Patent Application
20180327652
Embodiments of the disclosure relate generally to methods of obtaining a hydrocarbon contained within a subterranean formation. More particularly, embodiments of the disclosure relate to methods of recovering a hydrocarbon material from a subterranean formation using nanoparticles and one or more anionic surfactants, and to related methods.
Water flooding is a conventional process of enhancing the extraction of hydrocarbon materials (e.g., crude oil, natural gas, etc.) from subterranean formations. In this process, an aqueous fluid (e.g., water, brine, etc.) is injected into the subterranean formation through injection wells to sweep a hydrocarbon material contained within interstitial spaces (e.g., pores, cracks, fractures, channels, etc.) of the subterranean formation toward production wells offset from the injection wells. One or more additives may be added to the aqueous fluid to assist in the extraction and subsequent processing of the hydrocarbon material.
For example, in some approaches, a surfactant or solid particles (e.g., colloids) are added to the aqueous fluid. The surfactant or the solid particles can adhere to or gather at interfaces between a hydrocarbon material and an aqueous material to form a stabilized emulsion of one of the hydrocarbon material and the aqueous material dispersed in the other of the hydrocarbon material and the aqueous material. Surfactants may decrease the surface tension between the hydrocarbon phase and the water phase, such as, for example, in an emulsion of a hydrocarbon phase dispersed within an aqueous phase. Stabilization by the surfactant or the solid particles may lower the interfacial tension between the hydrocarbon and the aqueous phase and reduce the energy of the system, preventing the dispersed material (e.g., the hydrocarbon material, or the aqueous material) from coalescing, and maintaining the one material dispersed as units (e.g., droplets) throughout the other material. Reducing the surface tension increases the permeability and the flowability of the hydrocarbon material. As a consequence, the hydrocarbon material may be more easily transported through and extracted from the subterranean formation as compared to water flooding processes that do not employ the addition of a surfactant or solid particles. The effectiveness of the emulsion is determined in large part by the ability of the emulsion to remain stable at wellbore conditions (e.g., high temperature, high salinity, etc.) and ensure mixing of the two phases.
However, application of surfactants is usually limited by the cost of the surfactants and their adsorption and loss onto the rock of the hydrocarbon-containing formation. Disadvantageously, the effectively of various surfactants can be detrimentally reduced in the presence of dissolved salts (e.g., such as various salts typically present within a subterranean formation). In addition, surfactants may have a tendency to adsorb onto surfaces of the subterranean formation, resulting in the economically undesirable addition of more surfactant to the injected aqueous fluid to account for such losses. Solid particles can be difficult to remove from the stabilized emulsion during subsequent processing, preventing the hydrocarbon material and the aqueous material thereof from coalescing into distinct, immiscible components, and greatly inhibiting the separate collection of the hydrocarbon material. Furthermore, the surfactants are often functional or stable only within particular temperature ranges and may lose functionality at elevated temperatures or various conditions encountered within a subterranean formation.
Embodiments disclosed herein include methods of recovering hydrocarbons from a subterranean formation. For example, in accordance with one embodiment, a method of recovering hydrocarbons from a subterranean formation comprises introducing a suspension comprising silica nanoparticles into a subterranean formation, contacting surfaces of the subterranean formation with the suspension to form a layer of the silica nanoparticles on at least some surfaces of the subterranean formation, after introducing the suspension comprising silica nanoparticles into the subterranean formation, introducing a solution comprising at least one anionic surfactant into the subterranean formation, and extracting hydrocarbons from the subterranean formation.
In additional embodiments, a method of recovering hydrocarbons from a subterranean formation comprises mixing silica nanoparticles having a diameter less than about 100 nm with a carrier fluid comprising brine and at least one anionic surfactant to form a suspension, introducing the suspension into a subterranean formation having a temperature greater than about 50° C., and extracting hydrocarbons from the subterranean formation.
In yet additional embodiments, a method of recovering hydrocarbons from a subterranean formation, comprises introducing a suspension comprising nanoparticles selected from the group consisting of silica and aluminum silicate into a subterranean formation, adhering the nanoparticles to surfaces within the subterranean formation, and after introducing the suspension comprising nanoparticles into the subterranean formation, introducing a solution comprising at least one anionic surfactant into the subterranean formation.
Illustrations presented herein are not meant to be actual views of any particular material, component, or system, but are merely idealized representations that are employed to describe embodiments of the disclosure.
