System and method for underground storage of gases

Abstract

A method involves storing gas in a subsurface region of a hydrocarbon reservoir. The method includes injecting a barrier forming solution into the subsurface region. The method also includes injecting a driving solution into the subsurface region. The driving solution drives the barrier-forming solution to form a low permeability barrier bounded on the top by caprock. The method further includes injecting a gas into the subsurface region. The gas is stored under the caprock and within a gas storage region formed by the low permeability barrier.

Description

SYSTEM AND METHOD FOR UNDERGROUND STORAGE OF GASESCROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63 / 584,934, entitled “SYSTEM AND METHOD FOR UNDERGROUND STORAGE OF GASES,” having a filing date of September 25, 2023, the disclosure of which is incorporated herein by reference in its entirety.FIELD OF THE INVENTION

[0002] The techniques described herein relate generally to the field of containment of greenhouse gases (GHG), as well as other gases. More specifically, the techniques described herein relate to the long-term storage of GHG such as carbon dioxide (CO2) and short term storage of hydrogen (H2), natural gas and coal gas in the subsurface.BACKGROUND OF THE INVENTION

[0003] This section is intended to introduce various aspects of the art, which may be associated with embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

[0004] There is increasing global concern regarding GHG emissions. Many industrial activities result in the production of GHG, such as CO2. Further, industrial activities result in the production of other gases, including hydrogen gas (H2).

[0005] One approach to storing GHG and other gases is to contain them underground so that they are not released into the atmosphere. Injection of gases into subsurface porous media has been used for both short-term and long-term gas storage. However, efficiently storing gases in the subsurface has proven to be problematic.

[0006] A major challenge is the low pore space utilization (storage efficiency) in the absence of an anticline (geologic dome structure), which may range from about 0.5% to 4% for carbon sequestration. In the absence of an anticline, storage efficiency may be even lower for H2 because of the physical properties of H2.

[0007] Some theories have been advanced regarding improving efficiency of underground gas storage. With regard to CO2 storage, these theories relate to viscosification of CO2 using additives,such as polymers. However, implementation of these theories is expected to be prohibitively expensive and technically challenging.

[0008] As to cost, chemicals needed to viscosify CO2 are estimated to increase operating expenses. Further, it is expected that polymers used to viscosify CO2 should be biodegradable because of environmental concerns as these polymers should migrate with the CO2 plume, further escalating both cost and technical complexity of the solution.

[0009] Also, viscosifying CO2 is likely to add significant operational complexity and cost. The polymer additives need to be mixed with supercritical CO2 prior to injection into the subsurface. This has not been proven to be technically feasible at commercial scale. Operators should need to ship the additives to the injection site and maintain them at the correct temperature and pressure to avoid flow assurance issues. High pressure, large scale mixing tanks should likely be needed as well.

[0010] Furthermore, polymer additives are not soluble in water, so as CO2 dissolves in formation brine, the polymer additives are likely to drop out and clog up the pore space, resulting in potential formation damage. An improved way of performing underground gas storage is desirable.SUMMARY OF THE INVENTION

[0011] An embodiment provided herein relates to a method of storing gas in a subsurface region of a hydrocarbon reservoir or saline formation. The method includes injecting a barrier-forming solution into the subsurface region. The method also includes injecting a driving solution into the subsurface region. The driving solution drives the barrier-forming solution to form a low permeability barrier bounded on the top by caprock. The method further includes injecting a gas into the subsurface region. The gas is stored under the caprock and within a gas storage region formed by the barrier.

[0012] Another embodiment provided herein relates to a well system for storing gas in a subsurface region of a hydrocarbon reservoir or saline formation. The well system includes an injection well. The well system also includes a barrier-forming solution that is injected into the subsurface region through the injection well. The well system also includes a driving solution that is injected into the subsurface region through the injection well. The driving solution drives the barrierforming solution to form a low permeability barrier bounded on the top by caprock. The well system further includes a gas that is injected into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the low permeability barrier.

[0013] A further embodiment provided herein relates to a well system for storing gas in a subsurface region of a hydrocarbon reservoir or saline formation. The well system includes aninjection well. The well system also includes a barrier-forming solution that is injected into the subsurface region through the injection well. The well system further includes a driving solution that is injected into the subsurface region through the injection well. The driving solution drives the barrier-forming solution to form a low permeability barrier bounded on the top by caprock. The well system still further includes a gas that is injected into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the low permeability barrier. The well system additionally includes a computing system that computes an optimized composition and size of the low permeability barrier. The computing system controls the injection of the barrier-forming solution, the driving solution and the gas into the subsurface region.

