Foam gel system for water plugging in subterranean areas

Abstract

A foam composition includes a foam stabilizer, a blowing agent, brine, and an inert gas. The foam stabilizer comprises graphene. The blowing agent comprises a viscoelastic surfactant. The inert gas is dispersed in the whole mixture of the foam stabilizer, the foaming agent and the saline water in the form of bubbles. The foam composition is configured to convert into a gel that is substantially impermeable to fluid flow in response to exposure to downhole conditions of a subterranean region.

Description

[0001] Priority claim

[0002] This application claims priority to U.S. patent application No. 17 / 871,688, filed on July 22, 2022, the entire contents of which are incorporated herein by reference. Technical Field

[0003] The present disclosure relates to water control in wellbore applications. In particular, in some embodiments, the present disclosure relates to a foam gel system that can block (or plug) water from entering a subterranean zone.

[0004] background

[0005] A common problem encountered in the process of extracting mineral hydrocarbons (e.g., crude oil and natural gas) from underground reservoirs is the co-extraction of water. Water is naturally present in oil and gas wells and reservoirs, for example, from lower aquifers or from injection wells, and can be mixed with the produced hydrocarbons and extracted together. The co-extraction of water and mineral hydrocarbons requires expensive separation, treatment and disposal, which in many cases requires re-injection back into the well. Water cut is the ratio of the amount of water produced from the production well to the total amount of the fluid produced. It is desirable to minimize the amount of water brought to the surface, that is, to minimize the water cut. In the hydrocarbon extraction process, water can enter the underground area in many ways, such as, for example, a wellbore or a reservoir, for example, through a porous rock layer such as a sedimentary layer or via a network of cracks or fissures connected to a water source or a gas source.

[0006] Overview

[0007] The present disclosure describes technologies related to water blocking in a subterranean region. Certain aspects of the described subject matter can be implemented as a foam composition. The foam composition comprises a foam stabilizer, a foaming agent, a brine, and an inert gas. The foam stabilizer comprises graphene. The foaming agent comprises a viscoelastic surfactant. The inert gas is dispersed in the form of bubbles throughout the mixture of the foam stabilizer, the foaming agent, and the brine. The foam composition is configured to transform into a gel that is substantially impermeable to fluid flow in response to exposure to downhole conditions in a subterranean region.

[0008] This aspect and other aspects may include one or more of the following features. In some embodiments, the foam stabilizer is in the range of about 0.7 weight / volume percentage (w / v %) to about 1.5 w / v % of the foam composition. In some embodiments, the foaming agent is in the range of about 5 volume percent (volume %) to about 15 volume % of the foam composition. In some embodiments, the brine is in the range of about 85 volume % to about 95 volume % of the foam composition. In some embodiments, the inert gas is nitrogen, and the foam amount of the foam composition is in the range of about 60% to about 70%. In some embodiments, the ratio of the inert gas to the mixture of the foam stabilizer, the foaming agent and the brine is in the range of about 3:7 to about 4:6. In some embodiments, the brine contains potassium chloride and has a salt concentration in the range of about 0.5 weight percent (wt %) to about 40 weight %. In some embodiments, the foaming agent is about 10.5 volume percent (volume %) of the foam composition. In some embodiments, the foam stabilizer comprises graphene nanoplatelets comprising 92 wt % carbon and 7 wt % oxygen.

[0009] Certain aspects of the described subject matter can be implemented as a method. A mixture of a foam stabilizer, a foaming agent, and brine is placed into a wellbore formed in a subterranean formation. The foam stabilizer comprises graphene. The foaming agent comprises a viscoelastic surfactant. An inert gas is placed into the wellbore. The inert gas is placed into the wellbore along with the mixture so that the inert gas is dispersed throughout the mixture as bubbles to form a foam within the wellbore. The foam is flowed to a designated downhole location in the subterranean formation, thereby exposing the foam to downhole temperatures, which causes the foam to convert into a gel that is substantially impermeable to fluid flow.

[0010] This aspect and other aspects may include one or more of the following features. In some embodiments, the mixture and the inert gas are mixed to form a foam before being placed in the wellbore, and the foam is placed in the wellbore. In some embodiments, additional inert gas is flowed into the wellbore together with the foam. In some embodiments, the foam stabilizer is in the range of about 0.7 weight / volume percentage (w / v %) to about 1.5 w / v % of the foam composition. In some embodiments, the foaming agent is in the range of about 5 volume percent (volume %) to about 15 volume % of the foam composition. In some embodiments, the brine is in the range of about 85 volume % to about 95 volume % of the foam composition. In some embodiments, the inert gas is nitrogen, and the foam amount of the foam composition is in the range of about 60% to about 70%. In some embodiments, the ratio of the mixture of the inert gas to the foam stabilizer, the foaming agent and the brine is in the range of about 3:7 to about 4:6. In some embodiments, the brine comprises potassium chloride and has a salt concentration in the range of about 0.5 weight percent (wt%) to about 40 weight percent. In some embodiments, the foaming agent is about 10.5 volume percent (volume %) of the foam composition. In some embodiments, the foam stabilizer comprises graphene nanoplatelets comprising 92 weight percent carbon and 7 weight percent oxygen.