The following description provides specific details, such as material types, compositions, material thicknesses, and processing conditions in order to provide a thorough description of embodiments of the disclosure. However, a person of ordinary skill in the art will understand that the embodiments of the disclosure may be practiced without employing these specific details. Indeed, the embodiments of the disclosure may be practiced in conjunction with conventional techniques employed in the industry. In addition, the description provided below does not form a complete process flow for recovering a hydrocarbon material from a subterranean formation. Only those process acts and structures necessary to understand the embodiments of the disclosure are described in detail below. A person of ordinary skill in the art will understand that some process components (e.g., pipelines, line filters, valves, temperature detectors, pH meters, flow detectors, pressure detectors, and the like) are inherently disclosed herein and that adding various conventional process components and acts would be in accord with the disclosure. Additional acts or materials to recover a hydrocarbon material from a subterranean formation may be performed by conventional techniques.
Act 102 may include mixing nanoparticles with a carrier fluid to form a first fluid comprising a suspension including nanoparticles dispersed in the carrier fluid. The carrier fluid may include water, brine, seawater, condensate, steam, etc., or combinations thereof. In some embodiments, the carrier fluid includes brine, such as may be encountered within a wellbore. By way of nonlimiting example, a concentration of salts in the carrier fluid may be between about 20 g salt/kg water and about 2,000 g salt/kg water, such as between about 20 g salt/kg water and about 50 g salt/kg water, between about 50 g salt/kg water and about 100 g salt/kg water, between about 100 g salt/kg water and about 500 g salt/kg water, between about 500 g salt/kg water and about 1,000 g salt/kg water, or between about 1,000 g salt/kg water and about 2,000 g salt/kg water. However, the disclosure is not so limited and the brine may have a different concentration of salt.
The nanoparticles may include nanoparticles that exhibit a negatively charged core, nanoparticles that include a negatively charged surface, nanoparticles including anionic functional groups formulated and configured to interact with active sites of a subterranean formation, and combinations thereof. By way of nonlimiting example, the nanoparticles may include silica nanoparticles, nanoparticles including a core comprising polyoctahedral silsesquioxane (POSS), metal nanoparticles (e.g., nanoparticles of one or more of iron, titanium, germanium, tin, lead, zirconium, ruthenium, nickel, cobalt, etc.), metal oxide nanoparticles (e.g., nanoparticles of one or more of oxides of iron, titanium, germanium, tin, lead, zirconium, ruthenium, nickel, cobalt, etc.), carbon nanoparticles (e.g., carbon nanotubes (e.g., single-walled carbon nanotubes (SWCNTs), multi-walled carbon nanotubes (MWCNTs), fullerenes, carbon nanodiamonds, graphene, graphene oxide), aluminum silicate nanoparticles, and combinations thereof. In some embodiments, the nanoparticles include silica nanoparticles, aluminum silicate nanoparticles, and a combination thereof. The aluminum silicate nanoparticles may include Al2SiO5 (Al2O3.SiO2), Al2Si2O5(OH)5 (Al2O3.2SiO2.2H2O), Al2Si2O7 (Al2O3.2SiO2), Al6SiO13 (3AlO3.2SiO2), Al4SiO8 (2Al2O3.SiO2), or combinations thereof.
Surfaces of the nanoparticles may be functionalized. By way of nonlimiting example, the nanoparticles may be functionalized with an alkyl group, an alkenyl group, an alkynyl group, a hydroxyl group, an organohalide group, a halide group, a carbonyl group, an amine group, an organosulfur group, an epoxy group, and a polyamine group, an aryl group (e.g., an aralkyl or an alkaryl group), a carbonyl group (a carbonyl group (—C═O)), such as a ketone, an aldehyde, a carboxylate (—COO−) group, an amine group, a thiol group, a phosphate (—PO43−) group, another functional group, or combinations thereof.
In some embodiments, surfaces of the nanoparticles may be functionalized with functional groups formulated and configured to provide a negative charge to the surface of the nanoparticles (e.g., anionic functional groups). By way of nonlimiting example, the anionic functional groups may include one or more of hydroxyl (—OH−) groups, carboxylate (—COO−) groups, sulfonate (—SO3−) groups, phosphate (—PO43−) groups, etc. In some embodiments, the functional groups may be formulated and configured to form nanoparticles formulated and configured to form a suspension having a negative zeta potential when mixed with the carrier fluid.
The functional group may be bonded directly to the core of the nanoparticle. In other embodiments, the functional group may be bonded to the core of the nanoparticle through one or more bridge groups (e.g., an R group, such as an alkyl group, an alkenyl group, an alkynyl group, a carbonyl group, an amine group, another group, or combinations thereof).
In some embodiments, at least some of the nanoparticles may be functionalized with at least a first type of functional group and at least some of the nanoparticles may be functionalized with at least a second type of functional group. By way of nonlimiting example, in some embodiments, at least some of the nanoparticles may be functionalized with sulfonate functional groups and at least some of the nanoparticles may be functionalized with carboxylate functional groups. As another example, at least some of the nanoparticles may be functionalized with phosphate groups and at least some of the nanoparticles may be functionalized with sulfonate groups or carboxylate groups. In yet other embodiments, at least some of the nanoparticles are functionalized with sulfonate groups, at least some of the nanoparticles are functionalized with phosphate groups, and at least some of the nanoparticles are functionalized with carboxylate groups. In other embodiments, at least some of the nanoparticles may not be functionalized and at least some of the nanoparticles may be functionalized.