[0014] These and other features and attributes of the disclosed embodiments of the present techniques and their advantageous applications and / or uses will be apparent from the detailed description that follows.BRIEF DESCRIPTION OF THE DRAWINGS

[0015] To assist those of ordinary skill in the relevant art in making and using the subject matter described herein, reference is made to the appended drawings, where:

[0016] FIG. 1 is a simplified schematic view of a conventional reservoir showing various types of gas storage in which the present techniques may be employed;

[0017] FIG. 2 is a schematic illustration showing a known use of an injection well configured to perform gas storage;

[0018] FIG. 3 is a schematic illustration showing an exemplary embodiment of a well configured to perform gas storage according to the present techniques;

[0019] FIG. 4 is a schematic illustration showing a first step in creating a low permeability barrier to facilitate gas storage in accordance with the present techniques;

[0020] FIG. 5 is a schematic illustration showing a second step in creating a low permeability barrier to facilitate gas storage in accordance with the present techniques;

[0021] FIG. 6 is a perspective view showing the formation of a low permeability barrier to form a perimeter to contain stored gases in accordance with the present techniques;

[0022] FIG. 7 is a schematic illustration showing the completed low permeability barrier in accordance with the present techniques;

[0023] FIG. 8 is a process flow diagram of an exemplary method for performing gas storage according to the present techniques;

[0024] FIG. 9 is a block diagram of an exemplary cluster computing system that may be utilized to implement at least a portion of the present techniques; and

[0025] FIG. 10 is a block diagram of an exemplary non-transitory, computer-readable storage medium that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques.

[0026] It should be noted that the figures are merely examples of the present techniques and are not intended to impose limitations on the scope of the present techniques. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the techniques.DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0027] In the following detailed description section, the specific examples of the present techniques are described in connection with preferred embodiments. However, to the extent that the following description is specific to a particular embodiment or a particular use of the present techniques, this is intended to be for exemplary purposes only and simply provides a description of the embodiments. Accordingly, the techniques are not limited to the specific embodiments described below, but rather, include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

[0028] At the outset, and for ease of reference, certain terms used in this application and their meanings as used in this context are set forth. To the extent a term used herein is not defined below, it should be given the broadest definition those skilled in the art have given that term as reflected in at least one printed publication or issued patent. Further, the present techniques are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments, and terms or techniques that serve the same or a similar purpose are considered to be within the scope of the present claims.

[0029] As used herein, the singular forms “a,” “an,” and “the” mean one or more when applied to any embodiment described herein. The use of “a,” “an,” and / or “the” does not limit the meaning to a single feature unless such a limit is specifically stated.

[0030] The term “and / or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and / or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and / or” clause, whether related or unrelated to those entities specifically identified. Thus,as a non-limiting example, a reference to “A and / or B,” when used in conjunction with open- ended language such as “including,” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

[0031] As used herein, the term “any” means one, some, or all of a specified entity or group of entities, indiscriminately of the quantity.

[0032] The phrase “at least one,” when used in reference to a list of one or more entities (or elements), should be understood to mean at least one entity selected from any one or more of the entities in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities, and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently, “at least one of A and / or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and / or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B, and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C,” and “A, B, and / or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B, and C together, and optionally any of the above in combination with at least one other entity.

[0033] As used herein, the phrase “based on” does not mean “based only on,” unless expressly specified otherwise. In other words, the phrase “based on” means “based only on,” “based at least on,” and / or “based at least in part on.”

[0034] As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present techniques, are intended to convey that the described component, feature, structure, or method is anillustrative, non-exclusive example of components, features, structures, or methods according to the present techniques. Thus, the described component, feature, structure, or method is not intended to be limiting, required, or exclusive / exhaustive; and other components, features, structures, or methods, including structurally and / or functionally similar and / or equivalent components, features, structures, or methods, are also within the scope of the present techniques.

[0035] As used herein, the term “field” (sometimes referred to as an “oil and gas field” or a “hydrocarbon field”) refers to an area including one or more hydrocarbon wells for which hydrocarbon production operations are to be performed to provide for the extraction of hydrocarbon fluids from a corresponding subterranean formation.

[0036] As used herein, the term “surface” refers to the uppermost land surface of a land well, or the mud line of an offshore well, while the term “subsurface” (or “subterranean”) generally refers to a geologic strata occurring below the earth’s surface. Moreover, as used herein, “surface” and “subsurface” are relative terms. The fact that a particular piece of equipment is described as being on the surface does not necessarily mean it must be physically above the surface of the earth but, rather, describes only the relative placement of the surface and subsurface pieces of equipment. In that sense, the term “surface” may generally refer to any equipment that is located above the casing strings and other equipment that is located inside the wellbore. Moreover, according to embodiments described herein, the terms “downhole” and “subsurface” are sometimes used interchangeably, although the term “downhole” is generally used to refer specifically to the inside of the wellbore.

