Preventing hydrate formation during water-alternating-gas (WAG) injection

Abstract

A method for switching from gas injection to water injection during water-alternating-gas (WAG) injection is provided to substantially prevent the formation of hydrates within the corresponding injection well. The method includes injecting gas into a fluid column of the injection well and injecting a gas-miscible organic solvent into the fluid column, forming a gas-miscible organic solvent layer within the fluid column. The method also includes injecting methanol into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer. The method further includes injecting water into the fluid column, where the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer.

Description

Preventing Hydrate Formation During Water-Alternating-Gas (WAG) Injection CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims priority to and the benefit of U.S. Provisional Application No. 63 / 606,987, entitled “PREVENTING HYDRATE FORMATION DURING WATER- ALTERNATING-GAS (WAG) INJECTION,” having a filing date of December 6, 2023, the disclosure of which is incorporated herein by reference in its entirety. FIELD OF THE INVENTION

[0002] The techniques described herein relate to the field of enhanced oil recovery (EOR) and related flow assurance considerations. More specifically, the techniques described herein relate to methods for preventing hydrate formation during water-alternating-gas (WAG) injection. 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] Water-alternating-gas (WAG) injection is a cyclic process of injecting alternating water and gas into a reservoir via one or more injection wells. WAG injection is often utilized in enhanced oil recovery (EOR) applications to increase the estimated ultimate recovery (EUR) from the reservoir by enhancing the reservoir sweep efficiency. During such WAG injection, fluid swaps occur, in which the injection wells switch from gas injection to water injection, or vice versa. However, during the fluid swap from gas to water for injection wells in subsea developments, the reduced temperatures and elevated pressures within the subsea environment often cause water molecules to encage gas molecules upon contact, forming solid crystalline composites that are referred to as “hydrates.” Such hydrates may then form obstructions within the injection wells and / or the equipment associated with the injection wells, resulting in shutdowns and other operational problems. SUMMARY OF THE INVENTION

[0005] An embodiment described herein provides a method for switching from gas injection to water injection during water-alternating-gas (WAG) injection. The method includes injecting gasinto a fluid column of an injection well as part of a WAG injection process and injecting a gas- miscible organic solvent into the fluid column, forming a gas-miscible organic solvent layer within the fluid column. The method also includes injecting methanol into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer. The method further includes injecting water into the fluid column, where the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer.

[0006] Another embodiment described herein provides a method for switching from gas injection to water injection for an injection well during WAG injection for multiple injection wells that are connected to the same flowline. The method includes simultaneously performing a WAG injection process for multiple injection wells connected to the same flowline. The method also includes performing the following for one of the injection wells without shutting in any of the other injection wells connected to the same flowline: injecting gas into a fluid column of the injection well; injecting a gas-miscible organic solvent into the fluid column, forming a gas-miscible organic solvent layer within the fluid column; injecting methanol into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer; and injecting water into the fluid column, where the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer.

[0007] 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

[0008] 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:

[0009] FIG.1 is a cross-sectional schematic view depicting the change within the fluid column of an injection well over time during a fluid swap operation for transitioning from gas injection to water injection during a conventional WAG injection process;

[0010] FIG.2 is a cross-sectional schematic view depicting the change within the fluid column of an injection well over time during a fluid swap operation for transitioning from gas injection to water injection during a WAG injection process in accordance with the present techniques;

[0011] FIG.3 is a simplified schematic view of a subsea hydrocarbon field in which a WAG injection process may be performed in accordance with the present techniques; and

[0012] FIG.4 is a process flow diagram of an exemplary method for switching from gas injection to water injection during a WAG injection process in accordance with the present techniques.

[0013] 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

[0014] 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.

[0015] 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.

[0016] 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.

[0017] The terms “about” and “around” mean a relative amount of a material or characteristic that is sufficient to provide the intended effect. The exact degree of deviation allowable in some cases may depend on the specific context, e.g., ±1%, ±5%, ±10%, ±15%, etc. It should be understood by those of skill in the art that these terms are intended to allow a description of certainfeatures described and claimed without restricting the scope of these features to the precise numerical ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described are considered to be within the scope of the disclosure.