[0011] Certain aspects of the described subject matter can be implemented as a method. A foam stabilizer, a foaming agent, brine, and nitrogen are mixed to form a foam. The foam stabilizer comprises graphene. The foaming agent comprises a viscoelastic surfactant. The foam is flowed together with additional nitrogen to a designated downhole location in a subterranean formation, thereby exposing the foam to downhole temperatures, which causes the foam to be converted into a gel that is substantially impermeable to the flow of aqueous fluids. After the foam has been converted to the gel, hydrocarbons are produced from the subterranean formation. The gel prevents leakage of the aqueous fluid from the designated downhole location, thereby preventing the aqueous fluid from being produced from the subterranean formation along with the hydrocarbons.

[0012] This aspect and other aspects may include one or more of the following features. In some embodiments, the foam stabilizer is in the range of about 0.7 weight / volume percentage (w / v %) to about 1.5 w / v % of the foam. In some embodiments, the foaming agent is in the range of about 5 volume percentage (volume %) to about 15 volume % of the foam. In some embodiments, the brine is in the range of about 85 volume % to about 95 volume % of the foam. In some embodiments, the foam amount of the foam is in the range of about 60% to about 70%. In some embodiments, the ratio of the nitrogen to the sum of the foam stabilizer, the foaming agent and the brine of the foam is in the range of about 3:7 to about 4:6. In some embodiments, the brine contains potassium chloride and has a salt concentration in the range of about 0.5 weight percent (wt %) to about 40 weight %. In some embodiments, the foaming agent is about 10.5 volume percent (volume %) of the foam. In some embodiments, the foam stabilizer contains graphene nanosheets, and the graphene nanosheets contain 92 weight % of carbon and 7 weight % of oxygen.

[0013] The details of one or more embodiments of the subject matter of the present disclosure are set forth in the drawings and the specification. Other features, aspects, and advantages of the subject matter will become apparent from the specification, drawings, and claims.

[0014] Description of the drawings

[0015] Figure 1A is a schematic diagram of an example well.

[0016] Figure 1B yes Figure 1A Schematic diagram of a well including a gel that has formed a plug that prevents water from flowing into the wellbore.

[0017] Figure 2 is a flow chart of an example method of plugging the flow of water into a wellbore.

[0018] Figure 3 is a flow chart of an example method of plugging the flow of water into a wellbore.

[0019] Figure 4 It is a graph of viscosity and time of two gels formed in different forms within a certain temperature range.

[0020] Details

[0021] The present disclosure describes a foam gel system. The foam gel system comprises a stabilizer (such as graphene), a foaming agent (such as a viscoelastic surfactant), an inert gas (such as nitrogen), and brine. The foam gel system can be used to inhibit and / or plug water flow in hydrocarbon production wells. The foam gel system can be pumped into a subterranean formation as a foam fluid, which can then be converted into a high viscosity gel in response to exposure to downhole temperatures (e.g., in the range of about 77 degrees Fahrenheit (℉) to about 200℉).

[0022] The subject matter described in the present disclosure can be implemented in specific embodiments to achieve one or more of the following advantages. The foam gel system can penetrate deeply into rock matrix and dense reservoirs to perform water plugging operations. The foam gel system has high mechanical strength and small volume, which can be used for fine-tuning placement of the foam gel system to plug water production in underground formations. Compared with conventional gel systems used in water plugging applications, the foam gel system is less destructive (e.g., to underground formations) and has lower costs. By adjusting the concentration of stabilizers and foaming agents present in the foam gel system, the viscosity and gelation time of the foam gel system can be adjusted and finely controlled to the desired level. The foam gel system can remain stable in harsh downhole environments, which can include high temperatures, high salinity, and high pH. Once the foam gel system has been converted to a gel, due to its high viscosity, the gel will not flow or be distributed along the underground formation. The foam gel system is versatile and can be converted to a gel over a wide temperature range (e.g., in the range of about 77°F to about 200°F).