[0037] The term “wellbore” refers to a borehole drilled into a subterranean formation. The borehole may include vertical, deviated, highly deviated, and / or horizontal sections. The term “wellbore” also includes the downhole equipment associated with the borehole, such as the casing strings, production tubing, gas lift valves, and other subsurface equipment. Relatedly, the term “hydrocarbon well” (or simply “well”) includes the wellbore in addition to the wellhead and other associated surface equipment.

[0038] FIG. 1 is a simplified schematic view of a conventional reservoir 100 showing various types of gas storage in which the present techniques may be employed. As a first example, a first injection well 102 operates in a region of the reservoir 100 in which hydrocarbons have been depleted. The first injection well 102 may be used to inject a gas such as CO2 into the formation, resulting in gas being stored in a stored CO2 region 104.

[0039] As a second example, CO2 may be used in an enhanced oil recovery (EOR) operation. CO2 may be injected into a second injection well 106. The CO2 injected into the second injectionwell 106 may stimulate hydrocarbon production from a producing well 108. The CO2 may remain in the reservoir in a stored CO2 region 110.

[0040] In a third example, CO2 may be injected into a region of the reservoir 100 to be stored in brine saturated reservoir rocks. As shown in FIG. 1, a third injection well 112 may be used to inject CO2 into the reservoir 100. The CO2 injected into the third injection well 112 is stored in a stored CO2 region 114.

[0041] The third injection well 112 may be located in a region of the reservoir 100 that is still being used to produce hydrocarbons via other wells. However, the third injection well 112 is typically be located in a portion of the field that is no longer productive when being used for gas storage. Because the stored CO2 region 114 no longer contains hydrocarbons, the pore structure of the stored CO2 region 104 is typically filled with brine. Gases that are injected into the third injection well 112 typically displace the brine in the pore structure to some extent, as explained herein.

[0042] FIG. 2 is a schematic illustration showing the use of an injection well 200 configured to perform gas storage in a known manner. Moreover, the injection well 200 shown in FIG. 2 is storing gas without the use of the present techniques. The flow of gases into the injection well 200 is shown in FIG. 2 by an arrow 202.

[0043] As described herein, a subsurface region 204 of the reservoir 100 has a pore structure that, prior to gas injection, is filled mostly with brine. When gas is injected into the subsurface region 204 for storage, buoyancy forces drive the formation of a plume 206, which first moves upwards and then spreads laterally, resulting in an inverted cone shape, as shown in FIG. 2. Away from the injection well 200 and near a caprock 208, however, the plume 206 spreads like a thin pancake or tongue underneath the caprock 208, as highlighted by the arrows 210.

[0044] FIG. 3 is a schematic illustration showing an exemplary embodiment of a well configured to perform gas storage according to the present techniques. FIG. 3 shows the subsurface region 204 after the injection of gas to create a gas plume 300 of stored gas.

[0045] The caprock 208 is a relatively impermeable or low-permeability layer of rock that lies above the subsurface region 204 and seals off an underlying reservoir or formation. The caprock 208 acts as a barrier or cap, preventing the upward migration or escape of fluids, such as oil, gas, or water, from the reservoir.

[0046] Exemplary embodiments of the present techniques relate to subsurface “fencing” technology that creates a low permeability barrier centered around the injection well 302 andunderneath the caprock 208 that mitigates the mobile gas plume from migrating past the barrier. As buoyancy drives the injected gas to rise towards the caprock 208 and then spread laterally, the caprock 208 and the barrier serve as an artificial dome or anticline that enables higher pore space utilization for gas storage. This results in improved storage efficiency of gases stored in the subsurface region 204. Furthermore, hydrodynamics drive convection cells within the dome that in the case of storing CO2, enhances CO2 / brine mixing and dissolution trapping.

[0047] The present techniques provide for the creation of a low permeability barrier 304 to provide a relatively impermeable perimeter to prevent dispersal of the gas plume 300 laterally within the subsurface region 204. The low permeability barrier 304 may take the shape of a ring or donut disposed to form a gas impermeable seal with the caprock 208. The practitioner may appreciate that the low permeability barrier 304 is desirably created as described herein prior to the injection of gases for storage via the injection well 302.

