EA044915B1 - COLLOIDAL SCALE INHIBITOR WITH PROLONGED RELEASE - Google Patents

Description

Cross reference to related applications

This application claims the benefit of U.S. Provisional Patent Application No. 62/826,369, filed March 29, 2019. The contents of the cited application are incorporated herein by reference.

Field and Background of the Invention

A. Technical Field of the Present Invention.

The present invention relates generally to nanoparticle carrier platforms for the controlled release of well treatment additives (eg, scale inhibitors) in subterranean gas, oil or water wells or subterranean formations. Nanoparticles can be made from complex oxides of silicon and metals. Subsurface well treatment additives can be used to coat the surface of the nanoparticles, permeate the bulk of the nanoparticles, or bind to the nanoparticles.

B. Background Art of the Present Invention.

Chemical carrier platforms may find use in industrial underground drilling to introduce additives to treat underground wells. As an example, scale inhibitors may be introduced into a subterranean well in order to prolong the period of time over which such additives are released. Controlled or sustained release of additives from carrier platforms is desirable to prevent or eliminate the need for well retreatment, which is costly and time consuming.

In addition, there are safety risks to humans and the environment associated with each treatment. In particular, scale inhibitors, which are used to prevent or control the formation of scale in underground wells, can be introduced using a method known as pressure treatment. During the process of pressurizing a scale inhibitor, the inhibitor may be attached to the formation matrix through chemical adsorption or thermally activated precipitation and returned with the production fluid in concentrations high enough to prevent scale formation. Scale inhibitor chemicals may be continuously injected through an injection point in the wellbore during the well completion process, or intermittent pressure treatment may be carried out to introduce the inhibitor into the formation matrix for subsequent mixing with production fluids. Some scale inhibitor systems combine scale inhibitor injection and hydraulic fracturing treatment in one step. In this type of treatment, the scale inhibitor can be injected into the formation, adsorbed onto the matrix during injection, and then released when hydraulic fracturing begins to produce water. As water passes through the adsorbed inhibitor zone, it dissolves the inhibitor, preventing scale nucleation and salt deposition in the well. A commercially available scale inhibitor system called Scaleguard® is sold by Carbo Ceramics, Inc. (Houston, Texas, USA). This system contains a porous ceramic proppant that is impregnated with scale inhibitor and releases the scale inhibitor in contact with water for slow release in hydraulically fractured wells through a semi-permeable coating.

A variety of scale inhibitor systems have been investigated to improve the introduction of additives into a hydrocarbon production well. As an example, Shen et al. (2008 Society of Petroleum Engineers (SPE) International Petroleum Scale Conference) describe nanoparticle suspensions containing calcium diethylenetriamine penta(methylenephosphonate) (Ca-DTPMP) for controlled delivery of scale inhibitors to formation and movement of scale inhibitors in porous media. Boehmite-based nanoparticles containing a sulfonated polymer were described in Yan et al. (Offshore Technology Conference, 2013), while the fabrication of boehmite-based nanoparticles for phosphate sorption was described in Wantanbe et al. ( Separation Science and Technology 46.5 (2011): 818-824).

Other attempts to improve the release of scale inhibitors into the well include crosslinking polymeric scale inhibitors with aluminum oxohydroxide (AlO(OH)) or α-aluminum oxohydroxide (a-AlO(OH)); see, for example, Yan et al., Society of Petroleum Engineers (SPE) International Symposium on Petroleum Chemistry, 2013; and Yan et al., SPE Journal, 19.04 (2014): 687-694. Work by Zhang et al. describes crystalline phase calcium phosphonate formation inhibitor nanomaterials derived from calcium phosphonate deposits on an amorphous silica matrix (RSC Adv., 2016, 6, 5259-5269; and Ind. Eng. Chem. Res., 2011, 50(4), 1819-1830).

At the same time, other additional additives were combined with scale inhibitors for well treatment. As an example, US Patent No. 7,422,759 (Kepner et al.) describes antimicrobial compositions in combination with scale inhibitors made from a variety of possible combinations of metal oxides.

Notwithstanding the above, the disadvantage of these nanoparticles as carriers is the insufficiently controlled release of additives for underground processing over an extended period of time from currently available carrier platforms, which leads to the need for reprocessing, as well as increasing environmental risks and economic losses .

Brief Disclosure of the Present Invention

An invention has been made that solves problems associated with treating subterranean formations (eg, reservoirs) or wells (eg, oil, gas and water wells) using well treatment additives (eg, scale inhibitors). This solution is the development of a complex silica-metal oxide nanoparticle, preferably a metal oxide nanoparticle, into which a well treatment additive is introduced. The released additive for treating hydrocarbon reservoirs and/or wells is attached to a complex oxide of silicon and metals, with a particle size of less than 300 nm. The metal may be a Group 2 metal or a transition metal. In a preferred embodiment, the metal is calcium. A nanoparticle may have the general formula

A/[Si _x M _z ]On, where M is contained in the crystal lattice structure of the nanoparticle and A is a well treatment additive that can be slowly released from the nanoparticle.

Surprisingly, this structural configuration provides a slow release profile for the additive such that the additive can be released from the nanoparticle over an extended period of time (e.g., at least 10 days to 10 years or more, 500 days, at least 1000 days , at least for 2000 days, at least for 500 to 2500 days or at least for 500 to 2000 days after well treatment) during use. The time it takes to achieve the required inhibitor concentration from a nanoparticle may vary depending on the rate of water production from the well. This, in turn, reduces costs and overcomes the disadvantages associated with the implementation of continuous or more periodic well treatment, for example, using methods that are currently used in industrial well treatment. Without wishing to be bound by theory, the authors believe that due to the existence of metals in the mixed metal oxide nanoparticles that are present in the crystal lattice, more efficient incorporation (eg, through adsorption or chemical bonding) of the well treatment additive into the crystal lattice can occur. Such embedding may provide more controlled or delayed dissolution or desorption of the additive into the aqueous environment and inhibit leaching of the well treatment additive from the nanoparticle, thereby providing a sustained release profile of the additive over the course of application. The nanoparticle according to the present invention, as illustrated in a non-limiting manner in the examples, compared with the previously used additive at the same dosage, provided a higher concentration of Si at release, higher efficiency throughout the treatment process, a significant increase in the duration of re-compression and a higher effect in calculated per active unit of inhibitor. Aqueous solutions of nanoparticles according to the present invention are stable (i.e. they do not shrink and change the size of nanoparticles) at temperatures from -20 to 200°C and/or pH values from 5 to 9, preferably from 7.1 to 8.6 . The nanoparticles of the present invention are shear stress resistant (eg, no sedimentation of particles after shearing). In addition, nanoparticles do not slow down or inhibit emulsion separation processes.