[0023] Figure 1A An example well 100 constructed according to the concepts herein is depicted. The well 100 extends from the surface 106 through the earth 108 to one or more subsurface regions of interest 110 (as shown). The well 100 is capable of accessing the subsurface region of interest 110 to allow fluids to be recovered (i.e., produced) to the surface 106 (at Figure 1A108). In some embodiments, the underground area 110 is a formation within the earth 108 that defines a reservoir, but in other cases, the area 110 may be a plurality of formations or a portion of a formation. The underground area may include, for example, a formation, a portion of a formation, or a plurality of formations in a hydrocarbon-containing reservoir from which a recovery operation may be performed to recover captured hydrocarbons. In some embodiments, the underground area includes an underlying formation of natural fractures or porous rock containing hydrocarbons (e.g., oil, gas, or both). In some embodiments, the well may pass through other types of formations, including reservoirs with non-natural fractures. For simplicity, the well 100 is shown as a vertical well, but in other cases, the well 100 may be a deviated well with a wellbore deviating from the vertical direction (e.g., horizontal or inclined), the well 100 may include a plurality of holes forming a multi-branch well (i.e., a well having a plurality of branch wells that branch out to another well or a plurality of wells), or both.

[0024] In some embodiments, the well 100 is a gas well, which is used to produce hydrocarbon gas (such as natural gas) from the underground area 110 of interest to the surface 106. Although it is called a "gas well", the well does not need to produce only dry gas, but can occasionally or very small amounts of liquid containing oil, water, or both. In some embodiments, the well 100 is an oil well, which is used to produce hydrocarbon liquids (such as crude oil) from the underground area 110 of interest to the surface 106. Although it is called an "oil well", the well does not need to produce only hydrocarbon liquids, but can occasionally or very small amounts of gas, water, or both. In some embodiments, the production from the well 100 can be multiphase in any ratio. In some embodiments, the production from the well 100 may produce liquids mostly or entirely at certain times, and may produce gas mostly or entirely at other times. For example, in some types of wells, water is usually produced for a period of time to obtain gas in the underground area. However, the concepts herein are not limited to application to gas wells, oil wells, or even production wells, but may also be used in wells that produce other gas or liquid resources, or may be used in injection wells, disposal wells, or other types of wells for placing fluids into the earth.

[0025] The wellbore of the well 100 is typically, although not necessarily, cylindrical. All or a portion of the wellbore is lined with tubing, such as casing 112. The casing 112 is connected to the wellhead at the surface 106 and extends downhole into the wellbore. The function of the casing 112 is to separate the bore of the well 100, which is defined in the casing portion of the well 100 by an inner bore 116 of the casing 112, from the surrounding earth 108. The casing 112 can be formed from a single continuous pipe, or from multiple lengths of pipe connected end to end (e.g., threaded). In Figure 1A In a well 100, casing 112 is perforated in a subsurface zone of interest 110 to allow fluid communication between the subsurface zone of interest 110 and bores 116 of casing 112. In some embodiments, casing 112 is omitted or deactivated in the area of ​​subsurface zone of interest 110. The portion of well 100 that is not casing is often referred to as an "open hole."

[0026] The wellhead defines an attachment point for attaching other equipment to the well 100. For example, Figure 1A A well 100 is shown in production with a Christmas tree connected to the wellhead. The Christmas tree includes valves for regulating flow into or out of the well 100. In particular, casing 112 is commercially produced in a variety of common sizes specified by the American Petroleum Institute ("API"), including 4-1 / 2, 5, 5-1 / 2, 6, 6-5 / 8, 7, 7-5 / 8, 7-3 / 4, 8-5 / 8, 8-3 / 4, 9-5 / 8, 9-3 / 4, 9-7 / 8, 10-3 / 4, 11-3 / 4, 11-7 / 8, 13-3 / 8, 13-1 / 2, 13-5 / 8, 16, 18-5 / 8, and 20 inches, with the API specifying an inner diameter for each casing size.

[0027] A foam 150 may be placed into the well 100. The foam 150 is configured to transform into a gel (example shown in FIG. Figure 1B, and described in more detail later), the gel can form a plug to prevent fluid from flowing from the subterranean zone and into the wellbore of the well 100 (e.g., for water blocking). The foam 150 is configured to transform into a gel in response to exposure to downhole conditions of the subterranean zone. For example, the foam 150 can be configured to become a gel (that is substantially impermeable to fluid flow) in response to exposure to downhole temperatures in the range of about 77°F to about 200°F, about 80°F to about 200°F, about 90°F to about 200°F, about 100°F to about 200°F, about 110°F to about 200°F, about 120°F to about 200°F, about 130°F to about 200°F, about 140°F to about 200°F, about 150°F to about 200°F, about 160°F to about 200°F, about 170°F to about 200°F, about 180°F to about 200°F, or about 190°F to about 200°F.