[0018] 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.

[0019] As used herein, the term “any” means one, some, or all of a specified entity or group of entities, indiscriminately of the quantity.

[0020] 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,” “oneor 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.

[0021] 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.”

[0022] The term “enhanced oil recovery (EOR)” refers to processes for enhancing the recovery of hydrocarbons from subterranean reservoirs through the introduction of materials not naturally occurring in the reservoir. Moreover, as used herein the term “enhanced oil recovery (EOR)” is intended to be inclusive of the term “improved oil recovery (IOR),” which refers to similar processes for improving the recovery of hydrocarbons from subterranean reservoirs, such as, in particular, injecting fluids into subterranean reservoirs to modify the properties of the oil within such reservoirs and thereby increase oil recovery from the reservoirs.

[0023] As used herein, the terms “example,” exemplary,” and “embodiment,” when used with reference to one or more components, features, structures, or methods according to the present techniques, are intended to convey that the described component, feature, structure, or method is an illustrative, non-exclusive example of components, features, structures, or methods according to the present techniques. Thus, the described component, feature, structure, or method is not intended to be limiting, required, or exclusive / exhaustive; and other components, features, structures, or methods, including structurally and / or functionally similar and / or equivalent components, features, structures, or methods, are also within the scope of the present techniques.

[0024] As used herein, the term “fluid” refers to gases and liquids, as well as to combinations of gases and liquids, combinations of gases and solids, combinations of liquids and solids, and combinations of gases, liquids, and solids.

[0025] As used herein, the term “gas,” when used with reference to a WAG injection process, is intended to encompass any hydrate-forming constituent that may be utilized as a part of the WAG injection process, where the term “hydrate-forming constituent” refers to a compound or molecule in petroleum fluids, including natural gas, that forms hydrates at elevated pressures and / or reduced temperatures. Illustrative hydrate-forming constituents include, but are not limited to, hydrocarbons such as methane, ethane, propane, butane, neopentane, ethylene, propylene, isobutylene, cyclopropane, cyclobutane, cyclopentane, cyclohexane, and benzene, among others. Hydrate-forming constituents can also include non-hydrocarbons, such as oxygen, nitrogen, hydrogen sulfide, carbon dioxide, sulfur dioxide, and chlorine, among others.

[0026] A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, the term “hydrocarbon” generally refers to components found in raw natural gas and oil.

[0027] The term “natural gas” refers to a multi-component gas that may be obtained from a subterranean reservoir. The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (CH4) as a significant component. Raw natural gas will also typically contain ethylene (C2H4), ethane (C2H6), other hydrocarbons, one or more acid gases (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon disulfide, and mercaptans), and minor amounts of contaminants such as water, nitrogen, iron sulfide, wax, and crude oil.

[0028] The term “substantially,” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may depend, in some cases, on the specific context.

[0029] 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 “well”) includes the wellbore in addition to the wellhead and other associated surface equipment.

[0030] Certain embodiments and features are described herein using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated. All numerical values are “about” or “approximately” the indicated value, and account for experimental errors and variations that would be expected by those skilled in the art.

[0031] Furthermore, concentrations, dimensions, amounts, and / or other numerical data that are presented in a range format are to be interpreted flexibly to include not only the numerical values explicitly recited as the limits of the range, but also all individual numerical values or sub-ranges encompassed within that range, as if each numerical value and sub-range were explicitly recited. For example, a disclosed numerical range of 1 to 200 should be interpreted to include, not only theexplicitly-recited limits of 1 and 200, but also individual values, such as 2, 3, 4, 197, 198, 199, etc., as well as sub-ranges, such as 10 to 50, 20 to 100, etc.