The nanoparticles may include a hydrophobic coating on surfaces thereof (e.g., silica nanoparticles having a surface modified with a reactive epoxy silane), a hydrophilic coating on surfaces thereof (e.g., hydrophilic fumed silica, hydrophilic fumed silica including functionalized surfaces, or a combination thereof), or a combination thereof.
The nanoparticles may have a spherical shape, a cylindrical shape, a plate shape, or another suitable shape. In some embodiments, the nanoparticles have a spherical shape.
The nanoparticles may have a size between about 5 nm and about 100 nm. In some embodiments, the nanoparticles have a size between about 5 nm and about 10 nm, between about 10 nm and about 15 nm, between about 15 nm and about 20 nm, between about 20 nm and about 50 nm, or between about 50 nm and about 100 nm. The size of the nanoparticles may be selected to be less than a pore size of the subterranean formation. In some embodiments, the nanoparticles have a size less than about 100 nm, less than about 50 nm, less than about 20 nm, less than about 15 nm, less than about 10 nm, or even less than about 5 nm. The nanoparticles may be monodisperse, wherein each of the nanoparticles exhibit substantially the same size and shape, or may be polydisperse, wherein the nanoparticles include a range of sizes and/or shapes.
A concentration of the nanoparticles in the suspension may be between about 100 ppm and about 5,000 ppm, such as between about 100 ppm and about 200 ppm, between about 200 ppm and about 500 ppm, between about 500 ppm and about 1,000 ppm, between about 1,000 ppm and about 2,500 ppm, or between about 2,500 ppm and about 5,000 ppm. However, the disclosure is not so limited and the concentration of the nanoparticles in the suspension may be lower or higher depending on a particular application.
A pH of the suspension may be between about 3.0 and about 12.0. In some embodiments, the suspension may exhibit a basic pH, such as a pH greater than about 9.0, greater than about 10.0, or even greater than about 11.0. In other embodiments, the suspension may exhibit a pH between about 7.0 and about 9.0, such as about 8.0. In other embodiments, the suspension may exhibit an acidic pH, such as a pH between about 3.0 and about 7.0, such as between about 3.0 and about 5.0, or between about 5.0 and about 7.0. In some embodiments, the pH of the suspension may be about 3.0. However, the disclosure is not so limited and the suspension may exhibit a different pH.
In some embodiments, act 102 may be performed after primary hydrocarbon recovery and secondary hydrocarbon recovery. By way of nonlimiting example, act 102 may be performed after performing one or more of water flooding, steam flooding (e.g., steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), vapor extraction, etc.), or one or more other forms of secondary hydrocarbon recovery.
Act 104 may include a flooding process including introducing the first fluid into a subterranean formation and contacting surfaces of the subterranean formation with the nanoparticles to adsorb the nanoparticles on surfaces of the subterranean formation. Without wishing to be bound by any particular theory, it is believed that the nanoparticles interact with active sites of the subterranean formation and form a monolayer of nanoparticles thereon. It is believed that the nanoparticles may remove a hydrocarbon film from surfaces of the subterranean formation. In some embodiments, the nanoparticles may be formulated and configured to interact with active sites of surfaces of the subterranean formation. By way of nonlimiting example, the nanoparticles may include amine functional groups. The nanoparticles may adhere to and interact with (e.g., bond with) surfaces of the subterranean formation.
In some embodiments, act 104 may be performed after primary hydrocarbon recovery and secondary hydrocarbon recovery, such as one or more of water flooding and one or more other forms of secondary hydrocarbon recovery. In other embodiments, act 104 includes mixing nanoparticles with water used during water flooding processes. In some such embodiments, the nanoparticles in the water flooding solution or suspension may contact and adhere to surfaces of the subterranean formation. In some such embodiments, a first portion of water flooding may be performed without the nanoparticles and a second portion thereof may be performed with the nanoparticles. In yet other embodiments, act 104 may be performed immediately after primary after primary hydrocarbon recovery, without performing water flooding.
Act 106 includes mixing at least one anionic surfactant with another carrier fluid to form a second fluid to be injected into the subterranean formation. The another carrier fluid may include water, brine, seawater, condensate, steam, etc., or combinations thereof. In some embodiments, the another carrier fluid includes brine. In some embodiments, the another carrier fluid comprises the same material as the carrier fluid used in act 102.