[0028] The foam 150 comprises a foam stabilizer 150a, a foaming agent 150b, a salt solution 150c and an inert gas 150d. The foam stabilizer 150a comprises graphene. The foaming agent 150b comprises a viscoelastic surfactant (VES). A viscoelastic surfactant is a surfactant having viscoelastic properties in an aqueous solution. Similar to conventional surfactants, a viscoelastic surfactant comprises a hydrophilic head group and a hydrophobic chain. However, viscoelastic surfactants exhibit viscoelastic properties, which are attributed to their ability to form worm-like micelles and entangled structures by hydrophobic interactions, electrostatic interactions and hydrogen bond interactions in an aqueous solution. Viscoelasticity refers to the properties of a material that exhibits viscosity and elasticity simultaneously when undergoing deformation. When stress is applied, a viscous material linearly resists shear flow and strain over time. Elastic materials are strained when stretched, and quickly return to their initial state once stress is eliminated. Viscoelastic materials exhibit these two properties, and therefore exhibit time-dependent strain. The salt solution 150c is a salt solution. Inert gas 150d is dispersed in the form of bubbles in the entire mixture of foam stabilizer 150a, foaming agent 150b and brine 150c, thereby forming foam 150. Inert gas 150d can be, for example, nitrogen. In some embodiments, inert gas 150d is replaced by air. In some embodiments, the foam amount of foam 150 (i.e., the ratio of gas volume to foam volume (volume of gas and liquid), sometimes referred to as gas fraction) is in the range of about 60% to about 70%. In some embodiments, the ratio of inert gas 150d to the rest of foam 150 (foam stabilizer 150a, foaming agent 150b and brine 150c) is in the range of about 3:7 to about 4:6.

[0029] Graphene is a graphite or carbon atom arranged in a single layer of a honeycomb lattice. The graphene of foam stabilizer 150a can be in any form. For example, the graphene of foam stabilizer 150a can be in the form of graphene powder, graphene solution or graphene paste. In some embodiments, foam stabilizer 150a includes a composite material (i.e., a material with multiple components) containing graphene. For example, foam stabilizer 150a includes graphene oxide (GO, which includes carbon, oxygen and hydrogen) and / or reduced graphene oxide (rGO, which contains less oxygen and more carbon than GO). Foam stabilizer 150a can include, for example, very few layers of graphene (vFLG, which includes 1 to 3 layers of carbon), few layers of graphene (FLG, which includes 2 to 5 layers of carbon), and / or multilayer graphene (MLG, which includes 2 to 10 layers of carbon). In some embodiments, foam stabilizer 150a includes functionalized graphene. For example, functional groups can be added to graphene to add elements to the surface and / or edge of graphene for certain applications. In some embodiments, graphene is functionalized with N-(trimethoxysilylpropyl)ethylenediaminetriacetic acid (EDTA-silane) and / or poly(methyl methacrylate) (PMMA). In some embodiments, the hydroxyl groups (-OH) of graphene oxide (GO) are functionalized by esterification. For example, the esterification functionalization of the hydroxyl groups of GO includes reacting GO with nitrile and separating the reaction product by filtering and / or centrifugation. In some embodiments, GO is functionalized with poly-L-lactic acid (PLLA). In some embodiments, GO functionalized with PLLA is functionalized by esterification to synthesize a GO framework. For example, GO can be combined with 1,3-phenylenediboronic acid to form a borate ester. In this case, the monolayer GO sheets can be cross-linked together to form a three-dimensional porous network connected by phenylenediboronic acid columns. GO frameworks can have modifiable pore widths, volumes, and binding sites, which make them useful for gas storage and provide stability to foams. Similar to hydroxyl and epoxy groups, carbonyl groups can be functionalized with small molecule or polymer chemical linkers by activation and amidation or esterification. In some cases, graphene can be functionalized with biomolecules such as deoxyribonucleic acid (DNA), proteins, and enzymes.

[0030] Reducing the concentration of the foam stabilizer 150a in the foam 150 may increase the gelation time of the foam 150, may reduce the viscosity of the gel formed by the foam 150, and may reduce the stability of the gel formed by the foam 150. Increasing the concentration of the foam stabilizer 150a in the foam 150 may reduce the transmission rate of the fluid film between the liquid phase and the gas phase, may reduce the gelation time of the foam 150, may increase the viscosity of the gel formed by the foam 150, and may increase the stability of the gel formed by the foam 150. In some embodiments, the foam stabilizer 150a is in a range of about 0.7 weight / volume percent (w / v %) to about 1.5 w / v % of the foam 150.