[0048] As shown in FIG. 3, the low permeability barrier 304 is disposed directly beneath and adjacent to the caprock 208. Moreover, the low permeability barrier 304 provides a robust storage region to efficiently store the gas plume 300 on a long-term basis. Arrows 306 show the thickness of the gas storage region created by the low permeability barrier 304. The low permeability barrier 304 facilitates the creation of a fenced storage region that is significantly thicker than the storage region that is present without the low permeability barrier 304. Moreover, the gas storage region shown in FIG. 3 is significantly thicker than the corresponding storage region shown in FIG. 2. According to the present techniques, the gas storage region shown in FIG. 3 may be in the range of may be in the range of 50% to 90% thicker than the gas storage region shown in FIG. 2.

[0049] According to the present techniques, buoyancy of injected gases drives the injected gases to rise toward the caprock 208 to form the gas plume 300. As the gas plume 300 spreads laterally, the caprock 208 and the low permeability barrier 304 act as an artificial dome or anticline that enables higher pore space utilization. Furthermore, hydrodynamics drive convection cells within the dome that in the case of stored CO2, enhances mixing and dissolution of CO2 with the brine disposed in the subsurface region 204.

[0050] FIG. 4 is a schematic illustration showing a first step in creating the low permeability barrier 304 (FIG. 3) to facilitate gas storage in accordance with the present techniques. As noted herein, the process of creating the low permeability barrier 304 is desirably done before the injection of any gases to be stored into the subsurface region 204.

[0051] The first step in creating the low permeability barrier 304 in the subsurface region 204 is to select a barrier-forming solution 400. The barrier-forming solution 400 may be a gel / polymer system with controllable setting and hardening time (i.e., cross-linking time) that is resistant to degradation under reservoir conditions of interest. In exemplary embodiments, the controllable setting and hardening time may range in the range of a few weeks to a few months. Examples of such systems include polymer gels such as polyacrylamides (PAM), partially hydrolyzed polyacrylamides (PHP A), xanthan gum, carboxymethylcellulose, furfural alcohol, acrylic / epoxy resins, silicate based gels, and block copolymers. Meanwhile, the crosslinker can be classified into two groups: organic (such as phenol, formaldehyde, and polyethyleneimine (PEI)) and inorganic (such as Cr3+, A13+, Zr3+). In particular, the barrier-forming solution 400, once deployed into the subsurface region 204, is desirably resistant to ambient temperatures, pressures, salinity, low pH in the case of CO2 storage, etc. over a long period of time. This means that the barrier-forming solution 400 is chosen to have properties that facilitate gas storage for an extended period of time (e g., one year or longer).

[0052] Once selected, the barrier-forming solution 400 is injected into the subsurface region 204, as shown in FIG. 4. The barrier-forming solution 400 spreads across the top of the subsurface region 204, underneath the caprock 208, as indicated by the arrows 402 in FIG. 4.

[0053] Prior to barrier setting / hardening (cross-linking for a gel system), that is, during the injection phase, the viscosity of the barrier-forming solution 400 is to be greater than the viscosity of formation brine in the subsurface region 104. The viscosity of the barrier-forming solution 400 is preferably two times or more greater than the viscosity of the formation brine. If the viscosity of the barrier-forming solution 400 is greater than formation brine, undesirable viscous fingering may be reduced or arrested during deployment of the barrier-forming solution 400.

[0054] The practitioner may appreciate that the amount of the barrier-forming solution 400 to be injected into the subsurface region depends on the size of the containment dome that is desired to be created. Determining the thickness of the gas storage region created by the barrier-forming solution 400 should take into account the thickness of the reservoir that contains the subsurface region 204. The thickness of the reservoir is shown as “D” in FIG. 4 and the thickness of the barrier-forming solution 400 is shown as “d.” The thickness d of the barrier-forming solution 400 injected into the subsurface region 204 should be smaller than the thickness D of the reservoir. This avoids compartmentalization and minimize the undesirable increase in pressure in the subsurface region 204 over time. Increased pressure in the subsurface region 204 as gases are injected for storage over timeis undesirable because such increased pressure could result in caprock damage that may allow stored gases to escape.

[0055] FIG. 5 is a schematic illustration showing a second step in creating the low permeability barrier 304 (FIG. 3) to facilitate gas storage in accordance with the present techniques. Once the barrier-forming solution 400 is injected into the subsurface region 204, a driving solution 500 is then injected into the subsurface region 204. The driving solution 500 drives or pushes the barrierforming solution 400 outward, as indicated by the arrows 502 to form the barrier-forming solution 400 into the low permeability barrier 304 (FIG. 3).