According to one aspect of the present invention, a nanoparticle is described that contains a releasable hydrocarbon formation and/or well treatment additive attached to the nanoparticle. The nanoparticle may contain silica and at least one Group 2 metal, Group 14 metal or transition metal, or combinations thereof in a complex silica-metal oxide (M-SiO ₂ ). The nanoparticle may have a particle size of less than 300 nm (eg, from 0.1 to 300 nm, preferably from 10 to 250 nm). In a preferred embodiment, the metal is calcium (Ca) (eg Ca-SiO ₂ ). The additive for treating hydrocarbon formations and/or wells may be a scale inhibitor, hydrate inhibitor, clay stabilizer, bactericidal agent, salt substitute, relative permeability modifier, sulfide scavenger, corrosion inhibitor, corrosion inhibitor enhancer, pH adjusting agent, surfactant. active agent, thinner, filterability regulator, asphaltene precipitation inhibitor, wax precipitation inhibitor, complexing agent, foaming agent, defoaming agent, emulsifier, demulsifier, iron content regulator, solvent, friction reducer or any combination thereof. Scale inhibitors can

- 2 044915 contain an organic molecule in which groups of esters of carboxylic acid, polycarboxylic acid, aspartic acid, maleic acid, sulfonic acid, phosphonic acid or phosphoric acid or corresponding salts are present. The scale inhibitor may contain a phosphonic acid functional group. In preferred aspects, diethylenetriaminepenta(methylenephosphonic acid) (DTPMPA), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (HMPTPMP), ethylenediaminetetra(methylenephosphonic acid) (EDTMPA), aminotrimethylenephosphonic acid (ATMP), polyaminoprostopolyethermethylenephosphonic acid may be present in the formulation or as a scale inhibitor. acid (PAREMP), hydroxyethylamino-di(methylenephosphonic acid) (HEMPA) or a combination thereof, preferably DTPMPA and/or HEMPA. As some examples, 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP), 2-phosphonobutane-1,2,4tricarboxylic acid (PBTC), 2-hydroxyphosphonoacetic acid (HPAA), or any combination of them. In a preferred embodiment, the additive is DTPMPA and the nanoparticle is SiO ₂ -Ca. An additive for treating hydrocarbon formations and/or wells can permeate the volume of the nanoparticle. As some examples, the hydrocarbon reservoir and/or well treatment additive may be chemically bonded to the nanoparticle through ionic bonding, covalent bonding, hydrogen bonding, van der Waals interaction, or adsorption onto the particle. The additive may be capable of being released from the nanoparticle in a controlled manner over an extended period of time, for example at least 500 days, at least 1000 days, at least 2000 days, at least 500 to 2500 days or at least for 500 to 2000 days after use.

According to a further aspect of the present invention, the nanoparticle may have the formula A/[SixMz]On, wherein Si and M are contained in the crystal lattice structure of the nanoparticle, M being a Group 2 metal, a transition metal, a Group 14 metal, or any combination thereof;

x is from 0.03 to 3, z is from 0.01 to 0.4 and n is determined by the oxidation states of the metals Si, M; And

A may be an additive for the treatment of hydrocarbon formations or wells, capable of being released from a nanoparticle, which is described above.

In preferred aspects, the present invention provides nanoparticles that provide sustained release of subsurface well treatment additives, such as scale inhibitors. As discussed above and throughout the specification of the present invention, the additive may be associated with the nanoparticle or otherwise attached to the nanoparticle. The additive may be a scale inhibitor, which is an organic molecule in which carboxylic acid, polycarboxylic acid, aspartic acid, maleic acid, sulfonic acid, phosphonic acid or phosphoric acid ester groups are present. In particularly preferred embodiments, the scale inhibitor may contain a phosphonic acid functionality. In preferred aspects, diethylenetriaminepenta(methylenephosphonic acid) (DTPMPA), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (HMPTPMP), ethylenediaminetetra(methylenephosphonic acid) (EDTMPA), aminotrimethylenephosphonic acid (ATMP), polyaminoprostopolyethermethylenephosphonic acid may be present in the formulation or as a scale inhibitor. acid (PAREMP), hydroxyethylamino-di(methylenephosphonic acid) (HEMPA) or a combination thereof, preferably DTPMPA and/or HEMPA. As some examples, 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP), 2-phosphonobutane-1,2,4tricarboxylic acid (PBTC), 2-hydroxyphosphonoacetic acid (HPAA), or any combination of them.

In addition, methods for making nanoparticles are disclosed. The method may include contacting a metal salt solution that contains a Group 2 metal salt, a Group 14 metal salt, a transition metal salt (e.g., calcium chloride) with an aqueous dispersion of silica nanoparticles having a pH of 2.5 to 3.3, with the formation of a material based on a complex metal oxide and silicon. The underground well treatment additive can then be applied to the nanoparticle. If a mixture of metal salts is used, then a mixture of nanoparticles based on complex metal and silicon oxides (M-SiO ₂ and M ² -SiO2, where M and M ² are different metals that are obtained from salts of group 2 metals, group metals) can be obtained 14 or transition metals). For example, nanoparticles of Ca-SiO2, Mg- _SiO2 , etc. can be used in a mixture. In some aspects, the method may include the optional step of removing water from the aqueous solution, wherein the removal of water from the aqueous solution precipitates nanoparticles, preferably at a temperature of from 70 to 150°C for 0.1 to 24 hours. In preferred aspects, the solution may contain from 0 .2 to 5 wt.% SiO ₂ and from 0.18 to 0.22 wt.% metal (preferably Ca). Embedding the additive may involve contacting the nanoparticle with the well treatment additive to form a mixture and sonicating the mixture at a pH of 9 to 10 to form a nanoparticle that contains the embedded additive. It should be noted that the formation of nanoparticles and/or the incorporation of additives can be carried out when surfactant and/or piperazine-N,N'-bis(2-ethanesulfonic acid) (PIPES) is absent.

The metal salt solution may have a pH value of from 5.5 to 6.5, preferably 6. The nanoparticle contains at least 0.1 wt.% additive, preferably from 2 to 15 wt.%, based on the total weight containing the additive nanoparticles.

According to another aspect of the present invention, there are provided compositions for treating underground wells containing nanoparticles according to the present invention, as well as methods for treating wells using such compositions by introducing them into a well or underground formation, such as a reservoir or an open hole. The composition may be added to other drilling fluids, such as aqueous brine or other aqueous fluids. The composition may contain an aqueous medium, a non-aqueous medium, or mixtures thereof, such as an aqueous salt solution, an acidic aqueous solution, low sulfate seawater, an aqueous sodium carbonate solution, a surfactant, or other rinsing fluid, an oil phase, suspension, non-aqueous medium, or any combination thereof).

In some embodiments, a method of introducing an additive into a subterranean formation is provided. The method may include obtaining a composition that contains nanoparticles with embedded additives as described above and throughout the specification of the present invention, and introducing the composition containing nanoparticles into a subterranean formation. The composition of additive-containing nanoparticles can be introduced into a drilling fluid (drilling fluid) or fluid to enhance oil recovery.

