of FIG. 9 or 10. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zone 1111-1 and the active storage zone 1111-2.

The mineralization process is performed (e.g., simultaneously, sequentially, overlapping) within the active storage zone 1111-1 and the active storage zone 1111-2 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted in each active storage zone 1111. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within each active storage zone 1111. At this point, as shown in FIG. 12, the active storage zone 1111-1 and the active storage zone 1111-2 of FIG. 11 become depleted storage zone 1213-1 and depleted storage zone 1213-2, respectively.

Further, two new sections of virgin rock formation (a new active storage zone 1211-1 and a new active storage zone 1211-2) within the subterranean rock formation 910 is identified and targeted for the mineralization process using example embodiments. Under the field system 1299 of FIG. 12, the injection wellbore 1142-1 of the field system 1199 of FIG. 11 becomes an abandoned wellbore 1262-1 since the active storage zone 1111-1 of FIG. 11 is now designated as a depleted storage zone 1213-1, and the injection wellbore 1142-2 of the field system 1199 of FIG. 11 becomes an abandoned wellbore 1262-2 since the active storage zone 1111-2 of FIG. 11 is now designated as a depleted storage zone 1213-2. In addition, production wellbore 982-4, production wellbore 1082-1, production wellbore 1182-1, and production wellbore 1182-2 from FIG. 11 are converted to idle wellbore 1263-2, idle wellbore 1263-1, idle wellbore 1263-3, and idle wellbore 1263-4, respectively.

In addition, with the identification of the new active storage zone 1211-1 that is adjacent to the depleted storage zone 1213-2 and the new active storage zone 1211-2 that is adjacent to the depleted storage zone 1013, example embodiments are used to identify an entry point and path for new (added) injection wellbores 1242 and new (added) production wellbores 1282. Once new injection wellbore 1242-1, new production wellbore 1282-1, and new production wellbore 1282-2 are drilled, being paired together to help form active storage zone 1211-1, and once new injection wellbore 1242-2 and new production wellbore 1282-3 are drilled, being paired together with new production wellbore 1282-2 to help form active storage zone 1211-2, the configuration of FIG. 12 results. In the new pattern forming the new active storage zone 1211-1, production wellbore 982-3 and production wellbore 1182-3 continue to be used as production wellbores, and in the new pattern forming the new active storage zone 1211-2, production wellbore 982-2 and production wellbore 982-3 continue to be used as production wellbores.

The injection range of the new injection wellbore 1242-1 is located in the new active storage zone 1211-1 within the subterranean rock formation 910. Also, the production ranges of production wellbore 982-3, production wellbore 1182-3, new production wellbore 1282-1, and new production wellbore 1282-2 are located along the outer perimeter of in the active storage zone 1211-1 within the subterranean rock formation 910. In this case, the injection wellbore 1242-1 is surrounded by the four production wellbores (production wellbore 982-3, production wellbore 1182-3, production wellbore 1282-1, and production wellbore 1282-2), which are substantially equally spaced around the injection wellbore 1242-1 in the active storage zone 1211-1.

In the new pattern forming the new active storage zone 1211-2, production wellbore 982-2 and production wellbore 982-3 continue to be used as production wellbores. The injection range of the new injection wellbore 1242-2 is located in the new active storage zone 1211-2 within the subterranean rock formation 910. Also, the production ranges of production wellbore 982-2, production wellbore 982-3, new production wellbore 1282-2, and new production wellbore 1282-3 are located along the outer perimeter of the active storage zone 1211-2 within the subterranean rock formation 910. In this case, the injection wellbore 1242-2 is surrounded by the four production wellbores (production wellbore 982-2, production wellbore 982-3, production wellbore 1282-2, and production wellbore 1282-3), which are substantially equally spaced around the injection wellbore 1242-2 in the active storage zone 1211-2.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 1242-1, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 1242-1, and into the active storage zone 1211-1. As the pressurized fluid travels through the active storage zone 1211-1 toward one of the four production wellbores that define the boundary of the active storage zone 1211-1, the pressurized fluid converts to a transition fluid 944 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 944 mixes with formation fluids naturally occurring in the active storage zone 1211-1 within the subterranean rock formation 910 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1211-1 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the four production wellbores that define the boundary of the active storage zone 1211-1. Initially, the active storage zone 1211-1 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 944 through the active storage zone 1211-1 may be controlled via the balance of inflow rates of one or more of the four production wellbores that define the boundary of the active storage zone 1211-1.

At some point (e.g., simultaneously, subsequently, previously, overlapping), a pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 1242-2, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 1242-2, and into the active storage zone 1211-2. The pressurized fluid used with injection wellbore 1242-2 may be the same as, or different than, the pressurized fluid used with injection wellbore 1242-1 discussed above. As the pressurized fluid travels through the active storage zone 1211-2 toward one of the four production wellbores that define the boundary of the active storage zone 1211-2, the pressurized fluid converts to a transition fluid 944 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 944 mixes with formation fluids naturally occurring in the active storage zone 1211-2 within the subterranean rock formation 910 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1211-2 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the four production wellbores that define the boundary of the active storage zone 1211-2. Initially, the active storage zone 1211-2 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 944 through the active storage zone 1211-2 may be controlled via the balance of inflow rates of one or more of the four production wellbores that define the boundary of the active storage zone 1211-2. The rate of saturation of active storage zone 1211-1 may be the same as or different than the saturation rate of active storage zone 1211-2.

If the pressurized fluid injected into the injection wellbore 1242-1 and out the fluid injection completion system at the injection range into the active storage zone 1211-1 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbore 942 of FIG. 9, and/or if the pressurized fluid injected into the injection wellbore 1242-2 and out the fluid injection completion system at the injection range into the active storage zone 1211-2 differs from the pressurized fluid used with the injection wellbores of FIGS. 9, 10, or 11, then the characteristics of the transition fluid 944 flowing through the active storage zone 1211-1 and/or the active storage zone 1211-2, and/or the characteristics of the production fluid that flows into the production wellbores, may differ from the characteristics of the production fluid of FIGS. 9, 10, or 11. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B generally applies to the active storage zone 1211-1 and the active storage zone 1211-2.

The mineralization process is performed (e.g., simultaneously, sequentially, overlapping) within the active storage zone 1211-1 and the active storage zone 1211-2 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted in each active storage zone 1211. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within each active storage zone 1211.

Throughout the sequence in this example, no wellbore is abandoned unless it is surrounded by rock whose carbon storage potential is depleted (e.g., unless it is in the middle of a depleted storage zone (e.g., depleted storage zone 1013). In alternative embodiments, as when the wellbores shown in FIGS. 9 through 12 are substantially vertical sections, an injection wellbore (e.g., injection wellbore 942) that is later surrounded by rock whose carbon storage potential is depleted may avoid becoming abandoned (e.g., may be temporarily converted to idle status, may continue producing) by moving its fluid injection completion system (e.g., fluid injection completion system 148) to another location along the injection wellbore to continue to be utilized, either as an injection wellbore or a production wellbore, in another formation layer (e.g., having mafic rock, having ultramafic rock) of the subterranean rock formation 910 that may be used as an active storage zone. Also, as evidenced by the sequence in this example, one or more production wellbores (e.g., production wellbore 982-3) may be used for the carbon dioxide saturation of multiple active storage zones before being abandoned.

FIG. 13 shows an arrangement of a field system 1399 using a well placement strategy in the form of a semi-line-drive well pattern according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 12, the field system 1399 of FIG. 13 includes 9 wellbores drilled through an active storage zone 1311 within a subterranean rock formation 1310. Within the active storage zone 1311, each of the wellbores are substantially vertical wellbores (or at least non-horizontal wellbores). This configuration of the wellbores within the field system 1399 may be referred to as a semi-line-drive well pattern.

Specifically, the wellbores are arranged in a 3×3 pattern, where one outer row has three production wellbores 1382 (production wellbore 1382-1, production wellbore 1382-2, and production wellbore 1382-3), where the other outer row has three production wellbores 1382 (production wellbore 1382-4, production wellbore 1382-5, and production wellbore 1382-6), and where the middle row has three injection wellbores 1342 (injection wellbore 1342-1, injection wellbore 1342-2, and injection wellbore 1342-3).

In some cases, a line or plane formed by production wellbore 1382-1, injection wellbore 1342-1, and production wellbore 1382-4 within the active storage zone 1311 may be substantially parallel with a line or plane formed by production wellbore 1382-2, injection wellbore 1342-2, and production wellbore 1382-5 within the active storage zone 1311, which may be substantially parallel with a line or plane formed by production wellbore 1382-3, injection wellbore 1342-3, and production wellbore 1382-6 within the active storage zone 1311. In some cases, the distances between such lines or planes may be substantially the same.

The injection range of each of the injection wellbores 1342 is located in the active storage zone 1311 within the subterranean rock formation 1310. Also, the production ranges of each of the production wellbores 1382 is located in the active storage zone 1311 within the subterranean rock formation 1310. This orientation of the injection wellbores 1342 and the production wellbores 1382 creates a semi-linear flow within the active storage zone 1311. The spacing of the various wellbores is substantially uniform along the rows and columns of the field system 1399.

A pressurized fluid 1343 (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., simultaneously, sequentially, iteratively) into the injection wellbores 1342, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the respective injection wellbore 1342, and into the active storage zone 1311. As the pressurized fluid 1343 travels through the active storage zone 1311 toward one of the outer rows of production wellbores 1382, the pressurized fluid 1343 converts to a transition fluid 1344 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid 1343 is deposited on the accessible internal surfaces of the rock.

The transition fluid 1344 mixes with formation fluids naturally occurring in the active storage zone 1311 within the subterranean rock formation 1310 to form production fluid 1383 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1311 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the production wellbores 1382. Initially, the active storage zone 1311 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 1343 and the transition fluid 1344 through the active storage zone 1311 may be controlled via the balance of inflow rates of one or more of the production wellbores 1382. When the rock formation of the active storage zone 1311 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid 1383 are balanced among the production wellbores 1382 and are substantially equal in sum to the injection rate of the pressurized fluid 1343 from the injection wellbores 1342, the flow pattern of the transition fluid 1344 may be substantially similar to what is shown in FIG. 13.

Unbalancing the inflow rates of the production fluid 1383 into the production wellbores 1382 from the active storage zone 1311 (also sometimes referred to as the withdrawal rates of the production fluid 1383 from the active storage zone 1311 into the production wellbores 1382) may be used as necessary to shift the flow pattern within the active storage zone 1311 if the fluid permeability of the rock is not homogeneous within the active storage zone 1311. Using the type of well pattern shown in FIG. 13, large sections of the active storage zone 1311 may be developed with an overall simpler flow pattern than using multiple 4-spot or 5-spot well patterns simultaneously, as with the examples of FIGS. 5 through 12.

In addition, this type of well pattern may be utilized without sacrificing substantial amounts of accessible rock volume within the active storage zone 1311. A relatively simpler flow pattern may also result in simpler monitoring techniques in determining the progress of the mineralization process within the active storage zone 1311. However, deployment of a such a well pattern may require that fluid flow properties of a large section of the active storage zone 1311 are reasonably understood. If the fluid flow properties of relatively large sections of the active storage zone 1311 are not reasonably understood, then utilizing arrangements such as the 4-spot and 5-spot well patterns discussed above may be preferred in the early stages of developing a large-scale carbon storage project that relies on the mineralization process.

FIGS. 14 through 16 show the progression of field systems using a field development strategy based on the semi-line-drive well pattern shown in FIG. 13 according to certain example embodiments. Specifically, the field system 1499 of FIG. 14 includes a total of 18 wellbores. The field system 1599 of FIG. 15 adds 12 wellbores to the field system 1499 of FIG. 14. The field system 1699 of FIG. 16 adds 12 wellbores to the field system 1599 of FIG. 15. While this example covers 3 stages using multiple semi-line-drive well patterns, alternative embodiments may use fewer than 3 stages or more than 3 stages.

Referring to the description above with respect to FIGS. 1 through 13, the field system 1499 of FIG. 14 shows the initial development stage of a semi-line-drive well pattern (one row of injection wellbores 1442 positioned between two rows of production wellbores 1482, where all wellbores are drilled through an active storage zone 1411 within a subterranean rock formation 1410. The injection range of each of the injection wellbores 1442 (injection wellbore 1442-1, injection wellbore 1442-2, injection wellbore 1442-3, injection wellbore 1442-4, injection wellbore 1442-5, and injection wellbore 1442-6) is located in the active storage zone 1411 within the subterranean rock formation 1410.