The anionic surfactant may include any surfactant formulated and configured to reduce an interfacial between a hydrocarbon phase and an aqueous phase and mobilize the hydrocarbon phase within the subterranean formation. The anionic surfactant may include at least one anionic surfactant selected from the group consisting of sulfonates (e.g., including one or more sulfonate (—SO3−) groups), sulfates (e.g., including one or more sulfate (—SO42−) groups, carboxylates (e.g., including one or more carboxylate groups), phosphates (e.g., including one or more phosphate (—PO43−) groups), or combinations thereof.
By way of nonlimiting example, the anionic surfactant may include a sodium alkyl sulfate (e.g., sodium dodecyl sulfate (SDS)), sodium alkyl aryl sulfonate, sodium dodecylbenzenesulfonate (C18H29NaO3S), sodium laureth sulfate (CH3(CH2)10CH2(OCH2CH2)nOSO3Na), sodium stearate (C18H35NaO2), sodium laurate (CH3(CH2)10CO2Na), sulfated alkanolamides, a benzyl dodecane sulfonate sodium salt, a glycolic acid ethoxylate lauryl ether, sulfo-caborboxylic compounds (e.g., sodium lauryl sulfoacetate, dioctyl sulfosuccinate, etc.), organo phosohored surfactants, sarcosides or alkyl amino acids, ammonium lauryl sulfate, sodium phosphates, phosphate esters, internal olefin surfactants, alcohol alkoxy sulfates, alkyl alkoxy carboxylates, other anionic surfactants, and combinations thereof. In some embodiments, the anionic surfactant comprises a carboxylated surfactant (e.g., sodium stearate, sodium lauroyl sarcosinate, etc.).
In some embodiments, the anionic surfactants may include the same groups as the functional groups of the nanoparticles described above with reference to act 102. For example, the where the anionic surfactant includes sulfonates, the nanoparticles may include sulfonate functional groups. In embodiments where the anionic surfactant includes carboxylates or phosphates, the nanoparticles may include carboxylate or phosphate functional groups, respectively. In some such embodiments, at least some of the anionic surfactants may include the same groups as the functional groups adhered to the surfaces of the subterranean formation during act 104.
A concentration of the anionic surfactant in the carrier fluid may be between about 10 ppm and about 50,000 ppm, such as between about 10 ppm and about 50 ppm, between about 50 ppm and about 100 ppm, between about 100 ppm and about 200 ppm, between about 200 ppm and about 500 ppm, between about 500 ppm and about 1,000 ppm, between about 1,000 ppm and about 3,000 ppm, between about 3,000 ppm and about 5,000 ppm, between about 5,000 ppm and about 10,000 ppm, between about 10,000 ppm and about 30,000 ppm, or between about 30,000 ppm and about 50,000 ppm. However, the disclosure is not so limited and the concentration of the anionic surfactant may be different than those described. In some embodiments, a concentration of the anionic surfactant may be greater than a critical micelle concentration (CMC, a concentration of surfactants above which micelles form and additional surfactants added to the system form micelles). It is believed that a concentration of surfactants greater than the CMC may improve hydrocarbon recovery from the subterranean formation. Without wishing to be bound by any particular theory, it is believed that above the CMC, a microemulsion may form between an aqueous phase and the hydrocarbon phase. The microemulsion may reduce an interfacial tension between the hydrocarbon phase and the aqueous phase and the solid phase of the subterranean formation. In addition, a concentration of surfactants greater than the CMC may increase hydrocarbon recovery from the subterranean formation since, in some embodiments, at least some of the surfactant may be adsorbed onto surfaces of the subterranean formation.
In some embodiments, the second fluid may not include nanoparticles. In other embodiments, the second fluid may include both the anionic surfactant and nanoparticles. In some such embodiments, the nanoparticles may have a negatively charged surface. By way of nonlimiting example, the second fluid may include silica nanoparticles, POSS nanoparticles, carbon nanoparticles, metal nanoparticles, metal oxide nanoparticles, or combinations thereof. In some embodiments, the nanoparticles comprise silica nanoparticles.
The nanoparticles may have the same size and shape as the nanoparticles described above with reference to the nanoparticles in the first fluid. In some embodiments, the nanoparticles in the second fluid are the same as the nanoparticles in the first fluid. In other embodiments, the nanoparticles in the first fluid and the nanoparticles in the second fluid are different. By way of nonlimiting example, the nanoparticles in the first fluid may be formulated and configured to interact with active sites on surfaces of the subterranean formation. By way of nonlimiting example, where the subterranean formation includes active sites including exposed hydroxyl groups, the nanoparticles in the first fluid may be formulated and configured to interact with the exposed hydroxyl groups of the subterranean formation. In some such embodiments, the nanoparticles of the first fluid may include hydroxyl groups, amine groups, carboxylate groups, isocyanate groups, another functional group, sulfonate functional groups, phosphate functional groups, and combinations thereof. The nanoparticles of the second fluid may include nanoparticles having a negatively charged core, exposed anionic functional groups, or both. In some embodiments, the nanoparticles of the second fluid include functional groups that are the same as the groups of the surfactant (e.g., where the surfactant comprises sulfonates, carboxylates, or phosphates, the nanoparticles may respectively include sulfonate, carboxylate, or phosphate functional groups.