[0056] The driving solution 500 may comprise a polymer, gel or foam solution selected to drive the barrier-forming solution 400 to form the low permeability barrier 304. The driving solution 500 should have a viscosity higher than the viscosity of the barrier-forming solution 400 prior to setting / hardening. This is to avoid undesirable viscous fingering. Further, the driving solution 500 should be selected to degrade under reservoir conditions in a relatively short time or determined degradation time period. In an exemplary embodiment, the driving solution 500 comprises a hydrogel or foam that degrades in a matter of weeks or months under reservoir conditions. Examples of times (e.g., degradation time periods) in which the driving solution 500 may degrade and disappear under reservoir conditions include two to three weeks, two to four weeks, two to five weeks, two to six weeks or two to seven weeks. After the driving solution 500 drives or pushes the barrier-forming solution 400 to form the low permeability barrier 304, the driving solution 500 degrades under typical subsurface conditions and dissolves into the formation brine, allowing the low permeability barrier 304 to form a perimeter to store gases on a long-term basis. Gases to be stored may then be injected into the subsurface region 204.

[0057] FIG. 6 is a perspective view showing the formation of the low permeability barrier 304 (FIG. 3) to form a gas storage region to contain stored gases in accordance with the present techniques. FIG. 6 shows that the driving solution 500 has pushed the barrier-forming solution 400 into the shape of a donut or ring. When the driving solution 500 degrades and dissolves into the formation brine, the donut or ring becomes the low permeability barrier 304, which results in improved storage efficiency for stored gases in the subsurface region 204.

[0058] FIG. 7 is a schematic illustration showing the completed low permeability barrier 304 in accordance with the present techniques. After degradation of the driving solution 500, a gas storage region 700 remains. The gas storage region 700 is the region within the perimeter created by the barrier 304, bounded on the top by the caprock 208. The gas storage region 700 has a thickness d, asexplained herein with reference to FIG. 4. The thickness d of the gas storage region 700 is less than the overall thickness D of the entire reservoir.

[0059] FIG. 8 is a process flow diagram of an exemplary method 800 for storing gas in the subsurface region 104 of a hydrocarbon reservoir or saline formation. The method 800 may be executed, at least in part, by one or more computing systems including one or more processors, such as the cluster computing system described with respect to FIG. 9, or any suitable variation(s) thereof. In some embodiments, such computing system(s) (or a portion of such computing systems) may be located at a centralized facility or distributed across a number of locations.

[0060] The method 800 begins at block 802, at which a barrier-forming solution 400 is injected into the subsurface region 104. The specific characteristics of the barrier-forming solution 400 may be determined according to the present techniques.

[0061] At block 804, a driving solution 500 is injected into the subsurface region 104. The driving solution 500 acts to push or drive the barrier-forming solution to form a low permeability barrier bounded on the top by caprock 108. Thereafter, the driving solution 500 degrades and dissolves into formation brine, leaving the barrier-forming solution 400 formed into the low permeability barrier 304. According to the present techniques, the low permeability barrier 304 is constructed as described herein prior to injection of any gas to be stored in the subsurface region.

[0062] At block 806, a gas is injected into the subsurface region 204. The gas is stored under the caprock 208 and within the gas storage region 700 formed by the low permeability barrier 304. In this manner, storage efficiency of GHG, including CO2, is improved.

[0063] In various embodiments, the method 800 includes determining a composition and size of the low permeability barrier 304. The specific size and composition of the low permeability barrier may be determined for individual injection wells and reservoirs using the design considerations set forth in this disclosure.

[0064] The practitioner may appreciate that the gas storage region 700 (FIG. 7) constructed as described herein provides a number of advantages for the long-term storage of gases, including GHG such as CO2. The low permeability barrier 304 is desirably created prior to gas injection so no changes are introduced to gas injection operations.

[0065] Further, the oil and gas industry has many years of experience injecting gels or foams into the subsurface for conformance control so the present techniques may be accomplished without major technical hurdles from operational perspective. Also, the barrier-forming solution 400 and the driving solution 500 are introduced prior to the injection of stored gases. Thus, unexpectedconsequences from interaction between the barrier-forming / driving solutions, stored gases, brine and rock are unlikely to arise during performance of the present techniques.

[0066] Another advantage of the present techniques is that the barrier-forming / driving solutions and the stored gases are injected into the subsurface using the same injection well. Accordingly, no additional drilling cost is incurred when performing the present techniques. Further, the effectiveness of containment within the gas storage region 700 may be tested prior to the start of gas injection at commercial scale. This further reduces operational risks. The low permeability barrier created according to the present techniques may be used to fence out gases so that they do not leak through legacy wells that have not been properly plugged and abandoned. The barrier-forming solution may be deployed to remediate leaks in the caprock to further secure storage of gases in the subsurface region.