Also, the production ranges of the production wellbores 1482 (production wellbore 1482-1, production wellbore 1482-2, production wellbore 1482-3, production wellbore 1482-4, production wellbore 1482-5, and production wellbore 1482-6 in one outside row, and production wellbore 1482-7, production wellbore 1482-8, production wellbore 1482-9, production wellbore 1482-10, production wellbore 1482-11, and production wellbore 1482-12 in the opposite outside row) are also located in the active storage zone 1411, forming its boundary, within the subterranean rock formation 1410. The spacing of the various wellbores is substantially uniform along the rows and columns of the field system 1499.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbores 1742, out each of their respective fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along their respective injection wellbore 1442, and into the active storage zone 1411. As the pressurized fluid travels through the active storage zone 1411 toward one of the production wellbores 1482, the pressurized fluid converts to a transition fluid 1444 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 1444 mixes with formation fluids naturally occurring in the active storage zone 1411 within the subterranean rock formation 1410 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1411 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the production wellbores 1482. Initially, the active storage zone 1411 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 1444 through the active storage zone 1411 may be controlled via the balance of inflow rates of one or more of the production wellbores 1482. When the rock formation of the active storage zone 1411 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid are balanced among the production wellbores 1482 and are substantially equal in sum to the injection rate of the pressurized fluid from the injection wellbores 1442, the flow pattern of the transition fluid 1444 may be substantially similar to what is shown in FIG. 14.

Unbalancing the inflow rates of the production fluid into the production wellbores 1482 from the active storage zone 1411 (also sometimes referred to as the withdrawal rates of the production fluid from the active storage zone 1411 into the production wellbores 1482) may be used as necessary to shift the flow pattern within the active storage zone 1411 if the fluid permeability of the rock is not homogeneous within the active storage zone 1411. The mineralization process is performed within the active storage zone 1411 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zone 1411.

At this point, as shown in FIG. 15, the active storage zone 1411 becomes a depleted storage zone 1513, and so two new sections of virgin rock formation (two new active storage zones 1511) within the subterranean rock formation 1410 are identified and targeted for the mineralization process using example embodiments. Under the field system 1599 of FIG. 15, the six injection wellbores 1442 of the field system 1499 of FIG. 14 become abandoned wellbores 1562 (abandoned wellbore 1562-1, abandoned wellbore 1562-2, abandoned wellbore 1562-3, abandoned wellbore 1562-4, abandoned wellbore 1562-5, and abandoned wellbore 1562-6) since the active storage zone 1411 of FIG. 14 is now designated as a depleted storage zone 1513.

In addition, with the identification of two new active storage zones 1511 (active storage zone 1511-1 and active storage zone 1511-2) that are adjacent to the depleted storage zone 1513, example embodiments are used to identify an entry point and path for a total of 12 new (added) production wellbores 1582 in two rows, where one row includes production wellbore 1582-1, production wellbore 1582-2, production wellbore 1582-3, production wellbore 1582-4, production wellbore 1582-5, and production wellbore 1582-6, and where the other row includes production wellbore 1582-7, production wellbore 1582-8, production wellbore 1582-9, production wellbore 1582-10, production wellbore 1582-11, and production wellbore 1582-12.

Once the new production wellbores 1582 are drilled, the configuration of FIG. 15 results. In the new pattern forming the new active storage zone 1511-1, production wellbore 1482-1, production wellbore 1482-2, production wellbore 1482-3, production wellbore 1482-4, production wellbore 1482-5 and production wellbore 1482-6 from FIG. 14 are converted to injection wellbore 1542-1, injection wellbore 1542-2, injection wellbore 1542-3, injection wellbore 1542-4, injection wellbore 1542-5, and injection wellbore 1542-6, respectively. Injection wellbore 1542-1 through injection wellbore 1542-6 form one side boundary of the active storage zone 1511-1, while production wellbore 1582-1 through production wellbore 1582-6 form the opposite side boundary of the active storage zone 1511-1.

Similarly, in the new pattern forming the new active storage zone 1511-2, production wellbore 1482-7, production wellbore 1482-8, production wellbore 1482-9, production wellbore 1482-10, production wellbore 1482-11 and production wellbore 1482-12 from FIG. 14 are converted to injection wellbore 1542-7, injection wellbore 1542-8, injection wellbore 1542-9, injection wellbore 1542-10, injection wellbore 1542-11, and injection wellbore 1542-12, respectively. Injection wellbore 1542-7 through injection wellbore 1542-12 form one side boundary of the active storage zone 1511-2, while production wellbore 1582-7 through production wellbore 1582-12 form the opposite side boundary of the active storage zone 1511-2.

The injection range of each of the injection wellbores 1542 is located in the associated active storage zone 1511 (active storage zone 1511-1 for injection wellbore 1542-1 through injection wellbore 1542-6, and active storage zone 1511-2 for injection wellbore 1542-7 through injection wellbore 1542-12) within the subterranean rock formation 1410. Also, the production range of each of the production wellbores 1582 is located in the associated active storage zone 1511 (active storage zone 1511-1 for production wellbore 1582-1 through production wellbore 1582-6, and active storage zone 1511-2 for production wellbore 1582-7 through production wellbore 1582-12) within the subterranean rock formation 1410.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., simultaneously, sequentially) into one or more of the injection wellbores 1542, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbores 1542, and into the associated active storage zone 1511. As the pressurized fluid travels through the particular active storage zone 1511 toward the six production wellbores 1582 that define the boundary of that active storage zone 1511, the pressurized fluid converts to a transition fluid 1444 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 1444 mixes with formation fluids naturally occurring in the active storage zone 1511 within the subterranean rock formation 1410 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1511 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the six production wellbores 1582 that define the boundary of the particular active storage zone 1511. Initially, the active storage zones 1511 are completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 1444 through each of the active storage zones 1511 may be controlled via the balance of inflow rates of one or more of the six production wellbores 1582 that define the boundary of that active storage zone 1511.

If the pressurized fluid injected into the injection wellbores 1542 and out the fluid injection completion system at the injection range into the active storage zones 1511 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbores 1442 of FIG. 14, then the characteristics of the transition fluid 1444 flowing through the active storage zones 1511 and/or the characteristics of the production fluid that flows into the production wellbores 1582 may differ from the characteristics of the production fluid of FIG. 14. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zones 1511 of FIG. 15.

The mineralization process is performed within the active storage zones 1511 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zones 1511. At this point, as shown in FIG. 16, the active storage zone 1511-1 and the active storage zone 1511-2 of FIG. 15 become depleted storage zone 1613-1 and depleted storage zone 1613-2, respectively.

As a result, two new sections of virgin rock formation (two new active storage zones 1611) within the subterranean rock formation 1410 are identified and targeted for the mineralization process using example embodiments. Under the field system 1699 of FIG. 16, the 12 injection wellbores 1542 of the field system 1599 of FIG. 15 become abandoned wellbores 1662 (abandoned wellbore 1662-1, abandoned wellbore 1662-2, abandoned wellbore 1662-3, abandoned wellbore 1662-4, abandoned wellbore 1662-5, abandoned wellbore 1662-6, abandoned wellbore 1662-7, abandoned wellbore 1662-8, abandoned wellbore 1662-9, abandoned wellbore 1662-10, abandoned wellbore 1662-11, and abandoned wellbore 1662-12) since the active storage zone 1511-1 and the active storage zone 1511-2 of FIG. 15 are now designated as a depleted storage zone 1613-1 and depleted storage zone 1613-2, respectively.

In addition, with the identification of two new active storage zones 1611 (active storage zone 1611-1 and active storage zone 1611-2) that are adjacent to the depleted storage zones 1613 (depleted storage zone 1613-1 and depleted storage zone 1613-2, respectively), example embodiments are used to identify an entry point and path for a total of 12 new (added) production wellbores 1682 in two rows, where one row includes production wellbore 1682-1, production wellbore 1682-2, production wellbore 1682-3, production wellbore 1682-4, production wellbore 1682-5, and production wellbore 1682-6, and where the other row includes production wellbore 1682-7, production wellbore 1682-8, production wellbore 1682-9, production wellbore 1682-10, production wellbore 1682-11, and production wellbore 1682-12.

Once the new production wellbores 1682 are drilled, the configuration of FIG. 16 results. In the new pattern forming the new active storage zone 1611-1, production wellbore 1582-1, production wellbore 1582-2, production wellbore 1582-3, production wellbore 1582-4, production wellbore 1582-5 and production wellbore 1582-6 from FIG. 15 are converted to injection wellbore 1642-1, injection wellbore 1642-2, injection wellbore 1642-3, injection wellbore 1642-4, injection wellbore 1642-5, and injection wellbore 1642-6, respectively. Injection wellbore 1642-1 through injection wellbore 1642-6 form one side boundary of the active storage zone 1611-1, while production wellbore 1682-1 through production wellbore 1682-6 form the opposite side boundary of the active storage zone 1611-1.

Similarly, in the new pattern forming the new active storage zone 1611-2, production wellbore 1582-7, production wellbore 1582-8, production wellbore 1582-9, production wellbore 1582-10, production wellbore 1582-11 and production wellbore 1582-12 from FIG. 15 are converted to injection wellbore 1642-7, injection wellbore 1642-8, injection wellbore 1642-9, injection wellbore 1642-10, injection wellbore 1642-11, and injection wellbore 1642-12, respectively. Injection wellbore 1642-7 through injection wellbore 1642-12 form one side boundary of the active storage zone 1611-2, while production wellbore 1682-7 through production wellbore 1682-12 form the opposite side boundary of the active storage zone 1611-2.

The injection range of each of the injection wellbores 1642 is located in the associated active storage zone 1611 (active storage zone 1611-1 for injection wellbore 1642-1 through injection wellbore 1642-6, and active storage zone 1611-2 for injection wellbore 1642-7 through injection wellbore 1642-12) within the subterranean rock formation 1410. Also, the production range of each of the production wellbores 1682 is located in the associated active storage zone 1611 (active storage zone 1611-1 for production wellbore 1682-1 through production wellbore 1682-6, and active storage zone 1611-2 for production wellbore 1682-7 through production wellbore 1682-12) within the subterranean rock formation 1410.

A pressurized fluid (e.g., similar to pressurized fluid 143) (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., simultaneously, sequentially) into one or more of the injection wellbores 1642, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbores 1642, and into the associated active storage zones 1611. As the pressurized fluid travels through the particular active storage zone 1611 toward the six production wellbores 1682 that define the boundary of that active storage zone 1611, the pressurized fluid converts to a transition fluid 1444 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 1444 mixes with formation fluids naturally occurring in the active storage zone 1611 within the subterranean rock formation 1410 to form production fluid (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1611 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the six production wellbores 1682 that define the boundary of the particular active storage zone 1611. Initially, the active storage zones 1611 are completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 1444 through each of the active storage zones 1611 may be controlled via the balance of inflow rates of one or more of the six production wellbores 1682 that define the boundary of that active storage zone 1611.

If the pressurized fluid injected into the injection wellbores 1642 and out the fluid injection completion system at the injection range into the active storage zones 1611 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid used with the injection wellbores 1442 of FIG. 14 and/or the injection wells 1542 of FIG. 15, then the characteristics of the transition fluid 1444 flowing through the active storage zones 1611 and/or the characteristics of the production fluid that flows into the production wellbores 1682 may differ from the characteristics of the production fluid 1444 of FIG. 14. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zones 1611 of FIG. 16.

The mineralization process is performed within the active storage zones 1611 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zones 1611. At this point, the active storage zone 1611-1 and the active storage zone 1611-2 of FIG. 16 become depleted storage zones. In general, for a progressive field development using a semi-line-drive well pattern as set forth in FIGS. 14 through 16, as the reactive potential of each active storage zone is depleted, the entire line of associated injection wellbores is abandoned. In addition, the entire associated line of production wellbores are then converted to injector wellbores, and new rows of production wellbores are drilled (added).