[0032] As described above, hydrates are prone to form during the fluid swap from gas to water for WAG injection processes implemented in subsea developments. As a result, current WAG injection techniques typically involve pumping methanol ahead of the water to ensure that the gas is fully displaced from the injection well before water injection is initiated. This is performed due to the fact that increased methanol concentration in a water-methanol mixture increases the temperature at which hydrates can form when gas is present. This process is illustrated by FIG. 1, which is a cross-sectional schematic view depicting the change within the fluid column of an injection well 100 over time during a fluid swap operation for transitioning from gas injection to water injection during a conventional WAG injection process. As shown in FIG.1, at a first time 102, the WAG injection process is in a gas injection phase, and the fluid column includes only (or substantially only) gas. At a second time 104, the fluid swap operation begins with the pumping of methanol into the fluid column. At a third time 106, the methanol that has been pumped into the fluid column begins to mix with the gas within the injection well. At a fourth time 108, the mixing of the methanol and the gas continues, with gas bubbles beginning to form within the methanol layer. At a fifth time 110, additional gas bubbles continue to form within the methanol layer. At a sixth time 112, a portion of the gas bubbles float to the top of the methanol layer, meaning that gravity swapping has occurred between a portion of the gas and a portion of the methanol within the fluid column. At a seventh time 114, an entire gas layer has formed above the methanol layer. As a result, when water injection begins at an eighth time 116, the gas mixes with the water at low temperatures and high pressures, forming hydrates within the injection well, as shown in FIG.1.

[0033] In an attempt to avoid the formation of hydrates during a gas-to-water fluid swap as shown in FIG. 1, current WAG injection techniques typically rely on the rapid pumping of methanol through the flowline to adequately displace the lighter gas phase. However, to achieve this, the entire injection process has suspended for a period of time (e.g., around twelve hours) to enable the methanol to be loaded within the flowline, meaning that every injection well that is connected to the flowline has to be temporarily shut-in to enable the fluid swap operation to be performed for a single injection well. In addition to wasting time, the shut-in of all the injection wells at once negatively impacts pressure maintenance efforts, leads to the impairment of the injection wells that have been left idle, and requires significant coordination by the operational staff.

[0034] Accordingly, the present techniques provide methods for preventing hydrate formation during a WAG injection process. More specifically, the present techniques provide methods for performing a gas-to-water fluid swap operation for an injection well at a relatively low injection rate, thus enabling the WAG injection process to be continued for injection wells that are connected to the same flowline. This is accomplished, at least in part, by providing smooth density gradients between the fluids during the fluid swap operation, where such smooth density gradients slow the buoyant swapping of fluids, regardless of gravity stability. More specifically, according to embodiments described herein, the method includes pumping a gas-miscible organic solvent, such as xylene, into the fluid column of an injection well, providing a smooth density gradient between the gas and the gas-miscible organic solvent. Methanol is then pumped into the fluid column. Due to the density contrast between the gas-miscible organic solvent and the methanol, the methanol remains gravity stable above the gas-miscible organic solvent, thus preventing gravity swapping. Water injection is then initiated. Because water is miscible with methanol, a smooth density gradient exists between the methanol and the water. In this manner, the gas-to-water fluid swap operation is performed without any substantial contact between the gas and the water. As a result, the present techniques prevent or hinder (or substantially prevent or substantially hinder) the formation of hydrates within the fluid column during the switch from gas injection to water injection, even at relatively low injection rates. Therefore, the present techniques provide for highly-efficient displacement of fluids from an injection well at low injection rates and without having to shut-in any other injection wells that are connected to the same flowline.

[0035] This is illustrated by FIG.2, which is a cross-sectional schematic view depicting the change within the fluid column of an injection well 200 over time during a fluid swap operation for transitioning from gas injection to water injection during an exemplary WAG injection process in accordance with the present techniques. As shown in FIG.2, at a first time 202, the fluid column includes only gas since the WAG injection process is in a gas injection phase. At a second time 204, the fluid swap operation begins with the pumping of xylene (and / or another suitable gas-miscible organic solvent) into the fluid column. In various embodiments, the xylene is pumped at a relatively low injection rate. As a non-limiting example, in some embodiments, the xylene injection rate is in a range between around 1 cubic meter per hour (m3 / hr) and around 5 m3 / hr, or in a range between around 0.5 m3 / hr and around 8 m3 / hr. Moreover, in various embodiments, the volume of xylene to be pumped, as well as the injection rate for pumping such xylene, is determined (at least in part) based on the size of the wellbore and the volume of gas that is to be displaced from the wellbore.