In some embodiments, the nanoparticles in the second fluid have a different size (e.g., diameter) than the nanoparticles in the first fluid. By way of nonlimiting example, the nanoparticles of the second fluid may exhibit a lower mean diameter than the nanoparticles of the first fluid. In other embodiments, the nanoparticles of the second fluid may exhibit a greater mean diameter than the nanoparticles of the first fluid.
In some embodiments, a concentration of the surfactant in the second fluid may be greater than a concentration of the nanoparticles in the second fluid. By way of nonlimiting example, the concentration of surfactant in the second fluid may be between about 500 ppm and about 5,000 ppm and a concentration of the nanoparticles in the second fluid may be between about 100 ppm and about 2,000 ppm. In some embodiments, the concentration of the surfactant may be about 1,500 ppm and the concentration of the nanoparticles may be about 200 ppm.
In some embodiments, a ratio of surfactant to nanoparticles (e.g., a concentration of surfactant divided by a concentration of nanoparticles) in the second fluid may be greater than about 1.0. By way of nonlimiting example, the ratio of surfactant to nanoparticles in the second fluid may be greater than about 1.0, greater than about 1.5, greater than about 2.0, greater than about 2.5, greater than about 3.0, greater than about 4.0, greater than about 5.0, or even greater than about 10.0.
Act 108 includes introducing the second fluid into the subterranean formation. An amount of anionic surfactant that is lost due to adsorption on surfaces of the subterranean formation may be reduced because of the nanoparticles already attached to the active sites of the subterranean formation in act 104. Without wishing to be bound by any particular theory, it is believed that introducing the nanoparticles during act 104 reduces a number of active sites in the subterranean formation that may otherwise interact with the anionic surfactant such that a lesser amount of the anionic surfactant is lost caused by adsorption to surfaces of the subterranean formation. Stated another way, introducing the nanoparticles into the subterranean formation and adhering the nanoparticles to surfaces of the subterranean formation prior to introducing the surfactant into the subterranean formation may reduce an amount of surfactant lost in the subterranean formation and may increase an effectiveness of the surfactant (e.g., by increased hydrocarbon recovery).
In some embodiments, where the second fluid includes nanoparticles, the nanoparticles of the second fluid may be formulated and configured to reduce a degree of interaction between the anionic surfactants and the active sites on surfaces of the subterranean formation. Without wishing to be bound by any particular theory, it is believed that the nanoparticles including a negatively charged core, anionic functional groups, or both may interact with the anionic surfactant in the carrier fluid to facilitate transport of the anionic surfactant deeper into the subterranean formation while reducing an adsorption of the anionic surfactant onto surfaces of the subterranean formation. It is believed that the nanoparticles introduced into the subterranean formation during act 104 may interact with the active sites on surfaces of the subterranean formation, reducing a likelihood of adsorption of the surfactant in the second fluid with the active sites. In addition, it is believed that cations in the carrier fluid (e.g., Ca2+ and Mg2+ when the carrier fluid comprises brine) interact with any nanoparticles present in the second fluid and form a so-called “shell” around the nanoparticles due to ion-ion interactions between the negative charges associated with the nanoparticles and the cations in the carrier fluid. The anionic surfactants may be attracted to the positively charged shell of cations surrounding the nanoparticles in the second fluid and may form another shell around the cations surrounding the nanoparticles. Accordingly, the anionic heads of the surfactant may be oriented toward the shell of the nanoparticle and the tail portion of the surfactant may be oriented away from the nanoparticles. The tail portion of the anionic surfactant may include, for example, alkyl groups. Within the subterranean formation, the tail portion of the anionic surfactant may be oriented toward the surfaces of the subterranean formation while the anionic head portion remains directed toward the positively charged shell surrounding the nanoparticles. Accordingly, it may be more likely for the anionic heads of the anionic surfactants to interact with the nanoparticles than with the active sites of the subterranean formation. In addition, due to the size of the nanoparticles, the nanoparticles may exhibit a substantially greater surface area than a surface area of the active sites of the subterranean formation.
Act 110 includes flowing (e.g., driving, sweeping, forcing, etc.) the hydrocarbons from the subterranean formation to a location above the subterranean formation. The surfactant may reduce an interfacial tension between the hydrocarbon phase and an aqueous phase. Accordingly, the surfactant may increase a mobility of hydrocarbons within the subterranean formation and the hydrocarbons may be transported to above the subterranean formation.