[0067] FIG. 9 is a block diagram of an exemplary cluster computing system 900 that may be utilized to implement at least a portion of the present techniques. Moreover, the cluster computing system 900 may be used, for example, to calculate the specific composition and size of the low permeability barrier 302. In particular, the specific materials used to prepare the barrier-forming solution and the driving solution, as well as the proportions of these materials used, may be computed by the cluster computing system 900. Volumes of the barrier-forming solution and driving solution and time required to inject them into the subsurface are further examples of parameters that could be determined by the cluster computing system 900.

[0068] The exemplary cluster computing system 900 shown in FIG. 9 has four computing units 902A, 902B, 902C, and 902D, each of which may perform calculations for a portion of the present techniques. However, one of ordinary skill in the art will recognize that the cluster computing system 900 is not limited to this configuration, as any number of computing configurations may be selected. For example, a smaller analysis may be run on a single computing unit, such as a workstation, while a large calculation may be run on a cluster computing system 900 having tens, hundreds, or even more computing units.

[0069] The cluster computing system 900 may be accessed from any number of client systems 904A and 904B over a network 906, for example, through a high-speed network interface 908. The computing units 902A to 902D may also function as client systems, providing both local computing support and access to the wider cluster computing system 900.

[0070] The network 906 may include a local area network (LAN), a wide area network (WAN), the Internet, or any combinations thereof. Each client system 904A and 904B may include one ormore non-transitory, computer-readable storage media for storing the operating code and program instructions that are used to implement at least a portion of the present techniques, as described further with respect to the non-transitory, computer-readable storage media of FIG. 7. For example, each client system 904A and 904B may include a memory device 910A and 910B, which may include random access memory (RAM), read only memory (ROM), and the like. Each client system 904A and 904B may also include a storage device 912A and 912B, which may include any number of hard drives, optical drives, flash drives, or the like.

[0071] The high-speed network interface 908 may be coupled to one or more buses in the cluster computing system 900, such as a communications bus 914. The communication bus 914 may be used to communicate instructions and data from the high-speed network interface 908 to a cluster storage system 916 and to each of the computing units 902A to 902D in the cluster computing system 900. The communications bus 914 may also be used for communications among the computing units 902A to 902D and the cluster storage system 916. In addition to the communications bus 914, a high-speed bus 918 can be present to increase the communications rate between the computing units 902A to 902D and / or the cluster storage system 916.

[0072] In some embodiments, the one or more non-transitory, computer-readable storage media of the cluster storage system 916 include storage arrays 920A, 920B, 920C and 920D for the storage of models, data, visual representations, results (such as graphs, charts, and the like used to convey results obtained using the present techniques), code, and other information concerning the implementation of at least a portion of the present techniques. The storage arrays 920A to 920D may include any combinations of hard drives, optical drives, flash drives, or the like.

[0073] Each computing unit 902A to 902D includes at least one processor 922A, 922B, 922C and 922D and associated local non-transitory, computer-readable storage media, such as a memory device 924A, 924B, 924C and 924D and a storage device 926A, 926B, 926C and 926D, for example. Each processor 922A to 922D may be a multiple core unit, such as a multiple core central processing unit (CPU) or a graphics processing unit (GPU). Each memory device 924A to 924D may include ROM and / or RAM used to store program instructions for directing the corresponding processor 922A to 922D to implement at least a portion of the present techniques. Each storage device 926A to 926D may include one or more hard drives, optical drives, flash drives, or the like. In addition, each storage device 926A to 926D may be used to provide storage for models, intermediate results, data, images, or code used to implement at least a portion of the present techniques.

[0074] The present techniques are not limited to the architecture or unit configuration illustrated in FIG. 9. For example, any suitable processor-based device may be utilized for implementing at least a portion of the embodiments described herein, including (without limitation) personal computers, laptop computers, computer workstations, mobile devices, and multi-processor servers or workstations with (or without) shared memory. Moreover, the embodiments described herein may be implemented, at least in part, on application specific integrated circuits (ASICs) or very-large-scale integrated (VLSI) circuits. In fact, those skilled in the art may utilize any number of suitable structures capable of executing logical operations according to the embodiments described herein.