[0031] Foaming agent 150b has low interfacial tension, high foaming ability, compatibility with formation water (i.e., soluble in formation water, unaffected by precipitated solids) and stability under downhole conditions (i.e., chemical inertness and resistance to thermal degradation). In some embodiments, foaming agent 150b has an interfacial tension in the range of about 20 millinewtons per meter (mN / m) to about 35 mN / m. Foaming ability refers to the amount or volume of foam formed under specified conditions (such as the method for forming foam, the temperature of the solution, the hardness of the water used, and / or the electrolyte content of the water used). In some embodiments, foaming agent 150b includes a cationic surfactant that carries a positive charge. Some examples of cationic surfactants include amine-based surfactants (such as trimethylamine hydrochloride and octenylamine dihydrochloride) and quaternary ammonium salts (such as hexadecylpyridinium chloride and benzethonium chloride). In some embodiments, foaming agent 150b includes an anionic surfactant that carries a negative charge. Anionic surfactants can include polar groups containing heteroatoms (such as oxygen, sulfur, phosphorus, silicon or nitrogen), which can be present in, for example, functional groups (such as alcohols, thiols, ethers, esters, acids, sulfates, sulfonates, phosphates, amines or amides). Anionic surfactants can include non-polar groups, such as hydrocarbon chains. Some examples of anionic surfactants include sodium dodecyl sulfate (SDS), alkyl ethylene oxide sulfates (e.g., sulfates with three ethylene oxide groups), alkyl benzene sulfonates (such as sodium dodecylbenzene), substituted sulfosuccinates (such as diethylhexyl sodium sulfosuccinate or dioctyl sodium sulfosuccinate), alkyl phosphates, salts of fatty acids and alpha-olefin sulfonates (AOS). In some embodiments, foaming agent 150b includes nonionic surfactants. Some examples of nonionic surfactants include fatty alcohol ethoxylates, alkylphenol ethoxylates and fatty acid alkoxylates. In some embodiments, the foaming agent 150b comprises an amphoteric surfactant comprising a molecular structure designated as an alkyl amphoacetate, an alkyl amphopropionate, or an alkyl iminopropionate. Some examples of amphoteric surfactants include alkyl amidopropylamine N-oxide (APAO), alkyl dimethylamine N-oxide (AO), alkyl betaine (Bt), alkyl amidopropyl betaine (APB), cocamidopropyl betaine, coconut oil amphoacetate, and coconut oil amphodiacetate. Reducing the concentration of the foaming agent 150b in the foam 150 can increase the gelation time of the foam 150, can reduce the viscosity of the gel formed by the foam 150, and can reduce the stability of the gel formed by the foam 150. Increasing the concentration of the foaming agent 150b in the foam 150 can reduce the gelation time of the foam 150, can increase the viscosity of the gel formed by the foam 150, and can increase the stability of the gel formed by the foam 150.In some embodiments, the blowing agent 150 b is in a range from about 5 volume percent (vol %) to about 15 vol % of the foam 150 .

[0032] Brine 150c can be prepared by mixing salt with water. For example, the brine of 150c can be an aqueous solution, which contains sodium chloride (NaCl), potassium chloride (KCl), calcium chloride (CaCl2), magnesium chloride (MgCl2), ammonium chloride (NH4Cl), calcium bromide (CaBr2), sodium bromide (NaBr), sodium formate (HCOONa), potassium formate (HCOOK) or any combination of these. In some embodiments, brine 150c is seawater or treated seawater (that is, seawater treated to change the properties of seawater, such as diluted seawater). The presence of one or more salts in brine 150c can reduce the volume of the gel formed by foam 150, and can reduce the stability of the gel formed by foam 150. However, the presence of one or more salts in brine 150c can also reduce the collapse rate of the gel formed by foam 150. Therefore, the salt concentration of brine 150c can be changed based on the desired properties of the gel formed by foam 150. The brine 150c can have a salt concentration in the following ranges: about 0.5 weight percent (wt %) to about 50 wt %, about 0.5 wt % to about 40 wt %, about 0.5 wt % to about 30 wt %, about 0.5 wt % to about 20 wt %, about 0.5 wt % to about 10 wt %, about 0.5 wt % to about 5 wt %, about 5 wt % to about 50 wt %, about 5 wt % to about 40 wt %, about 5 wt % to about 30 wt %, about 5 wt % to about 20 wt %, about 5 wt % to about 10 wt %, about 10 wt % to about 50 wt %, about 10 wt % to about 40 wt %, about 10 wt % to about 30 wt %, about 10 wt % to about 20 wt %, about 20 wt % to about 50 wt %, about 20 wt % to about 40 wt %, about 20 wt % to about 30 wt %, about 30 wt % to about 50 wt %, about 30 wt % to about 40 wt %, or about 40 wt % to about 50 wt %. In some embodiments, the brine 150c is an aqueous solution of NaCl and CaCl2. In some embodiments, the brine 150c is an aqueous solution of NaCl, CaCl2, and CaBr2. In some embodiments, the brine 150c is in the range of about 85% to about 95% by volume of the foam 150.