Although
Act 202 includes mixing nanoparticles and at least one anionic surfactant with a carrier fluid to form a suspension including the nanoparticles and the at least one anionic surfactant. The anionic surfactant may include the same anionic surfactants described above with reference to
The nanoparticles may include the same nanoparticles as those described above with reference to
Act 204 may include a flooding process including introducing the suspension into a subterranean formation and contacting surfaces of the subterranean formation with the nanoparticles to adsorb the nanoparticles on surfaces of the subterranean formation. Exposing the subterranean formation to the suspension including both the nanoparticles and the anionic surfactant may substantially reduce an amount of surfactant losses due to adsorption of the anionic surfactant onto surfaces of the subterranean formation.
Without wishing to be bound by any particular theory, it is believed that introducing nanoparticles including a negatively charged surface (e.g., silica nanoparticles) into the subterranean formation and exposing the subterranean formation to anionic surfactants simultaneously alters a wettability of the formation surfaces. It is believed that the nanoparticles alter a wettability of the formation surfaces. The altered wettability of the formation surfaces may substantially reduce an amount of surfactant that interacts with (e.g., adsorbs onto) surfaces of the subterranean formation. Accordingly, more of the anionic surfactant may be present at a hydrocarbon/aqueous interface, reducing an interfacial tension therebetween and improving a flowability of hydrocarbons from the subterranean formation.
Act 206 may include flowing (e.g., driving, sweeping, forcing, etc.) the hydrocarbons from the subterranean formation to a location above the subterranean formation. In some embodiments, act 206 may be substantially the same as act 110 described above with reference to
In some embodiments, the mixture of nanoparticles and the anionic surfactant may be stable (e.g., may not agglomerate) at temperatures as high as about 80° C. and at salinities that may be encountered during wellbore operations. Without wishing to be bound by any particular theory, it is believed that the unique combination of nanoparticles and anionic surfactants facilitate the stability of the suspension and use of the suspension in the subterranean formation to increase hydrocarbon recovery therefrom. In some embodiments, the surfactant may include a surfactant in addition to, or other than SDS, since in some instances SDS may not exhibit effectiveness in brine and temperatures greater than about 20° C. In some embodiments, the surfactant comprises a carboxylated surfactant. In some embodiments, the carboxylated surfactant used in combination with the nanoparticles may facilitate an increase in hydrocarbon recovery from the subterranean formation. In some embodiments, the surfactant includes carboxylated surfactants and sulfonated surfactants. It is believed that carboxylated surfactants enhance hydrocarbon recovery and sulfonated surfactants increase a temperature stability of the mixture including the surfactants.
Without wishing to be bound by any particular theory, it is believed that the combination of nanoparticles and surfactant in the subterranean formation exhibit synergistic properties. It is believed that the nanoparticles form a wedge between hydrocarbons and the surface of the subterranean formation. The nanoparticles may generate a disjoining pressure on the three-phase contact point (i.e., between the aqueous phase, the hydrocarbon phase, and the solid phase of the subterranean formation). The disjoining pressure may mobilize the hydrocarbons. Since the nanoparticles include a negative charge (similar to the negative charge of the anionic surfactant), the nanoparticles, rather than the surfactant, may interact with the active sites of the subterranean formation to reduce a loss of surfactant caused by adsorption. As the hydrocarbons are mobilized from surfaces of the subterranean formation, the surfactant may interact with the hydrocarbons and reduce an interfacial tension between the hydrocarbon phase and the aqueous phase, increasing a mobility of the hydrocarbons.
An amount of enhanced hydrocarbon recovery (e.g., enhanced oil recovery (EOR)) with suspensions comprising only nanoparticles, suspensions comprising only surfactants, and suspensions comprising nanoparticles and surfactants was compared. Table I below includes a composition of each suspension tested and includes an amount of hydrocarbon recovery for each suspension.
In Table I, Φ represents a porosity of the sample (e.g., the subterranean formation), So is the initial oil saturation in the sample, % ORWF is the percent hydrocarbon recovery during water flooding, and % EOR is the percent of enhanced hydrocarbon recover after flooding with the suspension.
In each sample, an initial water flooding process was performed on the sample to recover an initial amount of hydrocarbons therefrom, the amount of which recovery is indicated in the column labeled “% ORWF.” Thereafter, each sample was flooded with the indicated suspension to further enhance hydrocarbon recovery therefrom. The additional amount of hydrocarbons recovered from each sample responsive to flooding with the suspension is shown in the column labeled “% EOR.”
With reference to Table I, an amount of enhanced hydrocarbon recovery dramatically decreases when the nanoparticles in the suspension are exposed to a temperature greater than about 25° C. For example, at a temperature of about 25° C., silica nanoparticles enhance hydrocarbon recovery by between about 16% and about 19%. By way of contrast, hydrocarbon recovery is enhanced by only about 0.98%, about 1.3%, or about 0.5% when the silica nanoparticles are exposed to a temperature of about 80° C. or about 70° C.