FIG. 17 shows an arrangement of a field system 1799 using a well placement strategy in the form of a line-drive flow pattern according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 16, the field system 1799 of FIG. 17 includes 3 wellbores with horizontal sections that are drilled through an active storage zone 1711 within a subterranean rock formation 1710. The horizontal sections of the wellbores are used to create linear flow within the active storage zone 1711. This configuration of the wellbores within the field system 1799 may be referred to as a line-drive well pattern.

Specifically, the field system 1799 includes one injection wellbore 1742 and two production wellbores 1782 (production wellbore 1782-1 and production wellbore 1782-2). The horizontal sections of the three wellbores are arranged substantially parallel, planar, and equidistant with respect to each other within the active storage zone 1711. Injection wellbore 1742 is positioned between the production wellbore 1782-1 and the production wellbore 1782-2. The injection range of the injection wellbore 1742 corresponds to the horizontal section and is located in the active storage zone 1711 within the subterranean rock formation 1710. The production range of the production wellbore 1782-1 corresponds to the horizontal section and is located in the active storage zone 1711 within the subterranean rock formation 1710. The production range of the production wellbore 1782-2 corresponds to the horizontal section and is located in the active storage zone 1711 within the subterranean rock formation 1710. This orientation of the injection wellbore 1742 and the production wellbores 1782, combined with substantially evenly distributed fluid exit and entry along their respective horizontal completion ranges, creates a linear flow within the active storage zone 1711.

A pressurized fluid 1743 (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., simultaneously, sequentially, iteratively) into the injection wellbore 1742, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along substantially all of the horizontal section of the injection wellbore 1742, and into the active storage zone 1711. As the pressurized fluid 1743 travels through the active storage zone 1711 toward the production wellbores 1782 on either side of the injection wellbore 1742, the pressurized fluid 1743 converts to a transition fluid 1744 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid 1743 is deposited on the accessible internal surfaces of the rock.

The transition fluid 1744 mixes with formation fluids naturally occurring in the active storage zone 1711 within the subterranean rock formation 1710 to form production fluid 1783 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1711 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along substantially all of the horizontal section of one of the production wellbores 1782. Initially, the active storage zone 1711 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 1743 and the transition fluid 1744 through the active storage zone 1711 may be controlled via the balance of inflow rates of one or both of the production wellbores 1782. When the rock formation of the active storage zone 1711 has substantially homogeneous fluid permeability, and if the inflow rate of the production fluid 1783 is balanced among the production wellbores 1782 and are substantially equal in sum to the injection rate of the pressurized fluid 1743 from the injection wellbore 1742, and if fluid exit and entry is substantially evenly distributed along their respective horizontal completion ranges, the flow pattern of the transition fluid 1744 may be substantially similar to what is shown in FIG. 17.

Unbalancing the inflow rates of the production fluid 1783 into the production wellbores 1782 from the active storage zone 1711 (also sometimes referred to as the withdrawal rates of the production fluid 1783 from the active storage zone 1711 into the production wellbores 1782) may be used as necessary to shift the flow pattern within the active storage zone 1711 if the fluid permeability of the rock is not homogeneous within the active storage zone 1711. The line-drive well pattern shown in FIG. 17 is similar to that of a semi-line-drive well pattern of FIGS. 13 through 16, with the exception that fewer wellbores are required. If the pressurized fluid 1743 exiting the injector wellbore 1742 and the production fluid 1783 entering the production wellbores 1782 are evenly distributed along their associated horizontal sections (the injection range and the production ranges, respectively), purely linear fluid motion is possible in the storage formation under homogeneous permeability conditions.

Use of the line-drive well pattern may require a firm understanding of the fluid flow properties of the active storage zone 1711. By contrast, other well patterns discussed above use discreet wellbore locations, each of which may be used to influence the fluid flow pattern in the active storage zone via withdrawal and/or injection rates. The level of flexibility available with these other well patterns may not be available when using a single horizontal wellbore to replace multiple non-horizontal wellbores. Thus, reasonable certainty of the expected fluid flow pattern in the active storage zone may be required to ensure a successful outcome when using the line-drive well pattern.

FIGS. 18 through 20 show the progression of field systems using a field development strategy based on the arrangement shown in FIG. 17 according to certain example embodiments. Specifically, the field system 1899 of FIG. 18 includes a total of 3 wellbores. The field system 1999 of FIG. 19 adds 2 wellbores to the field system 1899 of FIG. 18. The field system 2099 of FIG. 20 adds 2 wellbores to the field system 1999 of FIG. 19. While this example covers 3 stages using multiple line-drive well patterns, alternative embodiments may use fewer than 3 stages or more than 3 stages.

Referring to the description above with respect to FIGS. 1 through 17, the field system 1899 of FIG. 18 shows the initial development stage of a line-drive well pattern that includes one horizontal section of an injection wellbore 1842 positioned between the horizontal section of two production wellbores 1882 (production wellbore 1882-1 and production wellbore 1882-2). The horizontal sections of all wellbores are drilled through an active storage zone 1811 within a subterranean rock formation 1810.

The injection range of the injection wellbore 1842 is located in the active storage zone 1811 within the subterranean rock formation 1810. Also, the production ranges of the production wellbores 1882 (production wellbore 1882-1 and production wellbore 1882-2) are also located in the active storage zone 1811, forming its boundary, within the subterranean rock formation 1810. The horizontal sections of the three wellbores are arranged substantially parallel, planar, and equidistant with respect to each other within the active storage zone 1811.

A pressurized fluid 1843 (e.g., in the form of a fluid mixture of water and CO₂) is injected into the injection wellbore 1842, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the horizontal section of the injection wellbore 1842, and into the active storage zone 1811. As the pressurized fluid 1843 travels through the active storage zone 1811 toward one of the production wellbores 1882, the pressurized fluid 1843 converts to a transition fluid 1844 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 1844 mixes with formation fluids naturally occurring in the active storage zone 1811 within the subterranean rock formation 1810 to form production fluid 1883 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1811 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the horizontal section of one of the production wellbores 1882. Initially, the active storage zone 1811 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 1843 and the transition fluid 1844 through the active storage zone 1811 may be controlled via the balance of inflow rates of the production wellbore 1882. When the rock formation of the active storage zone 1811 has substantially homogeneous fluid permeability, and if the inflow rate of the production fluid 1883 is substantially equal in sum to the injection rate of the pressurized fluid 1843 from the injection wellbore 1842, combined with substantially evenly distributed fluid exit and entry along their respective horizontal completion ranges, the flow pattern of the transition fluid 1844 may be substantially similar to what is shown in FIG. 18.

Unbalancing the inflow rates of the production fluid 1883 into the production wellbores 1882 from the active storage zone 1811 (also sometimes referred to as the withdrawal rates of the production fluid from the active storage zone 1811 into the production wellbores 1882) may be used as necessary to shift the flow pattern within the active storage zone 1811 if the fluid permeability of the rock is not homogeneous within the active storage zone 1811. The mineralization process is performed within the active storage zone 1811 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zone 1811.

At this point, as shown in FIG. 19, the active storage zone 1811 becomes a depleted storage zone 1913, and so two new sections of virgin rock formation (two new active storage zones 1911) within the subterranean rock formation 1810 are identified and targeted for the mineralization process using example embodiments. Under the field system 1999 of FIG. 19, the injection wellbore 1842 of the field system 1899 of FIG. 18 becomes an abandoned wellbore 1962 since the active storage zone 1811 of FIG. 18 is now designated as a depleted storage zone 1913. In addition, with the identification of two new active storage zones 1911 (active storage zone 1911-1 and active storage zone 1911-2) that are adjacent to the depleted storage zone 1913, example embodiments are used to identify an entry point and path for two new (added) production wellbores 1982 (production wellbore 1982-1 and production wellbore 1982-2).

Once the new production wellbores 1982 are drilled, the configuration of FIG. 19 results. In the new pattern forming the new active storage zone 1911-1, production wellbore 1882-1 from FIG. 18 is converted to an injection wellbore 1942-1, which forms one side boundary of the active storage zone 1911-1, while newly drilled production wellbore 1982-1 forms the opposite side boundary of the active storage zone 1911-1. Similarly, in the new pattern forming the new active storage zone 1911-2, production wellbore 1882-2 from FIG. 18 is converted to injection wellbore 1942-2, which forms one side boundary of the active storage zone 1911-2, while newly drilled production wellbore 1982-2 forms the opposite side boundary of the active storage zone 1911-2.

The injection range of each of the injection wellbores 1942 is located in the associated active storage zone 1911 (active storage zone 1911-1 for injection wellbore 1942-1, and active storage zone 1911-2 for injection wellbore 1942-2) within the subterranean rock formation 1810. Also, the production range of each of the production wellbores 1982 is located in the associated active storage zone 1911 (active storage zone 1911-1 for production wellbore 1982-1, and active storage zone 1911-2 for production wellbore 1982-2) within the subterranean rock formation 1810.

A pressurized fluid 1843 (e.g., similar to the production fluid 183) (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., simultaneously, sequentially) into one or both of the injection wellbores 1942, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbores 1942, and into the associated active storage zone 1911. As the pressurized fluid 1843 travels through the particular active storage zone 1911 toward the associated production wellbores 1982 that defines the boundary of that active storage zone 1911, the pressurized fluid 1843 converts to a transition fluid 1844 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 1844 mixes with formation fluids naturally occurring in the active storage zone 1911 within the subterranean rock formation 1810 to form production fluid 1883 (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 1911 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the associated production wellbores 1982 that defines the boundary of the particular active storage zone 1911. Initially, the active storage zones 1911 are completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 1844 through each of the active storage zones 1911 may be controlled via the balance of inflow rate of the production wellbores 1982 that defines the boundary of that active storage zone 1911.

If the pressurized fluid 1843 injected into the injection wellbores 1942 and out the fluid injection completion system at the injection range into the active storage zones 1911 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid 1843 used with the injection wellbore 1842 of FIG. 18, then the characteristics of the transition fluid 1844 flowing through the active storage zones 1911 and/or the characteristics of the production fluid that flows into the production wellbores 1982 may differ from the characteristics of the production fluid 1843 of FIG. 18. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zones 1911 of FIG. 19.

The mineralization process is performed within the active storage zones 1911 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. At this point, substantially the maximum amount of carbonate minerals has been deposited on the accessible internal surfaces of the rock within the active storage zones 1911. At this point, as shown in FIG. 20, the active storage zone 1911-1 and the active storage zone 1911-2 of FIG. 19 become depleted storage zone 2013-1 and depleted storage zone 2013-2, respectively. Under the field system 2099 of FIG. 20, the injection wellbore 1942-1 and the injection wellbore 1942-2 of the field system 1999 of FIG. 19 become an abandoned wellbore 2062-1 and an abandoned wellbore 2062-2, respectively, since the active storage zone 1911-1 and the active storage zone 1911-2 of FIG. 19 are now designated as a depleted storage zone 2013-1 and a depleted storage zone 2013-2, respectively. In addition, with the identification (using example embodiments) of two new active storage zones 2011 (active storage zone 2011-1 and active storage zone 2011-2) that are adjacent to the depleted storage zones 2013 (depleted storage zone 2013-1 and depleted storage zone 2013-2, respectively), example embodiments are used to identify an entry point and path for two new (added) production wellbores 2082 (production wellbore 2082-1 and production wellbore 2082-2).

Once the new production wellbores 2082 are drilled, the configuration of FIG. 20 results. In the new pattern forming the new active storage zone 2011-1, production wellbore 1982-1 from FIG. 19 is converted to an injection wellbore 2042-1, which forms one side boundary of the active storage zone 2011-1, while newly drilled production wellbore 2082-1 forms the opposite side boundary of the active storage zone 2011-1. Similarly, in the new pattern forming the new active storage zone 2011-2, production wellbore 1982-2 from FIG. 19 is converted to injection wellbore 2042-2, which forms one side boundary of the active storage zone 2011-2, while newly drilled production wellbore 2082-2 forms the opposite side boundary of the active storage zone 2011-2.

The injection range of each of the injection wellbores 2042 is located in the associated active storage zone 2011 (active storage zone 2011-1 for injection wellbore 2042-1, and active storage zone 2011-2 for injection wellbore 2042-2) within the subterranean rock formation 1810. Also, the production range of each of the production wellbores 2082 is located in the associated active storage zone 2011 (active storage zone 2011-1 for production wellbore 2082-1, and active storage zone 2011-2 for production wellbore 2082-2) within the subterranean rock formation 1810.