[0075] FIG. 10 is a block diagram of an exemplary non-transitory, computer-readable storage medium 1000 that may be used for the storage of data and modules of program instructions for implementing at least a portion of the present techniques. The non-transitory, computer-readable storage medium 1000 may include a memory device, a hard disk, and / or any number of other devices, as described herein. A processor 1002 may access the non-transitory, computer-readable storage medium 1000 over a bus or network 1004. While the non-transitory, computer-readable storage medium 1000 may include any number of modules for implementing the present techniques, in some embodiments, the non-transitory, computer-readable storage medium 1000 includes a low permeability barrier composition and size calculation module 1006 for performing the techniques described herein (and / or any suitable variations thereof). Moreover, the low permeability barrier low permeability barrier composition and size calculation module 1006 may be adapted to analyze data representing the composition and size of the low permeability barrier 304 in order to optimize gas storage, as described herein.

[0076] In one or more embodiments, the present techniques may be susceptible to various modifications and alternative forms, such as the following embodiments as noted in paragraphs 1 to 21:1. A method of storing gas in a subsurface region of a hydrocarbon reservoir or saline formation, the method comprising: injecting a barrier-forming solution into the subsurface region; injecting a driving solution into the subsurface region, the driving solution driving the barrier-forming solution to form a low permeability barrier bounded on the top by caprock; and injecting a gas into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the barrier.2. The method of paragraph 1, wherein the barrier-forming solution comprises a system with controllable setting and hardening time that is resistant to degradation under subsurface conditions.3. The method of paragraphs 1 or 2, wherein the barrier-forming solution has a viscosity greater than brine in the subsurface region to reduce viscous fingering.4. The method of any of any of paragraphs 1 to 3, wherein the driving solution has a viscosity greater than a viscosity of the barrier-forming solution prior to setting and hardening.5. The method of any of paragraphs 1 to 4, wherein the driving solution degrades in a degradation time period under subsurface conditions, so that the driving solution acts to form the barrier-forming solution into the low permeability barrier prior to degradation.6. The method of any of paragraphs 1 to 5, wherein the gas comprises greenhouse gasses (GHG)s including carbon dioxide (CO2), hydrogen, natural gas or coal gas.7. The method of any of paragraphs 1 to 6, wherein a thickness of the low permeability barrier is less than a thickness of the reservoir.8. A well system for storing gas in a subsurface region of a hydrocarbon reservoir or saline formation, the well system comprising: an injection well; a barrier-forming solution that is injected into the subsurface region through the injection well; a driving solution that is injected into the subsurface region through the injection well, the driving solution driving the barrier-forming solution to form a low permeability barrier bounded on the top by caprock; and a gas that is injected into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the low permeability barrier.9. The well system of paragraph 8, wherein the barrier-forming solution comprises a system with controllable setting and hardening time that is resistant to degradation under subsurface conditions.10. The well system of paragraphs 8 or 9, wherein the barrier-forming solution has a viscosity greater than brine in the subsurface region to reduce viscous fingering.11. The well system of any of paragraphs 8 to 10, wherein the driving solution has a viscosity greater than a viscosity of the barrier-forming solution prior to setting and hardening.12. The well system of any of paragraphs 8 to 11, wherein the driving solution degrades in a degradation time period under subsurface conditions, so that the driving solution acts to form the barrier-forming solution into the low permeability barrier prior to degradation.13. The well system of any of paragraphs 8 to 12, wherein the gas comprises greenhouse gases (GHGs) including carbon dioxide (CO2), hydrogen, natural gas or coal gas.14. The well system of any of paragraphs 8 to 13, wherein a thickness of the low permeability barrier is less than a thickness of the reservoir.15. A well system for storing gas in a subsurface region of a hydrocarbon reservoir or salineformation, the well system comprising: an injection well; a barrier-forming solution that is injected into the subsurface region through the injection well; a driving solution that is injected into the subsurface region through the injection well, the driving solution driving the barrier-forming solution to form a low permeability barrier bounded on the top by caprock; a gas that is injected into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the low permeability barrier; and a computing system that computes an optimized composition and size of the low permeability barrier and controls the injection of the barrier-forming solution, the driving solution and the gas into the subsurface region.16. The well system of paragraph 15, wherein the barrier-forming solution comprises a system with controllable setting and hardening time that is resistant to degradation under subsurface conditions.17. The well system of paragraphs 15 or 16, wherein the barrier-forming solution has a viscosity greater than brine in the subsurface region to reduce viscous fingering.18. The well system of any of paragraphs 15 to 17, wherein the driving solution has a viscosity greater than a viscosity of the barrier-forming solution prior to setting and hardening.19. The well system of any of paragraphs 15 to 18, wherein the driving solution degrades in a degradation time period under subsurface conditions, so that the driving solution acts to form the barrier forming solution into the low permeability barrier prior to degradation.20. The well system of any of paragraphs 15 to 19, wherein the gas comprises greenhouse gases (GHGs) including carbon dioxide (CO2), hydrogen, natural gas or coal gas.21. The well system of any of paragraphs 15 to 20, wherein a thickness of the low permeability barrier is less than a thickness of the reservoir.