In addition, aspects 1-42 are disclosed in the context of the present invention. Aspect 1 is a nanoparticle containing a releasable hydrocarbon formation and/or well treatment additive that is attached to the nanoparticle, wherein the nanoparticle contains silica and at least one metal forming a metal-silicon complex oxide, wherein the nanoparticle has a particle size of less than than 300 nm, with a Group 2 metal and/or a transition metal being selected as the metal. Aspect 2 is a nanoparticle according to aspect 1, in which the metal is calcium (Ca). Aspect 3 is a nanoparticle according to any of aspects 1-2, the particle size being from 0.1 to 300 nm, preferably from 10 to 250 nm. Aspect 4 is a nanoparticle according to any of aspects 1-3, wherein the hydrocarbon formation and/or well treatment additive is a scale inhibitor, hydrate inhibitor, clay stabilizer, germicidal agent, salt replacer, relative permeability modifier, sulfide scavenger, corrosion inhibitor, corrosion inhibitor enhancer, pH adjusting agent, surfactant, thinner, filterability regulator, asphaltene precipitation inhibitor, wax inhibitor, complexing agent, foaming agent, defoaming agent, emulsifier, demulsifier, iron content regulator, solvent, friction reducer or any combination of them. Aspect 5 is a nanoparticle according to aspect 4, wherein the additive is a scale inhibitor. Aspect 6 is a nanoparticle according to aspect 5, wherein the scale inhibitor is an organic molecule in which carboxylic acid, polycarboxylic acid, aspartic acid, maleic acid, sulfonic acid, phosphonic acid or phosphoric acid ester groups, or corresponding salts, are present. Aspect 7 is a nanoparticle according to aspect 5, in which the scale inhibitor contains a phosphonic acid functional group, preferably diethylenetriaminepenta(methylenephosphonic acid) (DTPMPA), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (HMTMP) may be present in the composition or as the scale inhibitor ), ethylenediaminetetra(methylenephosphonic acid) (EDTMPA), aminotrimethylenephosphonic acid (ATMP), polyaminoprostopolyethermethylenephosphonic acid (PAREMP), hydroxyethylamino-di(methylenephosphonic acid) (HEMPA) or a combination thereof, preferably DTPMPA and/or HEMPA, and/or in The scale inhibitor contains 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), 2-hydroxyphosphonoacetic acid (HPAA), or any combination thereof. Aspect 8 is a nanoparticle according to any of aspects 1-7, wherein the hydrocarbon formation and/or well treatment additive permeates the volume of the nanoparticle. Aspect 9 is a nanoparticle according to any of aspects 1-8, wherein the additive is DTPMPA and the nanoparticle contains SiO ₂ -Ca. Aspect 10 is a nanoparticle according to any of aspects 1-9, wherein the hydrocarbon formation and/or well treatment additive is chemically bonded to the nanoparticle through ionic bonding, covalent bonding, hydrogen bonding, van der Waals interaction, or adsorption on the particle. Aspect 11 is a nanoparticle according to any of aspects 1-10, wherein the additive is capable of being released from the nanoparticle in a controlled manner over an extended period of time, for example, at least 500 days, at least 1000 days, at least 2000 days, at least for 500 to 2500 days or at least for 500 to 2000 days after use.

Aspect 12 is a nanoparticle having the following formula

- 4 044915

A/[SixMz]On, wherein Si and M are contained in the crystal lattice structure of the nanoparticle, M being a Group 2 metal, a transition metal, a Group 14 metal, or any combination thereof;

x is from 0.03 to 3, z is from 0.01 to 0.4 and n is determined by the oxidation states of the metals Si, M; And

A is a hydrocarbon reservoir or well treatment additive capable of being released from a nanoparticle, the nanoparticle having a particle size of less than 300 nm.

Aspect 13 is a nanoparticle according to aspect 12, in which M represents beryllium (Be), magnesium (Mg), calcium (Ca), strontium (Sr), barium (Ba) and radium (Ra). Aspect 14 is a nanoparticle according to aspect 12, in which M represents calcium (Ca). Aspect 15 is a nanoparticle according to any of aspects 12-14, wherein A is a scale inhibitor, hydrate inhibitor, clay stabilizer, germicidal agent, salt replacer, relative permeability modifier, sulfide scavenger, corrosion inhibitor, corrosion inhibitor enhancer, pH adjusting agent, surfactant, thinner, filterability regulator, asphaltene deposition inhibitor, wax deposition inhibitor, complexing agent, foaming agent, defoaming agent, emulsifier, demulsifier, iron content regulator, solvent, friction reducer, or any combination thereof. Aspect 16 is a nanoparticle according to aspect 15, wherein the additive is a scale inhibitor. Aspect 17 is a nanoparticle according to aspect 16, wherein the scale inhibitor is an organic molecule in which carboxylic acid, polycarboxylic acid, aspartic acid, maleic acid, sulfonic acid, phosphonic acid or phosphoric acid ester groups, or corresponding salts, are present. Aspect 18 is a nanoparticle according to aspect 17, in which the scale inhibitor contains a phosphonic acid functional group, and preferably diethylenetriaminepenta(methylenephosphonic acid) (DTPMPA), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (HMTMP) are present in the composition or as the scale inhibitor ), ethylenediaminetetra(methylenephosphonic acid) (EDTMPA), aminotrimethylenephosphonic acid (ATMP), polyaminoprostopolyethermethylenephosphonic acid (PAREMP), hydroxyethylaminedi(methylenephosphonic acid) (HEMPA) or a combination thereof, preferably DTPMPA and/or HEMPA, and/or a scale inhibitor contains 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), 2-hydroxyphosphonoacetic acid (HPAA), or any combination thereof. Aspect 19 is a nanoparticle according to any of aspects 12-18, wherein additive A permeates the volume of the nanoparticle. Aspect 20 is a nanoparticle according to any of aspects 12-18, wherein additive A is chemically bonded to the nanoparticle through ionic bonding, covalent bonding, hydrogen bonding, van der Waals interaction, or adsorption onto the particle. Aspect 21 is a nanoparticle according to any of aspects 12-20, wherein the particle size is from 1 to 300 nm, preferably from 10 to 250 nm, or more preferably from 50 to 200 nm. Aspect 22 is a nanoparticle according to any of aspects 12-21, wherein the additive is capable of being released from the nanoparticle in a controlled manner over an extended period of time, for example, at least 500 days, at least 1000 days, at least 2000 days, at least for 500 to 2500 days or at least for 500 to 2000 days after use.

Aspect 23 is a well treatment composition comprising a plurality of nanoparticles according to any of aspects 1-22. Aspect 24 is a well treatment composition according to aspect 23, wherein the composition is a fluid. Aspect 25 is a well treatment composition according to any of aspects 23-24, wherein the well treatment composition is a controlled release composition that is capable of releasing the well treatment additive over an extended period of time, such as at least 500 days , at least for 1000 days, for at least 2000 days, for at least 500 to 2500 days, or for at least 500 to 2000 days after use. Aspect 26 is a well treatment composition according to any of aspects 23-25, which further contains water, an aqueous brine solution, an acidic aqueous solution, low sulfate seawater, an aqueous sodium carbonate solution, a surfactant or other flushing fluid, or any combination of them.

Aspect 27 is a method of treating a hydrocarbon formation or wellbore, comprising introducing a composition according to any of aspects 23-26 into the wellbore, the wellbore penetrating a subterranean formation. Aspect 28 is the method of aspect 27, wherein the treatment is pressure treatment, continuous treatment, or tubing treatment of a subterranean well formation or wellbore. Aspect 29 is a method according to any of aspects 27-28, in which the additive is released from the nanoparticle over an extended period of time.

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Aspect 30 is a method of making a nanoparticle according to any of aspects 1-11, the method comprising (a) adding a metal salt solution containing a Group 2 metal salt, a Group 14 metal salt or a transition metal salt, or a mixture thereof, to an aqueous silica solution, having a pH of from 2.5 to 3.3, to form a suspension containing nanoparticles of the metal-SiO ₂ type, where the metal is a group 2 metal, a group 14 metal or a transition metal; and (b) introducing a hydrocarbon formation or well treatment additive into the nanoparticle.

Aspect 31 is the method of aspect 30 wherein steps (a) and (b) omit the surfactant and piperazine-K,K'-bis(2-ethanesulfonic acid). Aspect 32 is a method according to any of aspects 30-31, the method further comprising removing water from an aqueous solution, preferably at a temperature of from 70 to 150°C for 0.1 to 24 hours. Aspect 33 is a method according to aspect 32. wherein the SiO ₂ content is from 0.2 to 5 wt.% and the metal content is from 0.18 to 0.22 M. Aspect 34 is a method according to any of aspects 30-33, in which step (c) includes introducing contacting the nanoparticles with a well treatment additive to form a mixture; and ultrasonicating the mixture at a pH of 9 to 10 to form a nanoparticle containing the well treatment additive embedded therein. Aspect 35 is a method according to any one of aspects 30-34, wherein the solution of a group 2 metal salt or a transition metal salt has a pH value of from 5.5 to 6.5, preferably 6. Aspect 36 is a method according to any one aspect 30-35, wherein the nanoparticle in step (c) contains at least 0.1 wt.%, preferably from 2 to 15 wt.%, additive relative to the total weight of the additive-containing nanoparticle. Aspect 37 is a method according to any of aspects 30-36, wherein the metal salt solution is an aqueous solution of calcium chloride. Aspect 38 is a method according to any of aspects 30-37, wherein water is removed by evaporation. Aspect 39 is the method according to aspect 38, in which the evaporation is carried out at a temperature of from 70 to 100°C.