[0036] At a third time 206, the xylene (with a density of around 880 kilograms per cubic meter (kg / m3), for example) begins to mix with the gas (with a density of around 380 kg / m3, for example), forming a gas / xylene mixture between the gas layer and the xylene layer within the fluid column. At a fourth time 208, the pumping of the xylene is continued, forming an uninterrupted layer of xylene within the fluid column. At a fifth time 210, the pumping of methanol (with a density of around 792 kg / m3, for example) is initiated. In various embodiments, the volume of methanol to be pumped, as well as the injection rate for pumping such methanol, is determined (at least in part) based on the size of the wellbore and the volume of gas that is to be displaced from the wellbore.

[0037] Due to the density contrast between the xylene and the methanol, the methanol remains gravity stable above the xylene (i.e., without gravity swapping), as shown in FIG.2. At a sixth time 212, the injection of water (with a density of around 1015 kg / m3, for example) begins. Because the water is miscible with the methanol, a methanol / water mixture forms between the methanol layer and the water layer within the fluid column. At a seventh time 214, the xylene layer and the methanol layer move through the fluid column ahead of the water, providing a smooth density gradient that substantially prevents contact between the gas and the water during the gas-to-water fluid swap operation. Finally, at an eighth time 216, the injection well has transitioned to a water injection phase without (or substantially without) the formation of hydrates. Moreover, the gas-to- water fluid swap operation may be performed at low injection rates without the necessity of shutting in other injection wells connected to the same flowline.

[0038] The cross-sectional schematic view of FIG.2 is provided as an exemplary implementation of the present techniques and is not intended to indicate that the present techniques are limited to the specific implementation depicted in FIG. 2. Therefore, modifications may be made in accordance with the details of each specific implementation, while still providing the same technical effect.

[0039] FIG.3 is a simplified schematic view of an exemplary subsea hydrocarbon field 300 in which a WAG injection process may be performed in accordance with the present techniques. As shown in FIG. 3, the subsea hydrocarbon field 300 includes a number of wellheads 302 coupled to injection wells 304 that are configured to inject alternating water and gas into a reservoir 306. The wellheads 302 are located on the ocean floor 308. Each injection well 304 may include single wellbores or multiple, branch wellbores. Each wellhead 302 is coupled to a central flowline 310 by gathering flowlines 312. In some embodiments, the central flowline 310 continues through the field 300, coupling to further wellheads (not shown). A flexible flowline 314 couples the central flowline310 to a surface facility 316 at the ocean surface 318. The surface facility 316 may be, for example, a floating processing station, such as a floating storage and offloading unit (FSO) or a floating production storage and offloading unit (FPSO), which may be anchored to the ocean floor 308 by a number of tethers 320. The surface facility 316 may also be a drilling platform that includes drilling equipment, such as a tower or derrick 322. The surface facility 316 may transport processed hydrocarbons to shore facilities by pipeline (not shown).

[0040] In some embodiments, production fluids from a wellhead (not shown) or manifold (not shown) are flowed into a separation system 324 through the flexible flowline 314. Within the separation system 324, the production fluids are separated into a liquid stream and a gas stream. The liquid stream may then be sent to the surface facility 316 via a flexible flowline 326.

[0041] The gas that is separated from the production fluids is flowed into a WAG injection system 328 via the central flowline 310. In addition, in some embodiments, water is obtained from an aquifer 330 via a flowline 332 and then injected into the WAG injection system 328. In other embodiments, water is injected into the WAG injection system 328 from any number of other sources. For example, local seawater that has been treated and processed at a facility may be injected into the WAG injection system 328 via a flexible flowline 334.

[0042] The WAG injection system 328 causes alternating water and gas to be injected into the reservoir 306 via the injection wells 304. Moreover, according to embodiments described herein, the WAG injection system 328 advantageously prevents or hinders (or substantially prevents or substantially hinders) the formation of hydrates during the fluid swap from gas to water within each injection well 304 by first injecting a gas-miscible organic solvent (e.g., xylene) into the gas column within the injection well 304, resulting in the formation of a gas / solvent mixture with a smooth density gradient. Next, the WAG injection system 328 injects methanol into the liquid column within the injection well 304. The methanol remains gravity stable above the gas-miscible organic solvent due to the density contrast. The WAG injection system 328 then initiates water injection. Because the water is miscible with the methanol, a methanol / water mixture with a smooth density gradient forms. As a result, the water and gas remain clearly separated within the wellbore during the transition from gas to water.