A pressurized fluid 1843 (e.g., similar to the production fluid 183) (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., simultaneously, sequentially) into one or both of the injection wellbores 2042, out the fluid injection completion system (e.g., similar to the fluid injection completion system 148) at the injection range along the injection wellbore 2042, and into the associated active storage zone 2011. As the pressurized fluid 1843 travels through the particular active storage zone 2011 toward the associated production wellbores 2082 that defines the boundary of that active storage zone 2011, the pressurized fluid 1843 converts to a transition fluid 1844 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid is deposited on the accessible internal surfaces of the rock.

The transition fluid 1844 mixes with formation fluids naturally occurring in the active storage zone 2011 within the subterranean rock formation 1810 to form production fluid 1883 (e.g., similar to the production fluid 183) (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 2011 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along the associated production wellbores 2082 that defines the boundary of the particular active storage zone 2011. Initially, the active storage zones 2011 are completely or mostly absent of deposited carbon. The movement of the pressurized fluid and the transition fluid 1844 through each of the active storage zones 2011 may be controlled via the balance of inflow rate of the production wellbores 2082 that defines the boundary of that active storage zone 2011.

If the pressurized fluid 1843 injected into the injection wellbores 2042 and out the fluid injection completion system at the injection range into the active storage zones 2011 differs (e.g., in terms of chemical make-up, in terms of temperature, in terms of pressure) from the pressurized fluid 1843 used with the injection wellbore 1842 of FIG. 18, then the characteristics of the transition fluid 1844 flowing through the active storage zones 2011 and/or the characteristics of the production fluid that flows into the production wellbores 2082 may differ from the characteristics of the production fluid 1843 of FIG. 18. The discussion above about flow patterns and distribution within the active storage zone 411 with respect to FIGS. 4A and 4B applies to the active storage zones 2011 of FIG. 20.

The mineralization process is performed within the active storage zones 2011 until the ability of the rock to react with the pressurized fluid (and more specifically the CO₂ portion of the pressurized fluid) is generally depleted. Generally, under this progressive field development using a line-drive well pattern, as the reactive potential of an active storage zone is depleted, horizontal sections of the injector wellbores are abandoned. Production wellbores are then converted to injector wellbores, where the horizontal sections are utilized. Those of ordinary skill in the art will appreciate that a number of other well patterns may be utilized in certain example embodiments. In addition, or in the alternative, multiple well patterns may be used as part of the same field operation within one or more active storage zones within a subterranean formation.

FIG. 21 shows an arrangement of a field system 2199 using another well placement strategy according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 20, the field system 2199 of FIG. 21 includes 7 wellbores drilled through an active storage zone 2111 within a subterranean rock formation 2110. Within the active storage zone 2111, each of the six production wellbores 2182 are substantially vertical wellbores (or at least non-horizontal wellbores). The lone injection wellbore 2142 is (at least within the active storage zone 2111) a horizontal wellbore, which may sometimes be referred to as a horizontal point-source injector.

Specifically, the six production wellbores 2182 are arranged symmetrically in a plane with respect to the injection wellbore 2142, with three production wellbores 2182 (production wellbore 2182-1, production wellbore 2182-2, and production wellbore 2182-3) positioned equidistantly with respect to each other in a line parallel to and on one side of the injection wellbore 2142, and with the other three production wellbores 2182 (production wellbore 2182-4, production wellbore 2182-5, and production wellbore 2182-6) positioned equidistantly with respect to each other in a line parallel to and on the opposite side of the injection wellbore 2142.

In some cases, a line or plane formed by production wellbore 2182-1, FICS 2148-1, and production wellbore 2182-4 within the active storage zone 2111 may be substantially parallel with a line or plane formed by production wellbore 2182-2, FICS 2148-2, and production wellbore 2182-5 within the active storage zone 2111, which may be substantially parallel with a line or plane formed by production wellbore 2182-3, FICS 2148-3, and production wellbore 2182-6 within the active storage zone 2111. In some cases, the distances between such lines or planes may be substantially the same.

The injection range of the injection wellbore 2142 is located in the active storage zone 2111 within the subterranean rock formation 2110. Specifically, the injection range of the injection wellbore 2142 is divided into three substantially equidistant segments by three FICSs 2148 (e.g., similar to the FICSs 148 discussed above). FICS 2148-1 is positioned substantially halfway between and in line with the production ranges of production wellbore 2182-1 and production wellbore 2182-4 in the active storage zone 2111. FICS 2148-2 is positioned substantially halfway between and in line with the production ranges of production wellbore 2182-2 and production wellbore 2182-5 in the active storage zone 2111. FICS 2148-3 is positioned substantially halfway between and in line with the production ranges of production wellbore 2182-3 and production wellbore 2182-6 in the active storage zone 2111.

A pressurized fluid 2143 (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., constantly, iteratively) into the injection wellbore 2142, out the fluid injection completion systems 2148 along the injection range of the injection wellbore 2142, and into the active storage zone 2111. As the pressurized fluid 2143 travels through the active storage zone 2111 toward one of the production wellbores 2182, the pressurized fluid 2143 converts to a transition fluid 2144 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid 2143 is deposited on the accessible internal surfaces of the rock.

The transition fluid 2144 mixes with formation fluids naturally occurring in the active storage zone 2111 within the subterranean rock formation 2110 to form production fluid 2183 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 2111 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the production wellbores 2182. Initially, the active storage zone 2111 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 2143 and the transition fluid 2144 through the active storage zone 2111 may be controlled via the balance of inflow rates of one or more of the production wellbores 2182 and/or via the FICSs 2148. When the rock formation of the active storage zone 2111 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid 2183 are balanced among the production wellbores 2182 and are substantially equal in sum to the injection rates of the pressurized fluid 2143 from the injection wellbores 2142, where the injection rates are substantially evenly distributed using the FICSs 2148, the flow pattern of the transition fluid 2144 may be substantially similar to what is shown in FIG. 21.

Unbalancing the inflow rates of the production fluid 2183 into the production wellbores 2182 from the active storage zone 2111 (also sometimes referred to as the withdrawal rates of the production fluid 2183 from the active storage zone 2111 into the production wellbores 2182) may be used as necessary to shift the flow pattern within the active storage zone 2111 if the fluid permeability of the rock is not homogeneous within the active storage zone 2111. The type of well pattern shown in FIG. 21 utilizes a horizontal injection wellbore 2142 to create a series of injection point-sources to replace the use of multiple non-horizontal line-source injection wellbores. An example configuration of the horizontal injection wellbore 2142 of FIG. 21 is shown in FIG. 22.

FIG. 22 shows a sectional view of a subsystem 2298 that includes part of the injection wellbore 2142 that may be used with the field system 2199 of FIG. 21 according to certain example embodiments. Referring to description above with respect to FIGS. 1 through 21, the injection range along the distal end of the injection wellbore 2142 of FIG. 22 includes three FICSs 2148 that are integrated with the distal end of the tubing string 2249 inserted into the injection wellbore 2142. The three FICSs 2148 are segmented from each other within the injection wellbore 2142. This arrangement may sometimes be referred to as a segmented horizontal point-source injection completion. In this case, there is a casing string 2266 inserted into the horizontal section of the injection wellbore 2142. The casing string 2266 includes a number of casing pipes that are coupled to each other in an end-to-end fashion. The inner diameter of the casing string 2266 is larger than the outer diameter of the tubing string 2249, forming an annulus 2267 therebetween. The tubing string 2249 includes a number of tubing pipes that are coupled to each other in an end-to-end fashion. The casing string 2266 is adhered to the wall of the wellbore 2142 using cement 2262.

In addition to the tubing pipes, the tubing string 2249 may include one or more of a number (in this example, three) of subs that include an FICS 2148. The sub that includes FICS 2148-1 is positioned adjacent to the perforated, and possibly fractured, injection zone 2261-1, which allows the pressurized fluid 2143 to flow therethrough to penetrate part of the casing string 2266, part of the cement 2262, and part of the active storage zone 2111. The sub that includes FICS 2148-2 is positioned adjacent to the perforated, and possibly fractured, injection zone 2261-2, which allows the pressurized fluid 2143 to flow therethrough to penetrate part of the casing string 2266, part of the cement 2262, and part of the active storage zone 2111. The sub that includes FICS 2148-3 is positioned adjacent to the perforated, and possibly fractured, injection zone 2261-3, which allows the pressurized fluid 2143 to flow therethrough to penetrate part of the casing string 2266, part of the cement 2262, and part of the active storage zone 2111.

Each of the subs that include a FICS 2148 may be totally or partially isolated from each other within the annulus 2267 by inserting one or more packers 2263 into the annulus 2267, where each packer 2263 creates a total or partial seal between the inner perimeter of the casing string 2266 and the outer perimeter of the tubing string 2249. In this case, there are three packers 2263 in the portion of the field system shown in FIG. 22. Packer 2263-1 is located upstream of FICS 2148-1. Packer 2263-2 is located between FICS 2148-1 and FICS 2148-2. Packer 2263-3 is located between FICS 2148-2 and FICS 2148-3. Packer 2263-1 and packer 2263-2 create an isolation zone 2264-1 within the annulus 2267, where the isolation zone 2264-1 includes FICS 2148-1. Packer 2263-2 and packer 2263-3 create an isolation zone 2264-2 within the annulus 2267, where the isolation zone 2264-2 includes FICS 2148-2. Packer 2263-3 and the end of the wellbore 2142 create an isolation zone 2264-3 within the annulus 2267, where the isolation zone 2264-3 includes FICS 2148-3.

In certain example embodiments, each FICS 2148 is configured to operate (e.g., reduce the amount of pressurized fluid 2143 that flows into the annulus 2267 (and so into the active storage zone 2111 through the proximate perforated, and possibly fractured, injection zone 2261) when a pressure differential (e.g., a difference between the pressure in the tubing string 2249 within the FICS 2148 and the pressure in the annulus 2267 outside the FICS 2148) reaches a minimal threshold value. By using the packers 2263, the pressure in the annulus 2267 within one isolation zone 2264 may differ from the pressure in the annulus 2267 within one or more of the other isolation zones 2264. As a result, each FICS 2148 in one isolation zone 2264 may perform independently of the FICSs 2148 in another isolation zone 2264. This operational independence of each FICS 2148 may depend, at least in part, on the ability of one or more of the packers 2263 to prevent fluidic communication therethrough within the annulus 2267.

When there are multiple FICSs 2148 in the tubing string 2249, the configuration aspects (e.g., type of actuator, calibration of the actuator, material, length, inner diameter, types of coupling features) of one FICS 2148 may be the same as, or different than, one or more of the corresponding configuration aspects of one or more of the other FICS 2148. The tubing string 2249 may include any number (e.g., one, three, seven, 15, 100) of FICSs 2148. An isolation zone 2264 may include any number (e.g., one, two, five, 10, 21) of FICSs 2148. The use of FICS 2148 in each isolation zone 2264 allows for the substantially even distribution of the pressurized fluid 2143 being injected among the isolation zones 2264 into the active storage zone 2111. Using this embodiment, the horizontal injection wellbore 2142 contains equipment (e.g., the FICSs 2148) that allows the pressurized fluid 2143 to be distributed as desired amongst selected sites in the active storage zone 2111. This equipment may collectively, and in general, be referred to as the “completion”.

FIG. 23 shows an arrangement of a field system 2399 using yet another well placement strategy according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 22, the field system 2399 of FIG. 23 includes 3 wellbores. The two production wellbores 2382 are drilled so that at least within the portion within the active storage zone 2311 within a subterranean rock formation 2310 are substantially horizontal. The lone injection wellbore 2342 is (at least within the active storage zone 2311) also a substantially horizontal wellbore. In this case, the two production wellbores 2382 (production wellbore 2382-1 and production wellbore 2382-2) are arranged substantially in parallel with each other within the active storage zone 2311. Further, the injection wellbore 2342 is also substantially parallel to and planar with the two production wellbores 2382 within the active storage zone 2311. Also, the injection wellbore 2342 is positioned substantially halfway between the two production wellbores 2382 within the active storage zone 2311.