Aspect 40 is a method of introducing an additive into a subterranean formation, comprising introducing a composition comprising (i) a nanoparticle according to any of aspects 1-22 into the subterranean formation or (ii) introducing a well treatment composition according to any of aspects 23-27 into the subterranean formation. . Aspect 41 is the method of aspect 40, wherein introducing the composition into a subterranean formation includes introducing the composition into a drilling fluid. Aspect 42 is the method of aspect 40, wherein introducing the composition into a subterranean formation includes introducing the composition into a fluid to enhance oil recovery.

The following are definitions of various terms and expressions used throughout the specification of the present invention.

The term releasable, as it relates to a subterranean well treatment additive, means that under conditions of use, such as in a subterranean well, the well treatment additive dissociates, hydrolyzes, becomes chemically unbound, or is otherwise separated from the nanoparticle and is available for use in accordance with a given purpose, for example, as a scale inhibitor in an underground well.

The term controlled release over an extended period of time refers to the rate of release of the underground well treatment additive from the nanoparticles and means that under application conditions such as, for example, an underground well, the additive is released from the nanoparticle over a longer period of time than if the additive was not adsorbed or otherwise attached to the nanoparticle according to the present invention.

The terms formation fluid or formation fluids mean liquids and gases that are present in a formation. Non-limiting examples of formation fluids include liquid and gaseous hydrocarbons, water, brine containing sulfur and/or hydrocarbons, inorganic liquids and gases, and the like.

The terms approximately or approximately are defined such that they mean approximation as understood by one of ordinary skill in the art. In a non-limiting embodiment, these terms are defined to be within 10%, preferably within 5%, more preferably within 1%, and most preferably within 0.5%.

The terms wt.%, vol.% or mol.% mean the mass, volume or molar percentage of a component, respectively, relative to the total weight, total volume or total number of moles of the material in which the component is contained. As a non-limiting example, 10 g of a component in 100 g of material represents 10% by weight of that component.

The term practically and its variations are defined to be ranges within 10%, within 5%, within 1% or within 0.5%.

The terms inhibit, or reduce, or prevent, or avoid, or any modification of these terms, as used in the claims and/or description of the present invention, mean any measurable reduction or complete inhibition to achieve the desired result. The term effective, as used in the claims and/or description of the present invention, means sufficient to achieve the desired, expected or intended result.

The use of singular grammatical forms in combination with any of the terms including, including, containing or having in the claims and/or description of the present invention may mean one, but it also means one or more, at least one and one or more than one .

The nanoparticles and methods of the present invention may contain, consist primarily of, or consist of specific elements, ingredients, components, compositions, and other items that are disclosed throughout the specification of the present invention. In terms of transitional expression consisting primarily of, in one non-limiting aspect, the primary and novel characteristic of the nanoparticles of the present invention is their ability to introduce a controlled release well treatment additive over an extended period of time during application (eg, in underground wells).

The terms including (as well as any forms of including, such as include and include), having (as well as any forms of having, such as have and has), containing (as well as any forms of containing, such as contain and contains) or encompassing (as well as any forms of the word encompassing, such as embrace and covers) are inclusive or non-limiting, and do not exclude additional elements or technological steps that are not listed.

Other objects, features and advantages of the present invention will become apparent from the following figures, detailed description and examples. However, it should be understood that while these figures, detailed description and examples represent specific embodiments of the present invention, they are provided for illustrative purposes only and are not intended to be limiting. It is further intended that changes and modifications within the spirit and scope of the present invention will become apparent to those skilled in the art from this detailed description.

Brief description of the figures

In fig. 1 is a schematic representation of a method for treating a subterranean well using nanoparticles according to the present invention containing a subterranean well treatment additive.

In fig. Figure 2 shows a graph of the dependence of the nanoparticle size in micrometers on the bulk density in percent with and without the use of ultrasonic treatment.

In fig. 3 is a graph of countercurrent performance versus nanoparticle composition of the present invention in packed glass columns.

In fig. 4 is a graph of countercurrent performance versus nanoparticle composition of the present invention in an intact core.

In fig. 5 is a graph of countercurrent performance versus nanoparticle composition of the present invention in an intact core with KCl injection, sodium dodecylbenzenesulfonate (SDBS) injection, and injection of the present invention.

In fig. 6 is a plot of the on-line performance of the nanoparticle composition of the present invention with the core intact using DTPMP as an additive and the DTPMP described above.

Detailed Disclosure of the Present Invention

The present invention provides nanoparticle carriers containing additives intended for subsurface treatment (eg, well treatment additives). These nanoparticle carriers can provide sustained or sustained release of the additive for treating subterranean wells under application conditions, such as subterranean oil, gas or water wells, or any subterranean formation. It should be noted that the average particle size in the case of nanoparticles is less than 300 nm, which provides the advantage of minimal formation damage when introduced into a subterranean formation, wellbore or well. The controlled release of such additives over an extended period of time reduces or eliminates the need to re-treat wells or subterranean formations (eg, hydrocarbon formations) with such additives, and also provides reduced cost, labor intensity and reduced environmental impact. The present invention provides for binding or adsorbing an additive to nanoparticles that are silica-based nanoparticles that contain a Group 2 metal or a transition metal. These nanoparticle-based carriers can be obtained by performing the following operations:

(1) contacting an aqueous dispersion of silica nanoparticles with an aqueous solution containing a salt or alkoxide of a Group 2 metal, a Group 14 metal, or a transition metal at a pH of 2.5 to 3.3 to form a silica metal oxide nanoparticle ; and (2) incorporating a subsurface treatment additive (eg, a well treatment additive) into the nanoparticle. Without wishing to be bound by theory, the authors believe that a Group 2 metal, a Group 14 metal, or a transition metal is introduced into the Si-O lattice.

The present invention provides an elegant way to offer low-cost and

- 7 044915 low-cost methods of introducing a subterranean well treatment additive, such as a scale inhibitor, into wells in a manner that releases the additive over an extended period of time while reducing or eliminating the need to re-treat wells with such additives . In addition, the present invention provides effective methods for introducing additives into fluids used for the purpose of extracting fluids (eg, oil and gas) from subterranean formations. For example, additives can be added as additives to drilling fluids (drilling fluids), enhanced oil recovery (EOR) fluids, etc.

The above and other non-limiting aspects of the present invention are discussed in more detail in the following sections.

A) Nanoparticles containing an additive for the treatment of underground wells.

The well treatment additive-containing nanoparticle (additive-containing nanoparticle) of the present invention is a silicon metal oxide (SiMO) nanoparticle, wherein M is a metal allowing the well treatment additive to attach to the nanoparticle such that the additive for treating underground wells, small but effective quantities are released from the nanoparticle over a period of time. Additive-containing nanoparticles are discussed in more detail in the following sections.