[0043] The simplified schematic view of FIG.3 is only provided as an exemplary embodiment of a subsea hydrocarbon field 300 that may be utilized according to embodiments described herein. However, in practice, the configuration and / or composition of the subsea hydrocarbon field may vary depending on the details of the particular implementation.

[0044] FIG.4 is a process flow diagram of an exemplary method 400 for switching from gas injection to water injection during a WAG injection process in accordance with the present techniques. The method is executed via a WAG injection system and connected injection well, which may form part of a subsea hydrocarbon field. The exemplary method 400 begins at block 402, at which gas is injected into the fluid column of the injection well during the injection process (e.g., during a gas injection phase of the WAG injection process).

[0045] The gas-to-water fluid swap operation then begins at block 404 with the injection of a gas-miscible organic solvent, such as xylene, into the fluid column, forming a gas-miscible organic solvent layer within the fluid column. In various embodiments, this includes forming a mixture of the gas and the gas-miscible organic solvent, and the mixture provides a smooth density gradient between the gas and the gas-miscible organic solvent layer. Moreover, in some embodiments, the gas-miscible organic solvent is injected at an injection rate that is in a range between around 1 m3 / hr and around 5 m3 / hr, or in a range between around 0.5 m3 / hr and around 8 m3 / hr, for example. Furthermore, in various embodiments, the method 400 further includes determining an injection rate for injecting the gas-miscible organic solvent into the fluid column based on the size of the corresponding wellbore and the volume of gas that is to be displaced from the wellbore and then injecting the gas-miscible organic solvent in accordance with the determined injection rate.

[0046] At block 406, methanol is injected into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer. In some embodiments, the methanol is injected at an injection rate that is in a range between around 1 m3 / hr and around 5 m3 / hr, or in a range between around 0.5 m3 / hr and around 8 m3 / hr, for example. In addition, in various embodiments, the method 400 further includes determining an injection rate for injecting the methanol into the fluid column based on the size of the wellbore and the volume of gas that is to be displaced from the wellbore and then injecting the methanol in accordance with the determined injection rate.

[0047] The switch from gas injection to water injection is then completed at block 408. Specifically, at block 408, water is injected into the fluid column. In various embodiments, this includes forming a mixture of the methanol and the water, where the mixture provides a smooth density gradient between the methanol layer and the water. Moreover, at block 408, the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer (which remain substantially separated from each other within the fluid column). Therefore, the method 400 prevents or hinders (or substantially prevents or substantially hinders) the formation ofhydrates within the fluid column of the injection well, even for instances in which the gas-miscible organic solvent and / or the methanol are injected at relatively low injection rates.

[0048] The process flow diagram of FIG.4 is not intended to indicate that the method 400 is limited to the blocks shown. Rather, any number of additional blocks not shown in FIG.4 may be included within the method 400, depending on the details of the specific implementation . For example, in various embodiments, the method 400 is executed for one injection well out of a group of two or more injection wells that are connected to the same flowline (or the same WAG injection system). In such embodiments, the WAG injection process is simultaneously performed for all the injection wells, and the method 400 is then executed for one of the injection wells without shutting in any of the other injection wells.

[0049] In various embodiments, the specific properties of the various fluids are taken into account when determining suitable injection rates and volumes for injecting the fluids into the fluid column. For example, the densities of the gas-miscible organic solvent and the methanol, as well as potentially the density differences between the gas-miscible organic solvent and the methanol, may be used (potentially along with the size of the wellbore and / or the volume of gas that is to be displaced from the wellbore) to determine suitable injection rates and volumes such that the gas- miscible organic solvent and the methanal form the desired layers within the fluid column. Accordingly, the injection rate for the gas-miscible organic solvent (and potentially the injection rate for the methanol as well) may vary depending on whether xylene or another suitable type of gas- miscible organic solvent is utilized.