The injection range of the injection wellbore 2342, the production range of the production wellbore 2382-1, and the production range of the production wellbore 2382-2 are located in the active storage zone 2311 within the subterranean rock formation 2310. Specifically, the injection range of the injection wellbore 2342 is divided into three substantially equidistant segments by three FICSs 2348 (e.g., similar to the FICSs 148 discussed above). Similarly, the production range of the production wellbore 2382-1 is divided into three substantially equidistant segments by three FPCSs 2388-1 (e.g., similar to the FPCSs 188 discussed above), and the production range of the production wellbore 2382-2 is divided into three substantially equidistant segments by three FPCSs 2388-2.

The FICS 2348-1 is positioned substantially halfway between and planar with the FPCS 2388-1-1 of production wellbore 2382-1 and the FPCS 2388-2-1 of production wellbore 2382-2 in the active storage zone 2311. The FICS 2348-2 is positioned substantially halfway between and planar with the FPCS 2388-1-2 of production wellbore 2382-1 and the FPCS 2388-2-2 of production wellbore 2382-2 in the active storage zone 2311. The FICS 2348-3 is positioned substantially halfway between and planar with the FPCS 2388-1-3 of production wellbore 2382-1 and the FPCS 2388-2-3 of production wellbore 2382-2 in the active storage zone 2311. In some cases, a line or plane formed by FPCS 2388-1-1, FICS 2348-1, and FPCS 2388-2-1 within the active storage zone 2311 may be substantially parallel with a line or plane formed by FPCS 2388-1-2, FICS 2348-2, and FPCS 2388-2-2 within the active storage zone 2311, which may be substantially parallel with a line or plane formed by FPCS 2388-1-3, FICS 2348-3, and FPCS 2388-2-3 within the active storage zone 2311. In some cases, the distances between such lines or planes may be substantially the same.

A pressurized fluid 2343 (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., constantly, iteratively) into the injection wellbore 2342, out the fluid injection completion systems 2348 along the injection range of the injection wellbore 2342, and into the active storage zone 2311. As the pressurized fluid 2343 travels through the active storage zone 2311 toward one of the production wellbores 2382, the pressurized fluid 2343 converts to a transition fluid 2344 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid 2343 is deposited on the accessible internal surfaces of the rock.

The transition fluid 2344 mixes with formation fluids naturally occurring in the active storage zone 2311 within the subterranean rock formation 2310 to form production fluid 2383 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 2311 and enters the fluid production completion systems 2388 at the production range along the production wellbores 2382. Initially, the active storage zone 2311 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 2343 and the transition fluid 2344 through the active storage zone 2311 may be controlled via the balance of inflow rates of one or more of the production wellbores 2382 (e.g., via the FPCSs 2388) and/or via the FICSs 2348. When the rock formation of the active storage zone 2311 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid 2383 are balanced among the production wellbores 2382 and are substantially equal in sum to the injection rates of the pressurized fluid 2343 from the injection wellbores 2342, where the injection rates and the production rates are substantially evenly distributed using the FICSs 2348 and FPCSs 2388, respectively, the flow pattern of the transition fluid 2344 may be substantially similar to what is shown in FIG. 23.

Unbalancing the inflow rates of the production fluid 2383 into the production wellbores 2382 from the active storage zone 2311 (also sometimes referred to as the withdrawal rates of the production fluid 2383 from the active storage zone 2311 into the production wellbores 2382) may be used as necessary to shift the flow pattern within the active storage zone 2311 if the fluid permeability of the rock is not homogeneous within the active storage zone 2311. In this configuration, each horizontal production wellbore 2382 may be used to create a series of point-sinks to replace the use of multiple non-horizontal line-sink production wellbores, as in FIG. 21 above. An example configuration of one of the horizontal production wellbores 2382 of FIG. 23 is shown in FIG. 24.

FIG. 24 shows a sectional view of part of a subsystem 2498 that includes a production wellbore 2382 that may be used with the field system 2399 of FIG. 23 according to certain example embodiments. Referring to description above with respect to FIGS. 1 through 23, the production range along the distal end of one of the production wellbores 2382 (e.g., production wellbore 2382-1) of FIG. 24 includes three FPCSs 2388 that are integrated with the distal end of the tubing string 2449 (e.g., similar to the tubing string 249 discussed above) inserted into the production wellbore 2382. The three FPCSs 2388 are segmented from each other within the production wellbores 2382. This arrangement may sometimes be referred to as a segmented horizontal point-sink production completion. In this case, there is a casing string 2466 inserted into the horizontal section of the production wellbores 2382. The casing string 2466 includes a number of casing pipes that are coupled to each other in an end-to-end fashion. The inner diameter of the casing string 2466 is larger than the outer diameter of the tubing string 2449, forming an annulus 2467 therebetween. The tubing string 2449 includes a number of tubing pipes that are coupled to each other in an end-to-end fashion. The casing string 2466 is adhered to the wall of the wellbore 2342 using cement 2462.

In addition to the tubing pipes, the tubing string 2449 may include one or more of a number (in this example, three) of subs that include an FPCS 2388. The sub that includes FPCS 2388-1 is positioned adjacent to the perforated, and possibly fractured, production zone 2461-1, which allows the inflow of production fluid 2383 therethrough from part of the active storage zone 2311, through part of the cement 2462, and through part of the casing string 2466. The sub that includes the FPCS 2388-2 is positioned adjacent to the perforated, and possibly fractured, production zone 2461-2, which allows the inflow of production fluid 2383 therethrough from part of the active storage zone 2311, through part of the cement 2462, and through part of the casing string 2466. The sub that includes the FPCS 2388-3 is positioned adjacent to the perforated, and possibly fractured, production zone 2461-3, which allows the inflow of production fluid 2383 therethrough from part of the active storage zone 2311, through part of the cement 2462, and through part of the casing string 2466.

Each of the subs that include a FPCS 2388 may be totally or partially isolated from each other within the annulus 2467 by inserting one or more packers 2463 into the annulus 2467, where each packer 2463 creates a total or partial seal between the inner perimeter of the casing string 2466 and the outer perimeter of the tubing string 2449. In this case, there are three packers 2463 in the portion of the field system shown in FIG. 24. Packer 2463-1 is located upstream of the FPCS 2388-1. Packer 2463-2 is located between the FPCS 2388-1 and the FPCS 2388-2. Packer 2463-3 is located between the FPCS 2388-2 and the FPCS 2388-3. Packer 2463-1 and packer 2463-2 create an isolation zone 2464-1 within the annulus 2467, where the isolation zone 2464-1 includes the FPCS 2388-1. Packer 2463-2 and packer 2463-3 create an isolation zone 2464-2 within the annulus 2467, where the isolation zone 2464-2 includes the FPCS 2388-2. Packer 2463-3 and the end of the wellbore 2342 create an isolation zone 2464-3 within the annulus 2467, where the isolation zone 2464-3 includes the FPCS 2388-3.

In certain example embodiments, each FPCS 2388 is configured to operate (e.g., reduce the amount of production fluid 2383 that flows in from the active storage zone 2311 (and so in from the proximate perforated, and possibly fractured, injection zone 2461 to the annulus 2467) when a pressure differential (e.g., a difference between the pressure in the tubing string 2449 within the FPCS 2388 and the pressure in the annulus 2467 outside the FPCS 2388) reaches a minimal threshold value. By using the packers 2463, the pressure in the annulus 2467 within one isolation zone 2464 may differ from the pressure in the annulus 2467 within one or more of the other isolation zones 2464. As a result, each FPCS 2388 in one isolation zone 2464 may perform independently of the FPCSs 2388 in another isolation zone 2464. This operational independence of each FPCS 2388 may depend, at least in part, on the ability of one or more of the packers 2463 to prevent fluidic communication therethrough within the annulus 2467.

When there are multiple FPCSs 2388 in the tubing string 2449, the configuration aspects (e.g., type of actuator, calibration of the actuator, material, length, inner diameter, types of coupling features) of one FPCS 2388 may be the same as, or different than, one or more of the corresponding configuration aspects of one or more of the other FPCS 2388. The tubing string 2449 may include any number (e.g., one, three, seven, 15, 100) of FPCSs 2388. An isolation zone 2464 may include any number (e.g., one, two, five, 10, 23) of FPCSs 2388. The use of FPCS 2388 in each isolation zone 2464 allows for the substantially even distribution of the production fluid 2383 flowing into the isolation zones 2464 from the active storage zone 2311. Using this embodiment, the horizontal production wellbores 2382 contains equipment (e.g., the FPCSs 2388) that allows the production fluid 2383 to be received in a distributed manner from among selected sites in the active storage zone 2311. This completion is similar to that in FIG. 22 with the exception that pressurized fluid outflow devices (FICSs) in FIG. 22 are replaced by production fluid inflow devices (FPCSs). The inflow and outflow devices can be of similar or different designs, depending on differences in factors that may include, but are not limited to, the wellbores, the subterranean rock formation, and fluid characteristics.

FIG. 25 shows an arrangement of a field system 2599 using still another well placement strategy according to certain example embodiments. Specifically, the field system 2599 of FIG. 25 shows a horizontal line-source water/CO₂ injector and non-horizontal line-sink water producers. Referring to the description above with respect to FIGS. 1 through 24, the field system 2599 of FIG. 25 includes 7 wellbores drilled through an active storage zone 2511 within a subterranean rock formation 2510. Within the active storage zone 2511, each of the six production wellbores 2582 are substantially vertical wellbores (or at least non-horizontal wellbores). The lone injection wellbore 2542 is (at least within the active storage zone 2511) a horizontal wellbore.

The six production wellbores 2582 are arranged symmetrically in a plane with respect to the injection wellbore 2542, with three production wellbores 2582 (production wellbore 2582-1, production wellbore 2582-2, and production wellbore 2582-3) positioned equidistantly with respect to each other in a line parallel to and on one side of the injection wellbore 2542, and with the other three production wellbores 2582 (production wellbore 2582-4, production wellbore 2582-5, and production wellbore 2582-6) positioned equidistantly with respect to each other in a line parallel to and on the opposite side of the injection wellbore 2542.

The injection range of the injection wellbore 2542 is located in the active storage zone 2511 within the subterranean rock formation 2510. Specifically, the injection range of the injection wellbore 2542 is substantially uniform along the horizontal section of the injection wellbore 2542 using one or more (e.g., three) FICSs (e.g., similar to the FICSs 148 discussed above). Examples showing the FICSs are provided below with respect to FIGS. 26 and 27. A pressurized fluid 2543 (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., constantly, iteratively) into the injection wellbore 2542, out the FICSs (e.g., similar to the FICSs 148 discussed above) along the injection range of the injection wellbore 2542, and into the active storage zone 2511. As the pressurized fluid 2543 travels through the active storage zone 2511 toward one of the production wellbores 2582, the pressurized fluid 2543 converts to a transition fluid 2544 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid 2543 is deposited on the accessible internal surfaces of the rock.

The transition fluid 2544 mixes with formation fluids naturally occurring in the active storage zone 2511 within the subterranean rock formation 2510 to form production fluid 2583 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 2511 and enters the fluid production completion system (e.g., similar to the fluid production completion system 188) at the production range along one of the production wellbores 2582. Initially, the active storage zone 2511 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 2543 and the transition fluid 2544 through the active storage zone 2511 may be controlled via the balance of inflow rates of one or more of the production wellbores 2582 and/or via the FICSs. When the rock formation of the active storage zone 2511 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid 2583 are balanced among the production wellbores 2582 and are substantially equal in sum to the injection rates of the pressurized fluid 2543 from the injection wellbores 2542, where the injection rates are substantially evenly distributed using the FICSs 2548, the flow pattern of the transition fluid 2544 may be substantially similar to what is shown in FIG. 25. FIGS. 26 and 27 below show examples of injection wellbores that may be used with the field system 2599 of FIG. 25.

Unbalancing the inflow rates of the production fluid 2583 into the production wellbores 2582 from the active storage zone 2511 (also sometimes referred to as the withdrawal rates of the production fluid 2583 from the active storage zone 2511 into the production wellbores 2582) may be used as necessary to shift the flow pattern within the active storage zone 2511 if the fluid permeability of the rock is not homogeneous within the active storage zone 2511. The type of well pattern shown in FIG. 25 utilizes a horizontal injection wellbore 2542 that may be used to create a series of horizontal injection line-sources to replace the use of multiple non-horizontal line-source injection wellbores. As discussed above, example configurations of the horizontal injection wellbore 2542 of FIG. 25 are shown in FIGS. 26 and 27.