Referring again to Table I, an amount of hydrocarbon recovery flooding with a suspension including surfactants (Sample 5) was compared to an amount of hydrocarbon recovery responsive flooding with a suspension comprising the surfactant and silica nanoparticles (Sample 6).
An amount of enhanced hydrocarbon recovery from a sample responsive to sequential flooding with several different flooding solutions was measured. The sample exhibited a pore volume of about 35.1, a porosity of about 22.2, a permeability of about 472, a temperature of about 60° C., and an initial oil saturation of about 0.60.
The sample was first exposed to artificial seawater, resulting in recovery of about 77.4% of the hydrocarbons from the sample. Thereafter the sample was exposed to a solution comprising about 5,000 ppm of silica nanoparticles, followed by flooding with the artificial seawater. Thereafter, the artificial seawater remained in the sample overnight (for between about 8 hours and about 12 hours). Then, the sample was flooded with a suspension including about 3,000 ppm silica nanoparticles and about 2,000 ppm of sodium dodecyl sulfate (SDS), followed by flooding with a solution comprising about 2,000 ppm SDS, and then flooding with a suspension comprising about 3,000 ppm silica nanoparticles and 2,000 ppm SDS. Table II below shows the amount of hydrocarbon recovery responsive to the different flooding operations.
Referring to Table II, an amount of hydrocarbon recovery from the sample increased by about 7.9% responsive to exposure to the flooding suspension comprising the silica nanoparticles and the SDS surfactant after the sample had previously been exposed to a flooding suspension comprising silica nanoparticles.
An amount of enhanced hydrocarbon recovery from a sample responsive to sequential exposure to several different flooding solutions was measured. The sample exhibited a pore volume of about 34.4, a porosity of about 22.0, a permeability of about 1613, a temperature of about 60° C., and an initial oil saturation of about 0.77.
The sample was first flooded with a solution of artificial seawater, resulting in recovery of about 50.1% of the hydrocarbons from the sample. Thereafter the sample was flooded with a solution comprising about 2,000 ppm of SDS. Thereafter, the sample was flooded with a suspension comprising 3,000 ppm silica nanoparticles and 2,000 ppm SDS, then flooded with a suspension comprising 20,000 ppm silica nanoparticles and 2,000 ppm SDS, and then flooded with a suspension comprising 10,000 ppm silica nanoparticles and 2,000 ppm SDS. Table III below shows the amount of hydrocarbon recovery responsive to the different flooding operations.
Adsorption of surfactants on surfaces of a subterranean formation sample and adsorption of silica nanoparticle on the surfaces of the sample were measured. The results are shown in Table IV below.
Accordingly, an amount of silica nanoparticles adsorbed onto surfaces of the sample was greater when the carrier fluid comprised artificial seawater than when the carrier fluid comprised distilled water. Thus, a loss of nanoparticles due to adsorption increased with increasing salinity of the carrier fluid. In an artificial seawater carrier fluid, the SDS surfactant exhibited an adsorption of about 0.81 mg surfactant/g sample. By way of contrast, exposing the sample to silica nanoparticles in artificial seawater prior to exposing the sample to the SDS surfactant significantly reduced the amount of SDS surfactant adsorbed by the sample. For example, the adsorption of the SDS was decreased from 0.81 mg/g to about 0.26 mg/g, a decrease of over two-thirds.
Accordingly, providing a suspension including nanoparticles and anionic surfactants or sequentially providing nanoparticles and anionic surfactants to the subterranean formation may substantially reduce an amount of surfactant that adsorbs onto surfaces of the subterranean formation. The nanoparticles may alter a hydrocarbon-water interface in the presence of the anionic surfactant. The nanoparticles may mobilize hydrocarbons from the subterranean formation by disjoining pressure. The anionic surfactants may form a wedge at an interface between the surface of the subterranean formation, a hydrocarbon phase, and an aqueous phase. The combination of the nanoparticles and the surfactant may improve surfactant performance within the subterranean formation, even when exposed to high temperatures (e.g., a temperature greater than about 50° C., a temperature greater than about 60° C., a temperature greater than about 70° C., or even a temperature greater than about 80° C.) and high salinity.
Additional nonlimiting example embodiments of the disclosure are described below.
A method of recovering hydrocarbons from a subterranean formation, the method comprising: introducing a suspension comprising at least one of silica nanoparticles or aluminum silicate nanoparticles into a subterranean formation; contacting surfaces of the subterranean formation with the suspension to form a layer of the at least one of silica nanoparticles or aluminum silicate nanoparticles on at least some surfaces of the subterranean formation; after introducing the suspension comprising the at least one of silica nanoparticles or aluminum silicate nanoparticles into the subterranean formation, introducing a solution comprising at least one anionic surfactant into the subterranean formation; and extracting hydrocarbons from the subterranean formation.