[0077] While the embodiments described herein are well-calculated to achieve the advantages set forth, it will be appreciated that such embodiments are susceptible to modification, variation, and change without departing from the spirit thereof. In other words, the particular embodiments described herein are illustrative only, as the teachings of the present techniques may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Moreover, the systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and / or any optional element disclosed herein. While compositions and methods are described in terms of “comprising” or “including” various components or steps, the compositions and methods can also “consist essentially of’ or “consist of’ the various components and steps. Indeed, the presenttechniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Claims

CLAIMSWhat is claimed is:

1. A method of storing gas in a subsurface region of a hydrocarbon reservoir or saline formation, the method comprising: injecting a barrier-forming solution into the subsurface region; injecting a driving solution into the subsurface region, the driving solution driving the barrier-forming solution to form a low permeability barrier bounded on the top by caprock; and injecting a gas into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the barrier.

2. The method of claim 1, wherein the barrier-forming solution comprises a system with controllable setting and hardening time that is resistant to degradation under subsurface conditions.

3. The method of claim 1, wherein the barrier-forming solution has a viscosity greater than brine in the subsurface region to reduce viscous fingering.

4. The method of claim 1, wherein the driving solution has a viscosity greater than a viscosity of the barrier-forming solution prior to setting and hardening.

5. The method of claim 1, wherein the driving solution degrades in in a degradation time period under subsurface conditions, so that the driving solution acts to form the barrier-forming solution into the low permeability barrier prior to degradation.

6. The method of claim 1, wherein the gas comprises greenhouse gasses (GHG)s including carbon dioxide (CO2), hydrogen, natural gas or coal gas.

7. The method of claim 1, wherein a thickness of the low permeability barrier is less than a thickness of the reservoir.

8. A well system for storing gas in a subsurface region of a hydrocarbon reservoir or salineformation, the well system comprising: an injection well; a barrier-forming solution that is injected into the subsurface region through the injection well; a driving solution that is injected into the subsurface region through the injection well, the driving solution driving the barrier-forming solution to form a low permeability barrier bounded on the top by caprock; and a gas that is injected into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the low permeability barrier.

9. The well system of claim 8, wherein the barrier-forming solution comprises a system with controllable setting and hardening time that is resistant to degradation under subsurface conditions.

10. The well system of claim 8, wherein the barrier-forming solution has a viscosity greater than brine in the subsurface region to reduce viscous fingering.

11. The well system of claim 8, wherein the driving solution has a viscosity greater than a viscosity of the barrier-forming solution prior to setting and hardening.

12. The well system of claim 8, wherein the driving solution degrades in a degradation time period under subsurface conditions, so that the driving solution acts to form the barrier-forming solution into the low permeability barrier prior to degradation.

13. The well system of claim 8, wherein the gas comprises greenhouse gases (GHGs) including carbon dioxide (CO2), hydrogen, natural gas or coal gas.

14. The well system of claim 8, wherein a thickness of the low permeability barrier is less than a thickness of the reservoir.

15. A well system for storing gas in a subsurface region of a hydrocarbon reservoir or saline formation, the well system comprising: an injection well;a barrier-forming solution that is injected into the subsurface region through the injection well; a driving solution that is injected into the subsurface region through the injection well, the driving solution driving the barrier-forming solution to form a low permeability barrier bounded on the top by caprock; a gas that is injected into the subsurface region, the gas being stored under the caprock and within a gas storage region formed by the low permeability barrier; and a computing system that computes an optimized composition and size of the low permeability barrier and controls the injection of the barrier-forming solution, the driving solution and the gas into the subsurface region.

16. The well system of claim 15, wherein the barrier-forming solution comprises a system with controllable setting and hardening time that is resistant to degradation under subsurface conditions.

17. The well system of claim 15, wherein the barrier-forming solution has a viscosity greater than brine in the subsurface region to reduce viscous fingering.

18. The well system of claim 15, wherein the driving solution has a viscosity greater than a viscosity of the barrier-forming solution prior to setting and hardening.

19. The well system of claim 15, wherein the driving solution degrades in a degradation time period under subsurface conditions, so that the driving solution acts to form the barrier forming solution into the low permeability barrier prior to degradation.

20. The well system of claim 15, wherein the gas comprises greenhouse gases (GHGs) including carbon dioxide (CO2), hydrogen, natural gas or coal gas.

21. The well system of claim 15, wherein a thickness of the low permeability barrier is less than a thickness of the reservoir.

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