1. Carriers based on nanoparticles of complex metal and silicon oxides.

The nanoparticles of the present invention may contain silicon and a Group 2 metal, a Group 14 metal or a transition metal. These metals can form a complex metal oxide crystal lattice. M metals may be Group 2 metals or transition metals of the Periodic Table of elements. In some embodiments, the nanoparticle contains silicon and a Group 2 metal, preferably Ca. In other embodiments, the nanoparticle contains silicon and a transition metal. Non-limiting examples of Group 2 metals include beryllium (Be), magnesium (Mg), calcium (Ca), strontium (Sr), barium (Ba) and radium (Ra). Non-limiting examples of Groups 3-12 transition metals are scandium (Sc), titanium (Ti), vanadium (V), chromium (Cr), manganese (Mn), iron (Fe), cobalt (Co), nickel (Ni), copper (Cu), zinc (Zn), yttrium (Y), zirconium (Zr), niobium (Nb), molybdenum (Mo), technetium (Tc), ruthenium (Ru), rhodium (Rh), palladium (Pd), silver (Ag), cadmium (Cd), hafnium (Hf), tantalum (Ta), tungsten (W), rhenium (Re), osmium (Os), iridium (Ir), platinum (Pt), gold (Au), mercury (Hg), rutherfordium (Rf), dubnium (Db), seaborgium (Sg), bohrium (Bh), hassium (Hs), meitnerium (Mt), darmstadtium (Ds), roentgenium (Rg) and copernicium (Cn). In some embodiments, the Group 14 metals of tin (Sn), lead (Pb), and germanium (Ge) may be used.

Nanoparticles according to the present invention may have the general formula

A/[SixMz]On, where A is a subsurface well treatment additive capable of being released from the nanoparticle, and Si and M are contained in the crystal lattice structure of the nanoparticle.

M may be a Group 2 metal, optionally a Group 14 metal or a transition metal, or a combination thereof. Each metal M ² and M ³ may independently be beryllium (Be), magnesium (Mg), calcium (Ca), strontium (Sr), barium (Ba), radium (Ra), or combinations thereof. In a particular embodiment, Ca is particularly preferred. The molar amounts of each metal are indicated by x and z, with x ranging from 0.03 to 3 and z ranging from 0.01 to 0.4. The molar amount of oxygen is indicated by the letter n. In some embodiments, the nanoparticle contains hydrogen ions. The molar amount of oxygen is determined by the oxidation states of the metals Si and M. If hydrogen is present, the molar amount of hydrogen is determined by the degrees of hydrolysis of the metals Si and M in the crystal lattice. According to the present invention, x may be in the range of 0.03 to 3, 0.5 to 1, 2 to 3, or 0.03, 0.05, 0.1, 0.15, 1.0, 1.05 , 1.1, 1.15, 2.0, 2.05, 2.1, 2.15, 3.0 or any intermediate value in this range, and z can be in the range from 0 to 0.4, preferably from 0.1 to 0.3 and more preferably from 0.1 to 0.2 or 0.01, 0.05, 0.1, 0.15, 0.2, 0.25, 0.3, 0, 35, 0.4 or any value in between, n may range from 1 to 10, preferably from 2 to 8 and most preferably from 3 to 5 or 1, 2, 3, 4, 5, 6, 7 , 8, 9, 10 or take any intermediate value in this range. Without wishing to be bound by theory, the authors believe that the amount of hydrogen may be related to the degree of hydrolysis. In a fully hydrolyzed crystal, which is the hydroxide phase, the molar concentration of oxygen is equal to the molar concentration of hydrogen.

The nanoparticles may have a metal atomic ratio ranging from about 1 to about 99. For example, in one aspect, the Si/M atomic ratio may range from 20 to 80 or 40 to 75, or 90:5, 50:25, 50:30, 40:50 or any intermediate value in this range. The ratio of oxygen to metals will depend mainly on the oxidation state of the metals and can vary accordingly.

The nanoparticles according to the present invention have physical properties that can be

- 8 044915 provide controlled release of the additive for treating underground wells over an extended period of time. The nanoparticles may have an average diameter of 0.1 to 300 nm, preferably 10 to 200 nm, and more preferably 5 to 175 nm, 2 to 12 nm, or 5 to 10 nm, or 2, 3, 4, 5, 6 , 7, 8, 9, 10, 11, 12 nm, or be in any intermediate range, or take any intermediate value that can be measured using a laser particle sizing instrument and a transmission electron microscope (TEM).

2. Additive for treating underground wells.

Subterranean well treatment additives are additives that can modify or inhibit the performance of a material or fluid in a subterranean well, formation, etc. The subterranean well treatment additive may be released from the nanoparticle in response to a stimulus (eg, formation fluid, water, or pressure). The additive may bind to the nanoparticle, for example, chemically through the formation of an ionic bond, and/or it may attach to the nanoparticle. Non-limiting examples of bonds that the nanoparticle and additive form are ionic bonding, covalent bonding, hydrogen bonding, and van der Waals interactions. Adhesion to the nanoparticle can be through absorption or adsorption onto the particle.

Non-limiting examples of subsurface well treatment additives include scale inhibitor, hydrate inhibitor, clay stabilizer, germicidal agent, salt replacer, relative permeability modifier, sulfide scavenger, corrosion inhibitor, corrosion inhibitor enhancer, pH adjuster, surfactant, diluent, filterability regulator, asphaltene precipitation inhibitor, wax precipitation inhibitor, complexing agent, foaming agent, defoaming agent, emulsifier, demulsifier, iron content regulator, solvent, friction reducer, or any combination thereof. A scale inhibitor is a particularly preferred additive for treating underground wells. The scale inhibitor may be a molecule, preferably an organic molecule, containing a functionalized group that can form particulate bonds. Non-limiting examples of functionalized groups are carboxylic acid, polycarboxylic acid, aspartic acid, maleic acid, sulfonic acid, phosphonic acid or phosphoric acid ester groups, or the corresponding salts. A preferred scale inhibitor may contain a phosphonic acid group. Another preferred scale inhibitor may contain a sulfonated polycarboxylic acid (SPCA) group. In some particularly preferred aspects, diethylenetriaminepenta(methylenephosphonic acid) (DTPMPA), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (HMPTPMP), ethylenediaminetetra(methylenephosphonic acid) (EDTMPA), aminotrimethylenephosphonic acid (ATMP) may be present in the formulation or as a scale inhibitor. , polyaminoprostopolyethermethylenephosphonic acid (PAREMP), hydroxyethylamino-di(methylenephosphonic acid) (HEMPA) or a combination thereof, preferably DTPMPA and/or HEMPA. In some aspects, DTPMPA is a particularly preferred scale inhibitor that is available from a variety of commercial sources. As some examples, the scale inhibitor may contain 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), 2-hydroxyphosphonoacetic acid (HPAA), or any combination thereof.

B. Methods for producing nanoparticles.

The nanoparticles of the present invention can be prepared by contacting silicon nanoparticles with a metal salt solution at a pH of 2.5 to 3.3 to form metal-silicon composite oxide nanoparticles. The subsurface well treatment additive can then be incorporated into the metal oxide silica nanoparticles using infiltration or coating methods. These methods are described in more detail below in the examples section.

In the first stage of the method, an aqueous solution containing silicon dioxide or silicon alkoxide and a metal salt or alkoxide can be obtained. The aqueous solution may contain from 0.01 to 10 wt.% Si, from 0.1 to 7.5 wt.% Si, from 1.0 to 5 wt.% Si, or from 2 to 3 wt.% Si, from 0 .01 to 1 wt.% M, 0.1 to 0.5 wt.% M, or 0.25 to 0.3 wt.% M, where M is a Group 2 metal, a transition metal, or a Group 14 metal. The pH value of the aqueous silica dispersion or solution can be from 2.5 to 3.3, or 2.5, 2.6, 2.7, 2.8, 2.9, 3.0, 3.1, 3, 2, or 3.3 or take any intermediate value in this range. In a preferred aspect, the pH value is approximately 3.0.