FIGS. 26 and 27 show sectional views of part of subsystems that include injection wellbores that may be used with the field system 2599 of FIG. 25 according to certain example embodiments. Specifically, FIG. 26 shows a sectional view of part of a subsystem 2698 that includes an injection wellbore 2642 that may be used with the field system 2599 of FIG. 25 according to certain example embodiments. FIG. 27 shows a sectional view of part of a subsystem 2798 that includes another injection wellbore 2742 that may be used with the field system 2599 of FIG. 25 according to certain example embodiments.

Referring to description above with respect to FIGS. 1 through 25, the injection range along the distal end of the injection wellbore 2642 of FIG. 26 includes three FICSs 2648 that are integrated with the distal end of the tubing string 2649 inserted into the injection wellbore 2642. The three FICSs 2648 are segmented from each other within the injection wellbore 2642. This arrangement may sometimes be referred to as a cased-hole segmented horizontal line-source injection completion. In this case, there is a casing string 2666 inserted into the horizontal section of the injection wellbore 2642. The casing string 2666 includes a number of casing pipes that are coupled to each other in an end-to-end fashion. The inner diameter of the casing string 2666 is larger than the outer diameter of the tubing string 2649, forming an annulus 2667 therebetween. The tubing string 2649 includes a number of tubing pipes that are coupled to each other in an end-to-end fashion. The casing string 2666 is adhered to the wall of the wellbore 2642 using cement 2662.

In addition to the tubing pipes, the tubing string 2649 may include one or more of a number (in this example, three) of subs that include an FICS 2648. The sub that includes FICS 2648-1 is positioned adjacent to the perforated (and possibly fractured) and substantially uniformly distributed injection zone 2661-1, which allows the pressurized fluid 2643 to flow therethrough to penetrate part of the casing string 2666, part of the cement 2662, and part of the active storage zone 2611. The sub that includes FICS 2648-2 is positioned adjacent to the perforated (and possibly fractured) and substantially uniformly distributed injection zone 2661-2, which allows the pressurized fluid 2643 to flow therethrough to penetrate part of the casing string 2666, part of the cement 2662, and part of the active storage zone 2611. The sub that includes FICS 2648-3 is positioned adjacent to the perforated (and possibly fractured) and substantially uniformly distributed injection zone 2661-3, which allows the pressurized fluid 2643 to flow therethrough to penetrate part of the casing string 2666, part of the cement 2662, and part of the active storage zone 2611.

Each of the subs that include a FICS 2648 may be totally or partially isolated from each other within the annulus 2667 by inserting one or more packers 2663 into the annulus 2667, where each packer 2663 creates a total or partial seal between the inner perimeter of the casing string 2666 and the outer perimeter of the tubing string 2649. In this case, there are three packers 2663 in the portion of the field system shown in FIG. 26. Packer 2663-1 is located upstream of FICS 2648-1. Packer 2663-2 is located between FICS 2648-1 and FICS 2648-2. Packer 2663-3 is located between FICS 2648-2 and FICS 2648-3. Packer 2663-1 and packer 2663-2 create an isolation zone 2664-1 within the annulus 2667, where the isolation zone 2664-1 includes FICS 2648-1. Packer 2663-2 and packer 2663-3 create an isolation zone 2664-2 within the annulus 2667, where the isolation zone 2664-2 includes FICS 2648-2. Packer 2663-3 and the end of the wellbore 2642 create an isolation zone 2664-3 within the annulus 2667, where the isolation zone 2664-3 includes FICS 2648-3.

In certain example embodiments, each FICS 2648 is configured to operate (e.g., reduce the amount of pressurized fluid 2643 that flows into the annulus 2667 (and so into the active storage zone 2611 through the proximate perforated, and possibly fractured, injection zone 2661) when a pressure differential (e.g., a difference between the pressure in the tubing string 2649 within the FICS 2648 and the pressure in the annulus 2667 outside the FICS 2648) reaches a minimal threshold value. By using the packers 2663, the pressure in the annulus 2667 within one isolation zone 2664 may differ from the pressure in the annulus 2667 within one or more of the other isolation zones 2664. As a result, each FICS 2648 in one isolation zone 2664 may perform independently of the FICSs 2648 in another isolation zone 2664. This operational independence of each FICS 2648 may depend, at least in part, on the ability of one or more of the packers 2663 to prevent fluidic communication therethrough within the annulus 2667.

When there are multiple FICSs 2648 in the tubing string 2649, the configuration aspects (e.g., type of actuator, calibration of the actuator, material, length, inner diameter, types of coupling features) of one FICS 2648 may be the same as, or different than, one or more of the corresponding configuration aspects of one or more of the other FICS 2648. The tubing string 2649 may include any number (e.g., one, three, seven, 15, 100) of FICSs 2648. An isolation zone 2664 may include any number (e.g., one, two, five, 10, 26) of FICSs 2648. The use of FICS 2648 in each isolation zone 2664 allows for the substantially even distribution of the pressurized fluid 2643 being injected among the isolation zones 2664 into the active storage zone 2611.

Using this embodiment, the horizontal injection wellbore 2642 contains equipment (e.g., the FICSs 2648) that allows the pressurized fluid 2643 to be distributed as desired amongst selected sites in the active storage zone 2611. This example is similar to what is shown in FIG. 22, except that in this case fluid injection points (via perforations) are more numerous and widely distributed along the injection wellbore 2642 to, in effect, replicate a line-source at reservoir scale. As in earlier completion embodiments, fluid out-flow control devices (e.g., FICSs 2648) are used to distribute pressurized fluid 2643 to various sections of the active storage zone 2611 as desired. Put another way, the fluid injection completion system 2648 includes an injection wellbore cased-hole completion interval that is configured to allow the pressurized fluid 2643 to be injected into permeable sections of the active storage zone 2611 within the subterranean rock formation along the injection wellbore 2642.

With respect to the subsystem 2798 of FIG. 27, the configuration creates a theoretically true horizontal line-source via the elimination of casing and perforations. The three FICSs 2748 are segmented from each other within the injection wellbore 2742. This arrangement may sometimes be referred to as an open-hole segmented horizontal line-source injection completion. In this embodiment, pressurized fluid 2743 may enter the active storage zone 2711 at any point along the injection wellbore 2742. However, as with the embodiment of FIG. 26, packers 2763 and fluid out-flow control devices (e.g., FICSs 2748) are still used to distribute the pressurized fluid 2743 to various sections of the active storage zone 2711 as desired.

The subsystem 2798 of FIG. 27 includes an open (e.g., not cased) horizontal section of an injection wellbore 2742 drilled into an active storage zone 2711. In alternative embodiments, the open section of the wellbore 2742 may be at any angle ranging from vertical to horizontal. In this case, there is no casing string inserted into the wellbore 2742. Hydraulically-induced fracture zones may or may not exist in the active storage zone 2711. The tubing string 2749 includes a number of tubing pipes that are coupled to each other in an end-to-end fashion.

Each of the subs integrated with the tubing string 2749 that include a FICS 2748 may be totally or partially isolated from each other within the annulus 2767 (which in this case is defined as the space between the tubing string 2749 and the wall 2766 of the wellbore 2742) by inserting one or more packers 2763 into the non-cased injection wellbore 2742, where each packer 2763 creates a total or partial seal between the wall 2766 of the wellbore 2742 and the outer perimeter of the tubing string 2749. In this case, there are three packers 2763 in the portion of the subsystem 2798 shown in FIG. 27. Packer 2763-1 is located upstream of FICS 2748-1. Packer 2763-2 is located between FICS 2748-1 and FICS 2748-2. Packer 2763-3 is located between FICS 2748-2 and FICS 2748-3. Packer 2763-1 and packer 2763-2 create an isolation zone 2764-1 within the annulus 2767, where the isolation zone 2764-1 includes FICS 2748-1. Packer 2763-2 and packer 2763-3 create an isolation zone 2764-2 within the annulus 2767, where the isolation zone 2764-2 includes FICS 2748-2. Packer 2763-3 and the end of the wellbore 2742 create an isolation zone 2764-3 within the annulus 2767, where the isolation zone 2764-3 includes FICS 2748-3.

In certain example embodiments, each FICS 2748 is configured to operate (e.g., reduce the amount of pressurized fluid 2743 that flows from its cavity into the annulus 2767 (and so into the active storage zone 2711)) when a pressure differential (e.g., a difference between the pressure in the cavity within the FICS 2748 and the pressure in the annulus 2767 outside the FICS 2748) reaches a minimal threshold value. By using the packers 2763, the pressure in the annulus 2767 within one isolation zone 2764 may differ from the pressure in the annulus 2767 within one or more of the other isolation zones 2764. As a result, each FICS 2748 (or otherwise a specific number of FICSs 2748 as a group or subset) in one isolation zone 2764 may perform independently of the FICSs 2748 in another isolation zone 2764. This operational independence of each FICS 2748 may depend, at least in part, on the ability of one or more of the packers 2763 to prevent fluidic communication therethrough within the annulus 2767. The use of FICSs 2748 in each isolation zone 2764 allows for the substantially even distribution of injected pressurized fluid 2743 among the isolation zones 2764.

Put another way, this configuration may be applied to injection wellbores 2742 so that the open-hole completion interval of the injection wellbore 2742 is configured to allow the pressurized fluid 2743 to be injected into permeable sections of the active storage zone 2711 within the subterranean rock formation along the injection wellbore 2742. In certain example embodiments, a combination of open-hole and cased-hole scenarios may exist in a wellbore (e.g., injection wellbore 2742, production wellbores 2382). In such cases, for an injection wellbore, the fluid injection completion system may include an injection wellbore internal completion assembly that is configured to allow the pressurized fluid to be injected into permeable sections of the active storage zone within the subterranean rock formation via open-hole and cased-hole completion intervals along the injection wellbore.

FIG. 28 shows an arrangement of a field system 2899 using yet another well placement strategy according to certain example embodiments. Referring to the description above with respect to FIGS. 1 through 27, the field system 2899 of FIG. 28 includes 3 wellbores. The two production wellbores 2882 are drilled so that at least within the portion within the active storage zone 2811 within a subterranean rock formation 2810 are substantially horizontal. The lone injection wellbore 2842 is (at least within the active storage zone 2811) also a substantially horizontal wellbore. In this case, the two production wellbores 2882 (production wellbore 2882-1 and production wellbore 2882-2) are arranged substantially in parallel with each other within the active storage zone 2811. Further, the injection wellbore 2842 is also substantially parallel to and planar with the two production wellbores 2882 within the active storage zone 2811. Also, the injection wellbore 2842 is positioned substantially halfway between the two production wellbores 2882 within the active storage zone 2811.

The injection range of the injection wellbore 2842, the production range of the production wellbore 2882-1, and the production range of the production wellbore 2882-2 are located in the active storage zone 2811 within the subterranean rock formation 2810. Specifically, the injection range of the injection wellbore 2842 is divided into three substantially equidistant segments by three FICSs 2848 (e.g., similar to the FICSs 148 discussed above). Similarly, the production range of the production wellbore 2882-1 may be divided into a number (e.g., three) of substantially equidistant segments using one or more FPCSs (e.g., similar to the FPCSs 188 discussed above), and the production range of the production wellbore 2882-2 may be divided into a number (e.g., three) of substantially equidistant segments using one or more FPCSs.

The FICS 2848-1 is positioned substantially halfway between and planar with the proximal section of the production wellbore 2882-1 and the proximal section of the production wellbore 2882-2 in the active storage zone 2811. The FICS 2848-2 is positioned substantially halfway between and planar with the middle section of the production wellbore 2882-1 and the middle section of the production wellbore 2882-2 in the active storage zone 2811. The FICS 2848-3 is positioned substantially halfway between and planar with the distal section of the production wellbore 2882-1 and the distal section of the production wellbore 2882-2 in the active storage zone 2811.

A pressurized fluid 2843 (e.g., in the form of a fluid mixture of water and CO₂) is injected (e.g., constantly, iteratively) into the injection wellbore 2842, out the FICSs 2848 along the injection range of the injection wellbore 2842, and into the active storage zone 2811. As the pressurized fluid 2843 travels through the active storage zone 2811 toward one of the production wellbores 2882, the pressurized fluid 2843 converts to a transition fluid 2844 as carbon from the CO₂ (as well as other forms of carbonate minerals) of the pressurized fluid 2843 is deposited on the accessible internal surfaces of the rock.