[0033] Figure 1B1 is a schematic diagram of a well 100, wherein the foam 150 has formed a gel 150', providing a plug that slows down and / or prevents water flow from entering the wellbore. The gel 150 is positioned at a downhole position in the well 100, and it is necessary to plug the aqueous fluid from the underground formation from this position so that the aqueous fluid will not leak into the wellbore of the well 100. Once formed, the gel 150' is substantially impermeable to fluid flow. The gel 150' prevents the aqueous fluid from being produced to the surface 106 along with the desired one or more hydrocarbons. In some embodiments, the gel 150' has a permeability of less than about 5,000 millidarcy (mD). For example, the gel 150' can have a permeability in the range of about 500 mD to about 5,000 mD. In some embodiments, the gel 150' has a compressive strength greater than about 7,000 Pascals (Pa). For example, the gel 150' can have a permeability in the range of about 7,000 Pa to about 10,000 Pa. In some embodiments, gel 150' has a viscosity greater than about 1,000 centipoise (cP).For example, gel 150' can have a viscosity in a range of about 1,000 cP to about 4,000 cP.

[0034] Figure 22 is a flow chart of an example method 200 for plugging water flow into a wellbore. At block 202, a mixture of a foam stabilizer (such as foam stabilizer 150a), a foaming agent (such as foaming agent 150b), and a brine (such as brine 150c) is placed in a wellbore (such as the wellbore of well 100) formed in an underground formation. As previously described, foam stabilizer 150a contains graphene, and foaming agent 150b contains a viscoelastic surfactant. At block 204, an inert gas (such as inert gas 150d) is placed in the wellbore. For example, the inert gas 150d placed in the wellbore at block 204 can be nitrogen. The mixture (placed in the wellbore at block 202) and the inert gas 150d (placed in the wellbore at block 204) can be placed in the wellbore together, so that the inert gas 150d is dispersed throughout the mixture as bubbles to form foam (such as foam 150) in the wellbore. In some embodiments, the mixture and the inert gas 150d are mixed before being placed in the wellbore at blocks 202 and 204, respectively. Mixing the mixture with the inert gas 150d can form a foam 150, and the foam 150 can be placed in the wellbore. At block 206, the foam 150 is flowed to a specified downhole location in the underground formation. In some embodiments, additional inert gas is flowed into the wellbore together with the foam 150. The specified downhole location in the underground formation is a location where water blocking is required in the underground formation. At block 206, the foam 150 is flowed to the specified downhole location, and the foam 150 is exposed to downhole temperatures, which converts the foam 150 into a gel (such as gel 150') that is impermeable to fluid flow (e.g., aqueous fluid flow). Once the gel 150' has been formed, water flow is prevented from entering the wellbore from the specified downhole location. Therefore, the gel 150' effectively blocks the water generation from the specified downhole location. In some embodiments, a cooling fluid (e.g., water) is flowed into the wellbore prior to starting the method 200 at block 202. Flowing the cooling fluid into the wellbore can reduce the downhole temperature in the well 100, which can slow the gelation time of the foam 150 to the gel 150'. Cooling the well 100 can be beneficial when the foam 150 requires additional time to penetrate into the subterranean formation to reach a target area (e.g., a water-forming area requiring water sealing) and then to convert to the gel 150'.

[0035] Figure 3300 is a flow chart of an example method 300 for plugging water flow into a wellbore. At block 302, a foam stabilizer (such as foam stabilizer 150a), a foaming agent (such as foaming agent 150b), a brine (such as brine 150c), and an inert gas (such as inert gas 150d) are mixed to form a foam (such as foam 150). As previously described, foam stabilizer 150a contains graphene, foaming agent 150b contains a viscoelastic surfactant, and inert gas 150d can be nitrogen. At block 304, foam 150 and additional inert gas 150d are flowed together to a specified downhole location in an underground formation. The specified downhole location in the underground formation is a location within the underground formation where water plugging is required. At block 304, foam 150 and additional inert gas 150d are flowed to the specified downhole location, and foam 150 is exposed to downhole temperature, which causes foam 150 to be converted into a gel (such as gel 150') that is impermeable to fluid flow (e.g., aqueous fluid flow). Once gel 150' has been formed, water flow is prevented from entering the wellbore from the specified downhole position. Therefore, gel 150' effectively blocks the water production from the specified downhole position. After foam 150 has been converted into gel 150', hydrocarbons are produced from the underground formation at block 306. Because gel 150' prevents aqueous fluid from leaking (flowing) from the specified downhole position, aqueous fluid is prevented from being produced from the underground formation together with the hydrocarbons at block 306. In some embodiments, before foam 150 and additional inert gas 150d are flowed into the specified downhole position in the underground formation at block 304, a cooling fluid (e.g., water) is flowed into the wellbore. Flowing a cooling fluid into the wellbore can reduce the downhole temperature in the well 100, which can slow down the gelation time of foam 150 being converted into gel 150'. Cooling the well 100 may be beneficial when the foam 150 requires additional time to penetrate into the subterranean formation to reach a target area (eg, a water formation area requiring water blocking) and then converts to the gel 150'. Example