Non-limiting examples of alkoxides that can form bonds with Si and/or M include methoxide, ethoxide, propoxide, isopropoxide, sec-butoxide, isobutoxide, 2-ethylhexoxide, tert-butoxide, hexafluoro-tert-butoxide, tri-sec-butoxide or combinations thereof. In some embodiments, SiO ₂ is used in nanoparticle form.

The metal (M) may be present in various oxidation states in metallic, oxide, hydroxide or salt form, generally depending on the properties of each metal, such as stability, reactivity and/or physical/chemical properties, and preferably

- 9 044915 water-soluble salts or alkoxides are definitely present. For the manufacture of nanoparticles, metals can be present in stable oxidation states in the form of complexes that form monodentate, bidentate, tridentate or tetradentate coordinating ligands such as, for example, iodide, bromide, sulfide, thiocyanate, chloride, nitrate, azide, acetate, fluoride, hydroxide , oxalate, water, isothiocyanate, acetonitrile, pyridine, ammonia, ethylenediamine, 2,2'-bipyridine, 1,10-phenanthroline, nitrite, triphenylphosphine, cyanide or carbon monoxide. Various industrial sources can be used to prepare metal salts or alkoxides. A non-limiting example of an industrial source of the above metals and metal oxides is Millipore (USA). The metal M is preferably present in the form of an inorganic or organic metal salt, in particular in the form of a water-soluble metal salt such as halide salts, for example chlorides, bromides, iodides, fluorides; nitrates, nitrites, sulfates, etc. Organic metal salts may be acetates, carbonates, citrates, and the like. Preferably M is calcium, which is preferably present in the form of the corresponding chloride salt, such as calcium chloride (CaCl ₂ ). An aqueous solution of a Group 2 metal salt, a Group 14 metal salt, or a transition metal salt may have a pH value of 5.5 to 6.5, or 5.5, 5.7, 5.8, 5.9, 6.0 , 6.1, 6.2, 6.3, 6.4, 6.5, or being in any intermediate range or taking any intermediate value. As one preferred example, the pH value is approximately 6. Adding a metal salt solution to the silica dispersion or solution increases the initial pH value of the solution.

In some embodiments, the volume of the dispersion or solution, if alkoxides are used, can be reduced using known solvent removal/concentration techniques. When the amount of water and/or alcohol is reduced, nanoparticles may precipitate out of solution. For example, evaporation can be carried out at atmospheric or reduced pressure until nanoparticles are formed in an aqueous solution. In some embodiments, the water and/or alcohol may be removed at a temperature of 60 to 150°C, preferably 70 to 100°C, or 60, 65, 70, 75, 80, 85, 90, 95, 100, 105, 110, 120, 125, 130, 135, 140, 145 or 150°C, or any intermediate value in this range, at atmospheric pressure. In some embodiments, the water and/or alcohol is evaporated at a temperature of 70° C. and atmospheric pressure. The precipitation step can be carried out over a period of time ranging from about 0.1 hour to about 48 hours, preferably from about 1 hour to about 24 hours, most preferably from about 1.5 hours to about 10 hours.

The subterranean well treatment additive can be incorporated into the metal-silica nanoparticle using known infiltration and/or coating techniques. As an example, a subsurface well treatment additive may be mixed with complex metal oxide silica nanoparticles to form a mixture. The mixture can be agitated (eg, by ultrasonication) to form an additive-containing metal silica nanoparticle according to the present invention, wherein the subterranean well treatment additive is contained within or on the surface of the nanoparticle. According to a preferred aspect of the present invention, the nanoparticle of the present invention may contain at least 0.1 to 70 wt.%, or 80 wt.%, or 0.1, 0.5, 1, 5, 10, 15, 20, 25 , 30, 35, 40, 45, 50, 55, 60, 65, 70, 75, 80, 85 wt.% additives for well treatment. Without wishing to be bound by theory, the authors believe that the subterranean well treatment additive may be chemically bonded to the metal-silica nanoparticle through ionic bonding, covalent bonding, hydrogen bonding, van der Waals interaction, or through absorption or adsorption onto the particle. In some embodiments, the additive is incorporated into the interstices of the lattice structure. In some embodiments, the nanoparticles can be separated from the anions (eg, Cl ^- ) of the salt that is the precursor material. In some embodiments, the additive may be administered at a temperature of 60 to 150°C, preferably 70 to 100°C, or 60, 65, 70, 75, 80, 85, 90, 95, 100, 105, 110 , 120, 125, 130, 135, 140, 145 or 150°C, or any intermediate value within this range, at atmospheric pressure. In some embodiments, the water and/or alcohol is vaporized at a temperature of 70°C and atmospheric pressure. When adding an additive, the pH value of the dispersion or the pH value of the solution can increase to a level of 9 to 10. The final pH value can be 9, 9.1, 9.2, 9.3, 9.4, 9.5, 9.6, 9.7, 9.8, 9.9 or 10, or be in or take any value in between. The additive addition step can be carried out over a period of time ranging from about 0.1 hour to about 48 hours, preferably from about 1 hour to about 24 hours, most preferably from about 1.5 hours to about 10 hours. The final solution contains SiO ₂ is from 0.2 to 5 wt.% and the metal content is from 0.18 to 0.22 M. In some embodiments, the addition of the additive can be accomplished using a flow tank in combination with ultrasonic treatment. In some embodiments, the sonication device is a field sonication device.

- 10 044915

The additive is capable of being released from the nanoparticle in a controlled manner over an extended period of time, for example, at least 10 days, 1 month, 6 months, 1 year, 5 years or 10 years. In particularly preferred embodiments, at least some of the additive is released for at least 2000 days after use.

C. Compositions for treating underground wells.

The additive-containing nanoparticles of the present invention may be delivered to the treatment site in the form of individual nanoparticles or in the form of a subsurface treatment composition (eg, a subsurface well treatment composition). As an example, the composition for treating underground wells may contain a fluid (eg, a water-based liquid, particularly a suspension) in which a plurality of additive-containing nanoparticles are present. The composition may be a controlled release composition that is capable of releasing the subterranean well treatment additive over an extended period of time. These compositions can be prepared by mixing the additive-containing nanoparticles of the present invention with a fluid that will be introduced into the well. Non-limiting examples of the fluid in the subsurface treatment composition are water, an aqueous salt solution (KCl), an acidic aqueous solution, low sulfate seawater, an aqueous sodium carbonate solution, a surfactant or other flushing fluid, or a non-aqueous fluid may be present ( for example, an oil or natural gas based fluid may be present), or a combination of non-aqueous and aqueous fluids may be present.