The transition fluid 2844 mixes with formation fluids naturally occurring in the active storage zone 2811 within the subterranean rock formation 2810 to form production fluid 2883 (e.g., CO₂-depleted water, water that has only small amounts of CO₂) that exits the active storage zone 2811 and enters the FPCSs (e.g., similar to the FPCSs 188 above) at the production range along the production wellbores 2882. Initially, the active storage zone 2811 is completely or mostly absent of deposited carbon. The movement of the pressurized fluid 2843 and the transition fluid 2844 through the active storage zone 2811 may be controlled via the balance of inflow rates of one or more of the production wellbores 2882 (e.g., via the FPCSs) and/or via the FICSs (e.g., similar to the FICSs 148 discussed above). When the rock formation of the active storage zone 2811 has substantially homogeneous fluid permeability, and if the inflow rates of the production fluid 2883 are balanced among the production wellbores 2882 and are substantially equal in sum to the injection rates of the pressurized fluid 2843 from the injection wellbores 2842, where the injection and production rates are substantially evenly distributed using the FICSs 2842 and the FPCSs 2882, the flow pattern of the transition fluid 2844 may be substantially similar to what is shown in FIG. 28. FIGS. 29 and 30 below show examples of production wellbores that may be used with the field system 2899 of FIG. 28.

Unbalancing the inflow rates of the production fluid 2883 into the production wellbores 2882 from the active storage zone 2811 (also sometimes referred to as the withdrawal rates of the production fluid 2883 from the active storage zone 2811 into the production wellbores 2882) may be used as necessary to shift the flow pattern within the active storage zone 2811 if the fluid permeability of the rock is not homogeneous within the active storage zone 2811. In this configuration, each horizontal production wellbore 2882 may be used to create a horizontal point-source water/CO₂ injector and horizontal line-sink water producers. An example configuration of one of the horizontal production wellbores 2882 of FIG. 28 is shown in FIG. 29.

FIG. 29 shows a sectional view of part of a subsystem 2998 that includes a production wellbore 2982 that may be used with the field system 2899 of FIG. 28 according to certain example embodiments. Referring to description above with respect to FIGS. 1 through 28, the injection range along the distal end of the production wellbore 2982 of FIG. 29 includes three FPCSs 2988 that are integrated with the distal end of the tubing string 2949 inserted into the production wellbore 2982. The three FPCSs 2988 are segmented from each other within the production wellbore 2942. This arrangement may sometimes be referred to as a cased-hole segmented horizontal line-sink production completion. In this case, there is a casing string 2966 inserted into the horizontal section of the production wellbore 2982. The casing string 2966 includes a number of casing pipes that are coupled to each other in an end-to-end fashion. The inner diameter of the casing string 2966 is larger than the outer diameter of the tubing string 2949, forming an annulus 2967 therebetween. The tubing string 2949 includes a number of tubing pipes that are coupled to each other in an end-to-end fashion. The casing string 2966 is adhered to the wall of the production wellbore 2982 using cement 2962.

In addition to the tubing pipes, the tubing string 2949 may include one or more of a number (in this example, three) of subs that include an FPCS 2988. The sub that includes FPCS 2988-1 is positioned adjacent to the perforated (and possibly fractured) and substantially uniformly distributed production zone 2961-1, which allows the production fluid 2983 to inflow from part of the active storage zone 2911, through perforations in part of the cement 2962, and through perforations in part of the casing string 2966. The sub that includes FPCS 2988-2 is positioned adjacent to the perforated (and possibly fractured) and substantially uniformly distributed production zone 2961-2, which allows the production fluid 2983 to inflow from part of the active storage zone 2911, through perforations in part of the cement 2962, and through perforations in part of the casing string 2966. The sub that includes FPCS 2988-3 is positioned adjacent to the perforated (and possibly fractured) and substantially uniformly distributed production zone 2961-3, which allows the production fluid 2983 to inflow from part of the active storage zone 2911, through perforations in part of the cement 2962, and through perforations in part of the casing string 2966.

Each of the subs that include a FPCS 2988 may be totally or partially isolated from each other within the annulus 2967 by inserting one or more packers 2963 into the annulus 2967, where each packer 2963 creates a total or partial seal between the inner perimeter of the casing string 2966 and the outer perimeter of the tubing string 2949. In this case, there are three packers 2963 in the portion of the field system shown in FIG. 29. Packer 2963-1 is located upstream of FPCS 2988-1. Packer 2963-2 is located between FPCS 2988-1 and FPCS 2988-2. Packer 2963-3 is located between FPCS 2988-2 and FPCS 2988-3. Packer 2963-1 and packer 2963-2 create an isolation zone 2964-1 within the annulus 2967, where the isolation zone 2964-1 includes FPCS 2988-1. Packer 2963-2 and packer 2963-3 create an isolation zone 2964-2 within the annulus 2967, where the isolation zone 2964-2 includes FPCS 2988-2. Packer 2963-3 and the end of the production wellbore 2982 create an isolation zone 2964-3 within the annulus 2967, where the isolation zone 2964-3 includes FPCS 2988-3.

In certain example embodiments, each FPCS 2988 is configured to operate (e.g., reduce the amount of production fluid 2983 that flows from the annulus 2967 (and so from the active storage zone 2911)) and into its cavity when a pressure differential (e.g., a difference between the pressure in the tubing string 2949 within the FPCS 2988 and the pressure in the annulus 2967 outside the FPCS 2988) reaches a minimal threshold value. By using the packers 2963, the pressure in the annulus 2967 within one isolation zone 2964 may differ from the pressure in the annulus 2967 within one or more of the other isolation zones 2964. As a result, each FPCS 2988 in one isolation zone 2964 may perform independently of the FPCSs 2988 in another isolation zone 2964. This operational independence of each FPCS 2988 may depend, at least in part, on the ability of one or more of the packers 2963 to prevent fluidic communication therethrough within the annulus 2967.

When there are multiple FPCSs 2988 in the tubing string 2949, the configuration aspects (e.g., type of actuator, calibration of the actuator, material, length, inner diameter, types of coupling features) of one FPCS 2988 may be the same as, or different than, one or more of the corresponding configuration aspects of one or more of the other FPCSs 2988. The tubing string 2949 may include any number (e.g., one, three, seven, 15, 100) of FPCSs 2988. An isolation zone 2964 may include any number (e.g., one, two, five, 10, 29) of FPCSs 2988. The use of FPCS 2988 in each isolation zone 2964 allows for the substantially even distribution of the production fluid 2983 being injected among the isolation zones 2964 into the active storage zone 2911.

Using this embodiment, the horizontal production wellbore 2982 contains equipment (e.g., the FPCSs 2988) that allows the production fluid 2983 to inflow as desired from amongst selected sites in the active storage zone 2911. This example is similar to what is shown in FIG. 26, except that fluid outflow devices are replaced by fluid inflow devices. The completion in this example is segmented in a cased-hole wellbore configuration. Also in this case, the fluid production rate from each segment may be controlled as desired using packers 2963 and in-flow control devices (FPCSs 2988). In this way, the FPCS 2988 includes a production wellbore cased-hole completion interval that is configured to allow the production fluid 2983 to be produced from permeable sections of the active storage zone 2911 within the subterranean rock formation along the production wellbore 2982.

FIGS. 30 through 32 show sectional views of part of subsystems that include production wellbores that may be used in various field systems according to certain example embodiments. Specifically, FIG. 30 shows a sectional view of part of a subsystem 3098 that includes a production wellbore 3082 that may be used in various field systems according to certain example embodiments. FIG. 31 shows a sectional view of part of a subsystem 3198 that includes a production wellbore 3182 that may be used in various field systems according to certain example embodiments. FIG. 32 shows a sectional view of part of a subsystem 3298 that includes a production wellbore 3282 that may be used in various field systems according to certain example embodiments.

Referring to description above with respect to FIGS. 1 through 29, the configuration of the subsystem 3098 of FIG. 30 creates a theoretically true horizontal line-sink via the elimination of casing and perforations. In this embodiment, production fluid 3083 may flow in from the active storage zone 3011 at any point along the production wellbore 3082. However, as with the embodiment of FIG. 29, packers 3063 and fluid in-flow control devices (e.g., FPCSs 3088) are still used to distribute the production fluid 3083 from various sections of the active storage zone 3011 as desired. The three FPCSs 3088 are segmented from each other within the production wellbore 3042. This arrangement may sometimes be referred to as an open-hole segmented horizontal line-sink production completion.

The subsystem 3098 of FIG. 30 includes an open (e.g., not cased) horizontal section of a production wellbore 3082 drilled into an active storage zone 3011. In alternative embodiments, the open section of the production wellbore 3082 may be at any angle ranging from vertical to horizontal. In this case, there is no casing string inserted into the production wellbore 3082. Hydraulically-induced fracture zones may or may not exist in the active storage zone 3011. The tubing string 3049 includes a number of tubing pipes that are coupled to each other in an end-to-end fashion.

Each of the subs integrated with the tubing string 3049 that include a FPCS 3088 may be totally or partially isolated from each other within the annulus 3067 (which in this case is defined as the space between the tubing string 3049 and the wall 3066 of the production wellbore 3082) by inserting one or more packers 3063 into the annulus 3067, where each packer 3063 creates a total or partial seal between the wall 3066 of the production wellbore 3082 and the outer perimeter of the tubing string 3049. In this case, there are three packers 3063 in the portion of the subsystem 3098 shown in FIG. 30. Packer 3063-1 is located upstream of FPCS 3088-1. Packer 3063-2 is located between FPCS 3088-1 and FPCS 3088-2. Packer 3063-3 is located between FPCS 3088-2 and FPCS 3088-3. Packer 3063-1 and packer 3063-2 create an isolation zone 3064-1 within the annulus 3067, where the isolation zone 3064-1 includes FPCS 3088-1. Packer 3063-2 and packer 3063-3 create an isolation zone 3064-2 within the annulus 3067, where the isolation zone 3064-2 includes FPCS 3088-2. Packer 3063-3 and the end of the production wellbore 3082 create an isolation zone 3064-3 within the annulus 3067, where the isolation zone 3064-3 includes FPCS 3088-3.

In certain example embodiments, each FPCS 3088 is configured to operate (e.g., reduce the amount of production fluid 3083 that flows from the annulus 3067 (and so from the active storage zone 3011) into its cavity when a pressure differential (e.g., a difference between the pressure in the cavity within the FPCS 3088 and the pressure in the annulus 3067 outside the FPCS 3088) reaches a minimal threshold value. By using the packers 3063, the pressure in the annulus 3067 within one isolation zone 3064 may differ from the pressure in the annulus 3067 within one or more of the other isolation zones 3064. As a result, each FPCS 3088 (or otherwise a specific number of FPCSs 3088 as a group or subset) in one isolation zone 3064 may perform independently of the FPCSs 3088 in another isolation zone 3064.

This operational independence of each FPCS 3088 may depend, at least in part, on the ability of one or more of the packers 3063 to prevent fluidic communication therethrough within the annulus 3067. The use of FPCSs 3088 in each isolation zone 3064 allows for the substantially even distribution of inflowing production fluid 3083 among the isolation zones 3064. This example is similar to what is shown in FIG. 27, except that fluid outflow devices are replaced by fluid inflow devices. The completion in this example is segmented in an open-hole wellbore configuration. Also in this case, the fluid production rate from each segment may be controlled as desired using packers 3063 and in-flow control devices (FPCSs 3088).

In this way, the FPCS 3088 includes a production wellbore open-hole completion interval that is configured to allow the production fluid 3083 to be produced from permeable sections of the active storage zone 3011 within the subterranean rock formation along the production wellbore 3082. In some alternative cases, scenarios shown in FIGS. 29 and 30 may be combined. In such cases, the fluid production completion system may include a production wellbore internal completion assembly that is configured to allow the production fluid to be produced from permeable sections of the active storage zone within the subterranean rock formation via open-hole and cased-hole completion intervals along the production wellbore.