[0036] The foam was prepared by bubbling nitrogen through a mixture of 0.7 grams of graphene (a mixture of hydrophilic monolayer and multilayer graphene nanosheets (92% carbon, 7% oxygen by weight)), 10.5 milliliters of a viscoelastic surfactant (Armovis EHS-W from Nouryon) and 30 grams of KCl in 100 milliliters of deionized water. The graphene was prepared by chemical vapor deposition. The graphene has a density of 0.41 grams per milliliter. The size of the bubbles in the generated foam was in the range of about 200 nanometers to about 300 nanometers and the average layer size was in the range of about 10 micrometers to about 20 micrometers. A control foam was also prepared using the same composition, but without the foam stabilizer (graphene) for comparison. Under ambient conditions, the control foam converted to a gel in about 2 days, while the foam containing graphene converted to a gel in about 90 minutes. Furthermore, the gel formed from the control foam remained stable without phase separation for about 10 days under ambient conditions, while the gel formed from the graphene-containing foam remained stable without phase separation for 35 days under ambient conditions.

[0037] The viscosity and thermal stability of the control foam and the graphene-containing foam were also measured and compared. Figure 4 4 is a graph 400 showing the measured viscosity and operating temperature versus time for the duration of the experiment for a control foam 410 and a foam containing graphene 420. As shown in graph 400, in response to exposure to a temperature of 200°F, the foam containing graphene 420 exhibits an increased viscosity compared to the control foam 410, indicating that a stronger gel is formed by the foam 420 compared to the control foam 410.

[0038] Although this specification contains many specific implementation details, these should not be interpreted as limitations on the scope of what may be claimed, but rather as descriptions of features of a particular implementation specified. Certain features described in this specification in the context of separate implementations may also be performed in combination in the form of a single implementation. Conversely, various features described in the context of a single implementation may also be performed separately in multiple implementations or in any sub-combination. In addition, although previously described features may be described as working in a certain combination and even initially claimed as such, in some cases, one or more features of the claimed combination may be deleted from the combination, and the claimed combination may be directed to a sub-combination or a variation of the sub-combination.

[0039] As used in this disclosure, the terms "a", "an" or "the" are used to include one or more than one (one or more than one) unless the context clearly indicates otherwise. The term "or" is used to refer to a non-exclusive "or" unless otherwise indicated. The expression "at least one of A and B" has the same meaning as "A, B, or A and B". In addition, it should be understood that the words or terms used in this disclosure and not otherwise defined are for descriptive purposes only and not for limitation. Any use of section headings is intended to aid in the reading of the document and should not be construed as limiting; information related to the section heading may appear inside or outside that particular section.

[0040] As used in this disclosure, the terms "about" or "approximately" may allow a certain degree of variation in a value or range, for example, within 10%, 5% or 1% of a stated value or limit of a stated range.

[0041] As used in this disclosure, the term "substantially" refers to a majority or majority, such as at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%, 97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

[0042] Values ​​expressed in the form of ranges should be interpreted in a flexible manner, including not only the values ​​explicitly listed as the limits of the range, but also all individual values ​​or sub-ranges contained within the range, as if each value and sub-range were explicitly listed. For example, the range of "0.1% to about 5%" or "0.1% to 5%" should be interpreted as including about 0.1% to about 5%, as well as individual values ​​(e.g., 1%, 2%, 3% and 4%) and sub-ranges (e.g., 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the specified range. The expression "X to Y" has the same meaning as "about X to about Y", unless otherwise stated. Similarly, the expression "X, Y or Z" has the same meaning as "about X, about Y or about Z", unless otherwise stated.

[0043] Specific embodiments of the subject matter have been described. It will be apparent to those skilled in the art that other embodiments, alternatives, and variations of the described embodiments are within the scope of the subsequent claims. Although operations are described in a particular order in the drawings or claims, it should not be understood as requiring that the operations be performed in the particular order shown or in sequential order, or that all of the operations shown (some operations may be considered optional) be performed to achieve the desired results. In some cases, multitasking or parallel processing (or a combination of multitasking and parallel processing) may be advantageous and is performed where deemed appropriate.

[0044] Furthermore, the separation or integration of various system modules and components in the aforementioned embodiments should not be understood as requiring such separation or integration in all embodiments, and it should be understood that the described components and systems can generally be integrated together or packaged into multiple products.

[0045] Therefore, the above example embodiments do not limit or restrict the present disclosure. Other changes, substitutions and replacements are also possible without departing from the spirit and scope of the present disclosure.

Claims

1. A foam composition, comprising: a foam stabilizer, wherein the foam stabilizer comprises graphene; a blowing agent, the blowing agent comprising a viscoelastic surfactant; Salt water; and an inert gas dispersed in the form of bubbles throughout the mixture of the foam stabilizer, the foaming agent, and the brine, wherein the foam composition is configured to transform into a gel that is substantially impermeable to fluid flow in response to exposure to downhole conditions in a subterranean zone.