D. Methods of treating underground wells or boreholes.

The additive-containing nanoparticle or composition of additive-containing nanoparticles can be introduced into a subterranean formation using a variety of methods such as pumping, pressure injection, etc. In some embodiments, the method used is the application of pressure or continuous processing. In fig. 1 illustrates a method for treating a subterranean formation, well, or wellbore. When introduced for well treatment, the additive-containing nanoparticles can be used to introduce additives into a subterranean formation for other purposes (eg, to add drilling fluid additives to drilling fluids or enhanced oil recovery fluids, etc.). The wells 102 may penetrate a subterranean formation and may be injection wells, production wells, water wells, etc. As illustrated, wells 102 are vertical wells, but they can also be horizontal wells. The wells 102 may be open boreholes, cased boreholes, etc. In method 100, prior to production from well 102, additive-containing nanoparticles or compositions of the present invention may be introduced into one or more wells 102 and may then flow through the well into a subterranean formation 104, as represented by arrow 108. Additive-containing nanoparticles 110 may be applied on rock 106 in an underground formation. Known drilling equipment (eg, oil, gas, or water drilling equipment) can be used to introduce subterranean well treatment compositions into wells 102 (eg, using a pressurized method, a continuous method, or a trap method). The nanoparticles may be adsorbed to the rock 106, and the additive coated on the nanoparticle may be released into the well 102 in an effective amount to perform a desired function (eg, scale inhibition) when the well is brought into production. As illustrated in FIG. 1, the fluid may flow through the rock, as represented by arrow 112, and dissolve or desorb a small amount of the well treatment additive from the nanoparticle. The formation fluid containing the well treatment additive then flows into the well. The well treatment additive may coat or interact with the well materials or fluid in the well to treat the well (eg, inhibit scale formation). By way of example, the well treatment additive may be a scale inhibitor, and upon contact of the formation fluid with the scale inhibitor, an effective amount of the scale inhibitor is dissolved or desorbed from the nanoparticle and the scale inhibitor is carried into the wellbore. The scale inhibitor may interact with the wellbore material and/or fluids in the wellbore to inhibit the formation of scale on the interior of the wellbore wall 102. The composition of the nanoparticle and the attachment of the additive to the nanoparticle ensures that an effective amount of the additive is released from the nanoparticle over an extended period of time (e.g., for more than five years).

Examples

The present invention will be described in more detail by means of specific examples. The following examples are presented for illustrative purposes only and are not intended to limit the present invention in any way. Those skilled in the art will readily be able to identify a variety of non-critical parameters that can be changed or modified to obtain substantially the same results.

Example 1. Production of nanoparticles.

- 11 044915

Calcium chloride (CaCl ₂ , Sigma Aldrich) was dissolved in deionized water (180 ml) to obtain a solution having a concentration of 1 M and pH 6.0. A SiO ₂ dispersion was obtained (a fluid containing silicon dioxide nanoparticles at a concentration of 5 wt.% in a volume of 18.75 ml). The calcium chloride solution was added dropwise during vigorous stirring into a fluid containing silica nanoparticles. The pH value of the Ca-SiO ₂ colloidal solution was adjusted to 3 by adding hydrochloric acid. At a pH value of exactly or approximately 3, Ca-SiO ₂ nanoparticles have a high positive surface charge, which allows them to disperse in suspension to form stable colloids. DTPMP stock solution (17.2 ml) was added to the Ca-SiO ₂ solution using a syringe pump at a rate of 10 ml/h. The DTPMP/Ca-SiO ₂ solution was sonicated for 1 to 5 min at pH 7.4. After ultrasonication of the particles, the average particle size was between 185 and 190 nm. The total energy transferred to the sample was approximately 3300 J. In FIG. Figure 2 shows the sizes of DTPMP/CaSiO ₂ nanoparticles before and after ultrasonic treatment and filtration. Large particles were observed in the non-sonicated product, but ultrasonication for one minute reduced most of these agglomerates to nanometer particle sizes. By filtering the solution through a 0.7 µm filter, it was possible to remove a few large particles. One day after ultrasonication of the sample, no significant precipitation was detected, and thus the filtration step could be omitted from the synthesis. The amount of DTPMP introduced into the nanoparticle was 4.4 wt.% when determined by the inductively coupled plasma (ICP) method. The final solution had a pH value of 7.34, was translucent and exhibited a light amber color.

Example 2: Pressure experiment using DTPMP/Ca-SiO ₂ and comparative DTPMP.

A pressure experiment was carried out using a glass column filled with crushed core at a temperature of 70°C. Back pressure was maintained at 100 psi. The DTPMP threshold for stopping backflow was set at 1 ppm. The Ca phosphonate containing nanoparticle product had 4513 pore volumes and the product life was greater than 200% DTPMP recovery compared to unmodified DTPMP at pH 7. No pressure buildup was observed during the experiment and there was no blockage in the crushed core and in the tube. In table 1 shows a comparison of pore volume for three experiments carried out with a nanoparticle according to the present invention and DTPMP at different pH values. In fig. 3 shows countercurrent performance in packed glass columns for the nanoparticle of the present invention and unmodified DTPMP at various pH values. In fig. Figure 4 shows the countercurrent performance characteristics in an intact core. The graph below (see Fig. 5) shows the pressure difference during the injection stages. No increase in pressure was observed with the introduction of the product compared to KCl. In fig. 6 shows pressurized flow experiments with an intact core and nanoparticle according to the present invention and the previously used DTPMP. The nanoparticle of the present invention, at the same dosage, exhibited higher Si recovery concentration and increased lifetime efficiency, with recompression duration being significantly increased with increasing recovery per inhibitor active unit.

Table 1

Product Pore volume (at DTPMP > 1 ppm) Product containing nanoparticles with 4.4 wt.% DTPMP at pH 7.4 4513 Unmodified DTPMP 4.4 wt.% at pH 4.6 1860 Unmodified DTPMP 4.4 wt.% at pH 7.4 2180

Example 3 Stability of DTPMP/Ca-SiO ₂

The nanoparticle prepared in Example 1 was kept at temperatures of 80, 150 and -17°C for 24 hours. The product was held to freeze and then kept at -17°C for 25 hours. PSA and pH values were measured after the sample reached room temperature. No precipitation or change in particle size was observed. In addition, no change in particle size or pH value was observed. In table 2-4 show the results. The product was kept in a solution of 7 wt.% KCl. In table 5 presents the results of the study. No precipitation or change in particle size was observed, providing evidence of product stability up to 7 wt.% KCl. The product was kept at different pH values. The product was determined to be stable at pH values between 7.19 and 8.65. The product was exposed to low and high shear stresses produced by submersible mixers for one minute. As presented in table. 6, no precipitation or change in particle sizes or pH values was observed. Emulsions were prepared using 5, 10 and 30 vol.% water collected during pressure experiments with the core intact (see example 2) for a product representing

- 12 044915 containing nanoparticles, and DTPMP with crude oil having a gravity of 34.9 degrees American Petroleum Institute (API) at 60°F. Solutions were emulsified using low shear immersion mixers. The emulsions were allowed to separate for 3 min. The nanoparticle product of the present invention did not affect emulsion separation. In addition, the observed concentration of the nanoparticles of the present invention in the reflux from the intact core was negligible and, as a result, no effect of the nanoparticles of the present invention was expected under typical manufacturing conditions.

table 2

Experiment at 80°C (24 hours at 80°C) Before After P.S.A. 16-155 nm 16-155 nm pH 7.25 7.04

Table 3

Experiment at 150°C (24 hours at 150°C) Before After P.S.A. 16-155 nm 18-177 nm (7% maximum intensity) and 11-33 µm (0.2% maximum intensity) pH 7.25 7.12

Table 4

Experiment at -17°C (24 hours at -17°C) Before After P.S.A. 16-155 nm 18-156 nm pH 7.25 7.22

Table 5

7%KS1 Before (without KS1) After(7%KS1) P.S.A. 16-155 nm 16-155 nm pH 7.25 7.10

Table 6

Before shear stress Low shift (1 min) High shift (1 min) PSA (nm) 16-155 14-155 14-155 pH 7.82 7.82 7.82

CLAIM

Claims (42)