[0050] It should be noted that term “layer,” when used herein with reference to the gas-miscible organic solvent layer and the methanol layer, is not intended to indicate that such layers of fluid remain entirely separated from one another. Rather, some amount of mixing or intermingling is expected. However, the bulk of fluid within each layer will remain substantially separated from the fluid within the other layer such that identifiable layers are formed.

[0051] In some embodiments, the present techniques may also be applied to the stimulation of carbonate gas wells. In particular, the fluid swap methodology described herein may be utilized to provide enhanced stimulation of carbonate gas wells by increasing the efficiency of the fluid flow during the stimulation process.

[0052] In various embodiments, the present techniques may be susceptible to various modifications and alternative forms, such as the following embodiments noted in paragraphs 1 to17:1. A method for switching from gas injection to water injection during WAG injection, including: injecting gas into a fluid column of an injection well as part of a WAG injection process; injecting a gas-miscible organic solvent into the fluid column, forming a gas-miscible organic solvent layer within the fluid column; injecting methanol into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer; and injecting water into the fluid column, where the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer. 2. The method of paragraph 1, where the gas-miscible organic solvent includes xylene. 3. The method of paragraph 1 or 2, including injecting the gas-miscible organic solvent at an injection rate that is in a range between 1 m3 / hr and 5 m3 / hr. 4. The method of any of paragraphs 1 to 3, including injecting the methanol at an injection rate that is in a range between 1 m3 / hr and 5 m3 / hr. 5. The method of any of paragraphs 1 to 4, where injecting the gas-miscible organic solvent into the fluid column further includes forming a mixture of the gas and the gas-miscible organic solvent, and where the mixture provides a smooth density gradient between the gas and the gas-miscible organic solvent layer. 6. The method of any of paragraphs 1 to 5, where injecting the water into the fluid column further includes forming a mixture of the methanol and the water, and where the mixture provides a smooth density gradient between the methanol layer and the water. 7. The method of any of paragraphs 1 to 6, including simultaneously performing a WAG injection process for at least one other injection well that is connected to a same flowline without shutting in the at least one other injection well during the injection of the gas, the injection of the gas-miscible organic solvent, the injection of the methanol, or the injection of the water into the fluid column of the injection well. 8. The method of any of paragraphs 1 to 7, including determining an injection rate for injecting the gas-miscible organic solvent into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the gas-miscible organic solvent in accordance with the determined injection rate. 9. The method of any of paragraphs 1 to 8, including determining an injection rate for injecting the methanol into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the methanol in accordance with the determined injection rate.10. A method for switching from gas injection to water injection for an injection well during WAG injection for multiple injection wells connected to a same flowline, including: simultaneously performing a WAG injection process for multiple injection wells connected to a same flowline; and performing the following for one of the injection wells without shutting in any of the other injection wells connected to the same flowline: injecting gas into a fluid column of the injection well; injecting a gas-miscible organic solvent into the fluid column, forming a gas-miscible organic solvent layer within the fluid column; injecting methanol into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer; and injecting water into the fluid column, where the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer. 11. The method of paragraph 10, where the gas-miscible organic solvent includes xylene. 12. The method of paragraph 10 or 11, including injecting the gas-miscible organic solvent at an injection rate that is in a range between 1 m3 / hr and 5 m3 / hr. 13. The method of any of paragraphs 10 to 12, including injecting the methanol at an injection rate that is in a range between 1 m3 / hr and 5 m3 / hr. 14. The method of any of paragraphs 10 to 13, where injecting the gas-miscible organic solvent into the fluid column further includes forming a mixture of the gas and the gas-miscible organic solvent, and where the mixture provides a smooth density gradient between the gas and the gas-miscible organic solvent layer. 15. The method of any of paragraphs 10 to 14, where injecting the water into the fluid column further includes forming a mixture of the methanol and the water, and where the mixture provides a smooth density gradient between the methanol layer and the water. 16. The method of any of paragraphs 10 to 15, including determining an injection rate for injecting the gas-miscible organic solvent into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the gas-miscible organic solvent in accordance with the determined injection rate. 17. The method of any of paragraphs 10 to 16, including determining an injection rate for injecting the methanol into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the methanol in accordance with the determined injection rate.