2. The foam composition of claim 1, wherein the foam stabilizer is in the range of about 0.7 weight / volume percent (w / v %) to about 1.5 w / v % of the foam composition.

3. The foam composition of claim 2, wherein the blowing agent is in the range of about 5 volume percent (vol %) to about 15 volume % of the foam composition.

4. The foam composition of claim 3, wherein the saline is in the range of about 85% to about 95% by volume of the foam composition.

5. The foam composition of claim 4, wherein the inert gas is nitrogen and the foam amount of the foam composition is in the range of about 60% to about 70%.

6. The foam composition of claim 5, wherein the ratio of the inert gas to the mixture of the foam stabilizer, the foaming agent and the brine is in the range of about 3:7 to about 4:

6.

7. The foam composition according to claim 1, wherein: The brine comprises potassium chloride and has a salt concentration in a range from about 0.5 weight percent (wt %) to about 40 wt %; The blowing agent is about 10.5 volume percent (vol %) of the foam composition; and The foam stabilizer includes a plurality of graphene nanoplatelets, and the graphene nanoplatelets include 92 wt % carbon and 7 wt % oxygen.

8. A method comprising: placing a mixture of a foam stabilizer, a foaming agent, and brine into a wellbore formed in a subterranean formation, wherein the foam stabilizer comprises graphene and the foaming agent comprises a viscoelastic surfactant; placing an inert gas into the wellbore, wherein the inert gas is placed into the wellbore with the mixture so that the inert gas is dispersed as bubbles throughout the mixture to form a foam within the wellbore; and The foam is flowed to a designated downhole location in the subterranean formation, exposing the foam to downhole temperatures, which causes the foam to transform into a gel that is substantially impermeable to fluid flow.

9. The method of claim 8, wherein the mixture and the inert gas are mixed to form a foam prior to placement into the wellbore, and the foam is placed into the wellbore.

10. The method of claim 9, wherein additional inert gas is flowed into the wellbore along with the foam.

11. The method according to claim 8, wherein: The brine comprises potassium chloride and has a salt concentration in a range from about 0.5 weight percent (wt %) to about 40 wt %; The blowing agent is about 10.5 volume percent (vol %) of the foam; and The foam stabilizer includes a plurality of graphene nanoplatelets, and the graphene nanoplatelets include 92 wt % carbon and 7 wt % oxygen.

12. The method of claim 10, wherein the foam stabilizer is in the range of about 0.7 weight / volume percent (w / v %) to about 1.5 w / v % of the foam.

13. The method of claim 12, wherein the blowing agent is in the range of about 5 volume percent (vol %) to about 15 volume % of the foam.

14. The method of claim 13, wherein the saline is in the range of about 85% to about 95% by volume of the foam.

15. The method of claim 14, wherein the inert gas is nitrogen and the foam has a foam amount in a range of about 60% to about 70%.

16. The method of claim 15, wherein the ratio of the inert gas to the mixture of the foam stabilizer, the foaming agent, and the brine is in the range of about 3:7 to about 4:

6.

17. A method comprising: mixing a foam stabilizer, a foaming agent, saline, and nitrogen to form a foam, wherein the foam stabilizer comprises graphene, and the foaming agent comprises a viscoelastic surfactant; flowing the foam along with additional nitrogen gas to a designated downhole location in a subterranean formation, thereby exposing the foam to downhole temperatures, which causes the foam to transform into a gel that is substantially impermeable to the flow of aqueous fluids; and Hydrocarbons are produced from the subterranean formation after the foam has been converted to the gel, wherein the gel prevents aqueous fluids from escaping from the designated downhole location, thereby preventing the aqueous fluids from being produced from the subterranean formation along with the hydrocarbons.

18. The method of claim 17, wherein: The brine comprises potassium chloride and has a total dissolved solids level in a range from about 0.5 weight percent (wt %) to about 40 wt %; The blowing agent is about 10.5 volume percent (vol %) of the foam; and The foam stabilizer includes a plurality of graphene nanoplatelets, and the graphene nanoplatelets include 92 wt % carbon and 7 wt % oxygen.

19. The method of claim 17, wherein: The foam stabilizer is in the range of about 0.7 weight / volume percent (w / v %) to about 1.5 w / v % of the foam; The blowing agent is in the range of about 5 volume percent (vol %) to about 15 volume % of the foam; and The saline is in the range of about 85% to about 70% by volume of the foam.

20. The method of claim 19, wherein: The foam has a foam volume in the range of about 60% to about 70%; and The ratio of the nitrogen to the sum of the foam stabilizer, the foaming agent, and the brine of the foam is in the range of about 3:7 to about 4:6.

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