The method of Embodiment 1, further comprising selecting the at least one of silica nanoparticles or aluminum silicate nanoparticles to have a diameter less than about 100 nm.
The method of Embodiment 1 or Embodiment 2, wherein introducing a solution comprising at least one anionic surfactant into the subterranean formation comprises introducing a solution comprising at least one anionic surfactant and the at least one of silica nanoparticles or the aluminum silicate nanoparticles into the subterranean formation simultaneously.
The method of any one of Embodiments 1 through 3, further comprising selecting the at least one anionic surfactant to comprise sodium dodecyl sulfate.
The method of any one of Embodiments 1 through 4, wherein introducing a solution comprising at least one anionic surfactant into the subterranean formation comprises introducing the solution into a subterranean formation having a temperature greater than about 80° C.
The method of any one of Embodiments 1 through 5, wherein introducing a suspension comprising at least one of silica nanoparticles or aluminum silicate nanoparticles into a subterranean formation comprises introducing a suspension comprising silica nanoparticles dispersed in a brine carrier fluid into the subterranean formation.
The method of any one of Embodiments 1 through 6, further comprising forming the solution to include between about 10 ppm and about 50,000 ppm of the at least one anionic surfactant.
The method of any one of Embodiments 1 through 7, further comprising selecting the at least one of silica nanoparticles or aluminum silicate nanoparticles to include at least one anionic functional group.
The method of any one of Embodiments 1 through 8, further comprising at least one of water flooding and steam flooding the subterranean formation prior to introducing the suspension comprising the at least one of silica nanoparticles or aluminum silicate nanoparticles into the subterranean formation.
The method of any one of Embodiments 1 through 9, wherein introducing a solution comprising at least one anionic surfactant into the subterranean formation comprises introducing a solution comprising additional nanoparticles into the subterranean formation, wherein the additional nanoparticles are different from the at least one of silica nanoparticles or aluminum silicate nanoparticles in the suspension.
The method of any one of Embodiments 1 through 10, further comprising selecting the at least one of silica nanoparticles or aluminum silicate nanoparticles to comprise at least one functional group formulated and configured to react with hydroxyl groups on surfaces of the subterranean formation.
A method of recovering hydrocarbons from a subterranean formation, the method comprising: mixing nanoparticles having a diameter less than about 100 nm with a carrier fluid comprising brine and at least one anionic surfactant to form a suspension, the nanoparticles comprising silica nanoparticles, aluminum silicate nanoparticles, or a combination thereof; introducing the suspension into a subterranean formation having a temperature greater than about 50° C.; and extracting hydrocarbons from the subterranean formation.
The method of Embodiment 12, further comprising selecting the at least one anionic surfactant to comprise a sulfate or a sulfonate.
The method of Embodiment 12 or Embodiment 13, further comprising selecting the at least one anionic surfactant to comprise a phosphate.
The method of any one of Embodiments 12 through 14, further comprising selecting the at least one anionic surfactant to comprise at least one carboxylate surfactant and at least one sulfonate surfactant.
The method of any one of Embodiments 12 through 15, further comprising selecting the nanoparticles to comprise at least a first type of silica nanoparticle and at least a second type of silica nanoparticle.
The method of any one of Embodiments 12 through 16, further comprising: selecting the first type of silica nanoparticles to comprise silica nanoparticles including at least one functional group; and selecting the second type of silica nanoparticles to be substantially free of functional groups.
The method of any one of Embodiments 12 through 17, further comprising selecting the nanoparticles to comprise aluminum silicate nanoparticles.
The method of any one of Embodiments 12 through 18, further comprising introducing another suspension comprising nanoparticles into the subterranean formation prior to introducing the suspension comprising the nanoparticles and the at least one anionic surfactant into the subterranean formation.
A method of recovering hydrocarbons from a subterranean formation, the method comprising: introducing a suspension comprising nanoparticles selected from the group consisting of silica and aluminum silicate into a subterranean formation; adhering the nanoparticles to surfaces within the subterranean formation; and after introducing the suspension comprising nanoparticles into the subterranean formation, introducing a solution comprising at least one anionic surfactant into the subterranean formation.
While the disclosure is susceptible to various modifications and alternative forms, specific embodiments have been shown by way of example in the drawings and have been described in detail herein. However, the disclosure is not intended to be limited to the particular forms disclosed. Rather, the disclosure is to cover all modifications, equivalents, and alternatives falling within the scope of the disclosure as defined by the following appended claims and their legal equivalents.
This application claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application Ser. No. 62/504,731, filed May 11, 2017, the disclosure of which is hereby incorporated herein in its entirety by this reference.
| Number | Date | Country | |
|---|---|---|---|
| 62504731 | May 2017 | US |