[0053] 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, andchange 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. Furthermore, no limitations are intended on the details of formulation, construction, or design shown herein, other than as described in the claims below. 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 present techniques include all alternatives, modifications, and equivalents falling within the true spirit and scope of the appended claims.

Claims

CLAIMS What is claimed is:

1. A method for switching from gas injection to water injection during water-alternating-gas (WAG) injection, comprising: injecting gas into a fluid column of an injection well as part of a WAG injection process; injecting a gas-miscible organic solvent into the fluid column, forming a gas-miscible organic solvent layer within the fluid column; injecting methanol into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer; and injecting water into the fluid column, wherein the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer.

2. The method of claim 1, wherein the gas-miscible organic solvent comprises xylene.

3. The method of claim 1, comprising injecting the gas-miscible organic solvent at an injection rate that is in a range between 1 cubic meter per hour (m3 / hr) and 5 m3 / hr.

4. The method of claim 1, comprising injecting the methanol at an injection rate that is in a range between 1 cubic meter per hour (m3 / hr) and 5 m3 / hr.

5. The method of claim 1, wherein injecting the gas-miscible organic solvent into the fluid column further comprises forming a mixture of the gas and the gas-miscible organic solvent, and wherein the mixture provides a smooth density gradient between the gas and the gas-miscible organic solvent layer.

6. The method of claim 1, wherein injecting the water into the fluid column further comprises forming a mixture of the methanol and the water, and wherein the mixture provides a smooth density gradient between the methanol layer and the water.

7. The method of claim 1, comprising simultaneously performing a WAG injection process for at least one other injection well that is connected to a same flowline without shutting in the at leastone other injection well during the injection of the gas, the injection of the gas-miscible organic solvent, the injection of the methanol, or the injection of the water into the fluid column of the injection well.

8. The method of claim 1, comprising: determining an injection rate for injecting the gas-miscible organic solvent into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the gas-miscible organic solvent in accordance with the determined injection rate.

9. The method of claim 1, comprising: determining an injection rate for injecting the methanol into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the methanol in accordance with the determined injection rate.

10. A method for switching from gas injection to water injection for an injection well during water-alternating-gas (WAG) injection for multiple injection wells connected to a same flowline, comprising: simultaneously performing a WAG injection process for multiple injection wells connected to a same flowline; and performing the following for one of the injection wells without shutting in any of the other injection wells connected to the same flowline: injecting gas into a fluid column of the injection well; injecting a gas-miscible organic solvent into the fluid column, forming a gas-miscible organic solvent layer within the fluid column; injecting methanol into the fluid column, forming a methanol layer within the fluid column that remains gravity stable above the gas-miscible organic solvent layer; and injecting water into the fluid column, wherein the water remains separated from the gas as a result of the gas-miscible organic solvent layer and the methanol layer.

11. The method of claim 10, wherein the gas-miscible organic solvent comprises xylene.

12. The method of claim 10, comprising injecting the gas-miscible organic solvent at an injection rate that is in a range between 1 cubic meter per hour (m3 / hr) and 5 m3 / hr.

13. The method of claim 10, comprising injecting the methanol at an injection rate that is in a range between 1 cubic meter per hour (m3 / hr) and 5 m3 / hr.

14. The method of claim 10, wherein injecting the gas-miscible organic solvent into the fluid column further comprises forming a mixture of the gas and the gas-miscible organic solvent, and wherein the mixture provides a smooth density gradient between the gas and the gas-miscible organic solvent layer.

15. The method of claim 10, wherein injecting the water into the fluid column further comprises forming a mixture of the methanol and the water, and wherein the mixture provides a smooth density gradient between the methanol layer and the water.

16. The method of claim 10, comprising: determining an injection rate for injecting the gas-miscible organic solvent into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the gas-miscible organic solvent in accordance with the determined injection rate.

17. The method of claim 10, comprising: determining an injection rate for injecting the methanol into the fluid column based on a size of a wellbore of the injection well and a volume of gas that is to be displaced from the wellbore; and injecting the methanol in accordance with the determined injection rate.

Images