The configuration of the subsystem 3198 of FIG. 31 shows an unsegmented horizontal line-sink production wellbore 3182 with a cased-hole completion configuration. In this case, the completion is not segmented. The entry of the production fluid 3183 from the active storage zone 3111 is uncontrolled along the length of the completion of the production wellbore 3182. The configuration here is similar to what is shown in FIG. 29 above, except here there are no packers or inflow control devices (e.g., FPCSs) that are used. The casing string 3166 is adhered to the wall of the wellbore 3182 using cement 3162, and production fluid 3183 flows into the production wellbore 3182 from the active storage zone 3111 through perforations that extend through the casing string 3166, the cement 3162, adjacent portions of the active storage zone 3111. There is a packer 3163 that seals the annulus 3167 between the distal end of the tubing string 3149 and the casing string 3166, isolating the annulus 3167 from the area of inflow beyond the tubing string 3149.

The configuration of the subsystem 3298 of FIG. 32 shows an unsegmented horizontal line-sink production wellbore 3282 with an open-hole completion configuration. In this case, the completion is not segmented. The entry of the production fluid 3283 from the active storage zone 3211 is uncontrolled along the length of the completion of the production wellbore 3282. The configuration here is similar to what is shown in FIG. 30 above, except here there are no packers or inflow control devices (e.g., FPCSs) that are used. There is no casing string or cement in this case. The production fluid 3283 flows into the production wellbore 3282 from the active storage zone 3211 at any point along the production wellbore 3282. There is a packer 3263 that seals the annulus 3267 between the distal end of the tubing string 3249 and the casing string 3266, isolating the annulus 3267 from the area of inflow beyond the tubing string 3249.

FIG. 33 shows a flowchart 3302 of a method for implementing subterranean carbon mineralization according to certain example embodiments. While the various steps in this flowchart 3302 are presented sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps shown in this example method may be omitted, repeated, and/or performed in a different order.

While the examples above show that the sections of the various injection wellbores and production wellbores can have substantially similar orientations (e.g., horizontal, non-vertical) within an active storage zone within a subterranean rock formation, in alternative embodiments the orientation of one or more wellbores may vary within an active storage zone. For example, the injection range along an injection wellbore may be substantially horizontal, non-horizontal, or any combination thereof. As another example, the production range along a production wellbore may be substantially horizontal, non-horizontal, or any combination thereof.

In addition, a person of ordinary skill in the art will appreciate that additional steps not shown in FIG. 33 may be included in performing this method. Accordingly, the specific arrangement of steps should not be construed as limiting the scope. Further, a particular computing device, such as the computing device 318 discussed above with respect to FIG. 3, may be used to perform or facilitate performance of one or more of the steps (or portions thereof) for the method shown in FIG. 33 in certain example embodiments. Any of the functions (or portions thereof) performed below by a controller (e.g., a controller 104, a controller 204, a controller 304) may involve the use of one or more protocols 232, one or more algorithms 233, and/or stored data 233 stored in a storage repository 231. In addition, or in the alternative, any of the functions (or portions thereof) in the method may be performed by a user (e.g., user 151). In some cases, one or more of the various steps in the method of FIG. 33 can be performed automatically, as by a controller 104 of the monitoring subsystem 190.

The method shown in FIG. 33 is merely an example that may be performed by using an example system described herein. In other words, systems for implementing subterranean carbon mineralization may perform other functions using other methods in addition to and/or aside from those shown in FIG. 33. Referring to the description of FIGS. 1 through 33 above, the method shown in the flowchart 3302 of FIG. 33 begins at the START step and proceeds to step S1, where pressurized fluid 143 is injected into an injection wellbore 142. The pressurized fluid 143 may be injected using a pumping system 145 of a fluid injection well subsystem 140. The pressurized fluid 143 is configured to at least partially include carbon dioxide.

In step S2, an injection location and an injection rate of the pressurized fluid 143 from the injection wellbore 142 to an active storage zone 111 is controlled. The injection location and the injection rate of the pressurized fluid 143 may be controlled using a FICS 148 located within the injection wellbore 142 adjacent to the active storage zone 111. The injection wellbore 142 may include one FICS 148 or multiple FICSs 148. Each FICS 148 may operate autonomously or using a controller (e.g., controller 104, controller 204). The one or more FICSs 148 may be configured to be placed within an injection range of the injection wellbore 142.

In step S3, a production location and an inflow rate of production fluid 183 from the active storage zone 111 to a production wellbore 182 is controlled. The production location and the production rate of the production fluid 183 may be controlled using a FPCS 188 located within the production wellbore 182 adjacent to the active storage zone 111. The production wellbore 182 may include one FPCS 188 or multiple FPCSs 188. Each FPCS 188 may operate autonomously or using a controller (e.g., controller 104, controller 304). The one or more FPCSs 188 may be configured to be placed within a production range of the production wellbore 182.

In step S4, a determination is made as to whether the carbon storage potential of the active storage zone is depleted. The determination as to whether the carbon storage potential of the active storage zone is depleted may be made using, at least in part, measurements made by measuring equipment 160 of the monitoring subsystem 190. Some or all of the determination may be made by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151. If the carbon storage potential of the active storage zone is not depleted, then the process reverts to step S1. If the carbon storage potential of the active storage zone is depleted, then the process proceeds to step S5.

In step S5, the injection wellbore 142 is abandoned. Abandoning the injection wellbore 142 may include stopping the pumping system 145 of the fluid injection well subsystem 140. In addition, abandoning the injection wellbore 142 may include removing the tubing string 149 for use with another injection wellbore 142 or production wellbore 182.

In step S6, a determination is made as to whether an additional subterranean resource is available. Specifically, a determination is made as to whether another active storage zone 111 within the subterranean rock formation 110 is available so that additional carbon dioxide may be captured using carbon mineralization. The determination as to whether another active storage zone 111 within the subterranean rock formation 110 is available may be made using measurements made by the measuring equipment 160 of the monitoring subsystem 190. Some or all of the determination may be made by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151. If there is not an additional subterranean resource available, then the mineralization development of the subterranean resource is ended, and the process proceeds to the END step. If there is an additional subterranean resource available, then the process reverts to step S1 after another active storage zone 111 within the subterranean formation 110 is identified and developed by drilling at least one more injection wellbore 142 and at least one more production wellbore 182, as set forth in the method captured in FIG. 34 below.

In Step S7, wellbores for a new active storage zone 111 are established. In some cases, there may be multiple new active storage zones 111. In some cases, a new active storage zone 111 (sometimes called an additional active storage zone 111) is adjacent to a depleted storage zone (e.g., depleted storage zone 1913). Establishing a new active storage zone 111 may include identifying a location of the new active storage zone 111 within the subterranean formation 110, identifying an injection wellbore 142 and related characteristics (e.g., an entry point, a path through the subterranean formation 110, location of the FICSs 148), identifying one or more new production wellbores 182 and related characteristics (e.g., an entry point, a path through the subterranean formation 110, location of the FPCSs 188), maintaining a production wellbore 182 for production, and/or identifying one or more idle wellbores (e.g., idle wellbore 663) to revert to a production wellbore 182. In some cases, this step S7 (rather than step S1) may be the first step after the START step. When step S7 is complete, the process proceeds to step S1.

FIG. 34 shows a flowchart 3402 of a method for identifying a subterranean volume to facilitate carbon mineralization according to certain example embodiments. While the various steps in this flowchart 3402 are presented sequentially, one of ordinary skill will appreciate that some or all of the steps may be executed in different orders, may be combined or omitted, and some or all of the steps may be executed in parallel. Further, in one or more of the example embodiments, one or more of the steps shown in this example method may be omitted, repeated, and/or performed in a different order.

In addition, a person of ordinary skill in the art will appreciate that additional steps not shown in FIG. 34 may be included in performing this method. Accordingly, the specific arrangement of steps should not be construed as limiting the scope. Further, a particular computing device, such as the computing device 318 discussed above with respect to FIG. 3, may be used to perform or facilitate performance of one or more of the steps (or portions thereof) for the method shown in FIG. 34 in certain example embodiments. Any of the functions (or portions thereof) performed below by a controller (e.g., a controller 104, a controller 204, a controller 304) may involve the use of one or more protocols 232, one or more algorithms 233, and/or stored data 234 stored in a storage repository 231. In addition, or in the alternative, any of the functions (or portions thereof) in the method may be performed by a user (e.g., user 151). In some cases, one or more of the various steps in the method of FIG. 34 can be performed automatically, as by a controller 104 of the monitoring subsystem 190.

The method shown in FIG. 34 is merely an example that may be performed by using an example system described herein. In other words, systems for identifying a subterranean volume to facilitate carbon mineralization may perform other functions using other methods in addition to and/or aside from those shown in FIG. 34. Referring to the description of FIGS. 1 through 34 above, the method shown in the flowchart 3402 of FIG. 34 begins at the START step and proceeds to step S8, where measurements of parameters associated with the subterranean rock formation 110 are obtained. As used herein, the term “obtaining” may include receiving, retrieving, accessing, generating, etc. or any other manner of obtaining information (in this case, the measurements of the parameters associated with the subterranean rock formation 110).

The measurements may be obtained from the measuring equipment 160 of the monitoring subsystem 190. The measurements may be obtained by a controller 104 of the monitoring subsystem 190. In step S9, the measurements obtained in step S8 are evaluated. Some or all of the measurements may be evaluated by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151. In step S10, one or more active storage zones 111 are identified. An active storage zone 111 may be identified by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151.

In step S11, the entry point and pathway for one or more injection wellbores 142 and for one or more production wellbores 182 are identified. The entry points and pathways may be identified by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151. In step S12, a chemical composition and form of the pressurized fluid 143 are identified. The chemical composition may include, for example, how much carbon dioxide is included in the pressurized fluid 143. The form of the pressurized fluid 143 may include, for example, whether the pressurized fluid 143 is in liquid form or gas form. In step S13, additional measurements of parameters (e.g., identifying the chemical composition of the produced fluid 183) associated with the active storage zone 111 are obtained. The measurements may be obtained from the measuring equipment 160 of the monitoring subsystem 190. The measurements may be obtained by a controller 104 of the monitoring subsystem 190.

In step S14, a determination is made as to whether the carbon storage potential of the active storage zone 111 is depleted. The determination as to whether the carbon storage potential of the active storage zone is depleted may be made using, at least in part, measurements made by measuring equipment 160 of the monitoring subsystem 190. Some or all of the determination may be made by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151. If the carbon storage potential of the active storage zone is not depleted, then the process reverts to step S13. If the carbon storage potential of the active storage zone is depleted, then the process proceeds to step S15.

In step S15, instructions are sent to abandon the one or more injection wellbores 142. The instructions may be sent by a controller 104 of the monitoring subsystem 190 and received by a user 151. The instructions may also include other information, such as whether to suspend operations for one or more of the production wellbores 182. In step S16, a determination is made as to whether an additional subterranean resource is available. Specifically, a determination is made as to whether another active storage zone 111 within the subterranean rock formation 110 is available so that additional carbon may be captured using carbon mineralization. The determination as to whether another active storage zone 111 within the subterranean rock formation 110 is available may be made using measurements made by the measuring equipment 160 of the monitoring subsystem 190. Some or all of the determination may be made by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151. If there is an additional subterranean resource available, then the process proceeds to step S17. If there is not an additional subterranean resource available, then the process proceeds to the END step.

In step S17, one or more additional active storage zones 111 are identified. An additional active storage zone 111 may be identified by a controller (e.g., a controller 104 of the monitoring subsystem 190) and/or a user 151. When step S17 is complete, the process reverts to step S8 so that the process may be repeated.

Example embodiments may be used to provide systems and methods for implementing subterranean carbon mineralization. Example embodiments may utilize progressive stages that maximize utilization of storage zones within subterranean rock formations in terms of carbon sequestration through carbon mineralization. Example embodiments may provide a number of benefits. Such benefits may include, but are not limited to, more reliable field operations, ease of installation and use, reduced downtime, increased flexibility, configurability, and compliance with applicable industry standards and regulations.

Although embodiments described herein are made with reference to example embodiments, it should be appreciated by those skilled in the art that various modifications are well within the scope of this disclosure. Those skilled in the art will appreciate that the example embodiments described herein are not limited to any specifically discussed application and that the embodiments described herein are illustrative and not restrictive. From the description of the example embodiments, equivalents of the elements shown therein will suggest themselves to those skilled in the art, and ways of constructing other embodiments using the present disclosure will suggest themselves to practitioners of the art. Therefore, the scope of the example embodiments is not limited herein.