1. A nanoparticle containing a releasable additive for the treatment of hydrocarbon formations and/or wells attached to the nanoparticle, wherein the nanoparticle contains silicon dioxide and at least one metal forming a complex oxide with silicon dioxide, and the nanoparticle has a particle size of less than 300 nm , wherein the metal chosen is a Group 2 metal and/or a transition metal. 2. Nanoparticle according to claim 1, wherein the metal is calcium (Ca). 3. Nanoparticle according to any one of claims 1, 2, where the particle size is from 0.1 to 300 nm, preferably from 10 to 250 nm. 4. Nanoparticle according to any one of claims 1, 2, in which the additive for treating hydrocarbon formations and/or wells is a scale inhibitor, hydrate formation inhibitor, clay stabilizer, bactericidal substance, salt substitute, relative permeability modifier, sulfide absorber, inhibitor corrosion inhibitor, corrosion inhibitor enhancer, pH adjusting agent, surfactant, thinner, filterability regulator, asphaltene deposition inhibitor, wax deposition inhibitor, complexing agent, foaming agent, defoaming agent, emulsifier, demulsifier, iron content regulator, solvent, friction reducer or any their combination. 5. Nanoparticle according to claim 4, in which the additive is a scale inhibitor. 6. Nanoparticle according to claim 5, in which the scale inhibitor is an organic molecule in which groups of esters of carboxylic acid, polycarboxylic acid, aspartic acid, maleic acid, sulfonic acid, phosphonic acid, phosphoric acid or their corresponding salts are present. 7. Nanoparticle according to claim 5, in which the scale inhibitor contains a phosphonic acid functional group, and the scale inhibitor preferably contains diethylenetriaminepenta(methylenephosphonic acid) (DTPMPA), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (BHMTPMP), ethylenediaminetetra(methylenephosphonic acid) acid) (EDTMPA), aminotrimethylene- - 13 044915 phosphonic acid (ATMP), polyaminopolyethermethylenephosphonic acid (PAREMP), hydroxyethylamino-di(methylenephosphonic acid) (HEMPA) or a combination thereof, preferably DTPMPA and/or HEMPA and/or the scale inhibitor contains 1-hydroxyethylidene-1,1-diphosphonic acid (HEDP), 2-phosphonobutane-1,2,4-tricarboxylic acid (PBTC), 2-hydroxyphosphonoacetic acid (HPAA) or any of them combination. 8. Nanoparticle according to any one of claims 1, 2, where the nanoparticle is impregnated in volume with an additive for treating hydrocarbon formations and/or wells. 9. Nanoparticle according to any one of claims 1, 2, in which the additive is DTPMPA, and the nanoparticle contains SiO ₂ -Ca. 10. Nanoparticle according to any one of claims 1, 2, in which the additive for treating hydrocarbon formations and/or wells is chemically bonded to the nanoparticle through ionic bonding, covalent bonding, hydrogen bonding, van der Waals interaction or adsorption on the particle. 11. Nanoparticle according to any one of claims 1, 2, where the additive is capable of being released from the nanoparticle in a controlled manner over an extended period of time, for example at least 500 days, at least 1000 days, at least 2000 days , at least for 500 to 2500 days or at least for 500 to 2000 days after application. 12. Nanoparticle having the following formula A/[SixMz]On, where Si and M are contained in the crystal lattice structure of the nanoparticle, M is a group 2 metal, a transition metal, a group 14 metal, or any combination thereof; x is from 0.03 to 3, z is from 0.01 to 0.4 and n is determined by the oxidation states of the metals Si, M; And A is a hydrocarbon reservoir or well treatment additive capable of being released from a nanoparticle, wherein the nanoparticle has a particle size of less than 300 nm. 13. Nanoparticle according to claim 12, in which M represents beryllium (Be), magnesium (Mg), calcium (Ca), strontium (Sr), barium (Ba) and radium (Ra). 14. Nanoparticle according to claim 12, in which M represents calcium (Ca). 15. Nanoparticle according to any one of claims 12-14, in which A is a scale inhibitor, a hydrate inhibitor, a clay stabilizer, a bactericidal agent, a salt substitute, a relative permeability modifier, a sulfide scavenger, a corrosion inhibitor, a corrosion inhibitor enhancer, a regulating pH agent, surfactant, thinner, filterability regulator, asphaltene deposition inhibitor, wax deposition inhibitor, complexing agent, foaming agent, defoamer, emulsifier, demulsifier, iron content regulator, solvent, friction reducer, or any combination thereof. 16. Nanoparticle according to claim 15, wherein the additive is a scale inhibitor. 17. The nanoparticle according to claim 16, wherein the scale inhibitor is an organic molecule in which carboxylic acid, polycarboxylic acid, aspartic acid, maleic acid, sulfonic acid, phosphonic acid, phosphoric acid ester groups or their corresponding salts are present. 18. Nanoparticle according to claim 17, in which the scale inhibitor contains a phosphonic acid functional group, and the scale inhibitor preferably contains diethylenetriaminepenta(methylenephosphonic acid) (DTPMPA), bis(hexamethylenetriaminepenta(methylenephosphonic acid)) (BHMTPMP), ethylenediaminetetra(methylenephosphonic acid) acid) (EDTMPA), aminotrimethylenephosphonic acid (ATMP), polyaminopolyethermethylenephosphonic acid (PAREMP), hydroxyethylamino-di(methylenephosphonic acid) (HEMPA) or a combination thereof, preferably DTPMPA and/or HEMPA, and/or the scale inhibitor contains 1-hydroxyethylidene -1,1-diphosphonic acid (HEDP), 2-phosphonobutane-1,2,4tricarboxylic acid (PBTC), 2-hydroxyphosphonoacetic acid (HPAA), or any combination thereof. 19. Nanoparticle according to any one of claims 12-14, where the nanoparticle is impregnated in volume with additive A. 20. Nanoparticle according to any one of claims 12 to 14, wherein additive A is chemically bonded to the nanoparticle through ionic bonding, covalent bonding, hydrogen bonding, van der Waals interaction or adsorption on the particle. 21. Nanoparticle according to any one of claims 12 to 14, where the particle size is from 1 to 300 nm, preferably from 10 to 250 nm, or more preferably from 50 to 200 nm. 22. Nanoparticle according to any one of claims 12 to 14, where the additive is capable of being released from the nanoparticle in a controlled manner over an extended period of time, preferably at least 500 days, at least 1000 days, at least 2000 days , at least for 500 to 2500 days or at least for 500 to 2000 days after application. 23. A composition for treating wells containing a plurality of nanoparticles according to any one of claims 1 to 22. 24. The composition for treating wells according to claim 23, where the composition is a fluid. - 14 044915 25. The well treatment composition according to any one of claims 23, 24, wherein the well treatment composition is a controlled release composition capable of releasing the well treatment additive over an extended period of time, preferably at least 500 days, at least at least within 1000 days, at least within 2000 days, at least within 500 to 2500 days, or at least within 500 to 2000 days after use. 26. The well treatment composition according to any one of claims 23, 24, further containing water, an aqueous salt solution, an acidic aqueous solution, low sulfate seawater, an aqueous sodium carbonate solution, a surfactant, or any combination thereof. 27. A method of treating a hydrocarbon formation or wellbore, comprising introducing a composition according to any one of claims 23-26 into the wellbore, where the wellbore penetrates a subterranean formation. 28. The method of claim 27, wherein the treatment is a pressure treatment, a continuous treatment, or a trap treatment of the subterranean well formation or wellbore. 29. Method according to any one of claims 27, 28, in which the additive is released from the nanoparticle over an extended period of time. 30. A method for producing a nanoparticle according to any one of claims 1 to 11, the method comprising (a) introducing a metal salt solution containing a Group 2 metal salt, a Group 14 metal salt or a transition metal salt, or a mixture thereof, into an aqueous silica solution having pH from 2.5 to 3.3, to form a suspension containing nanoparticles of the metal-SiO ₂ type, where the metal is a group 2 metal, a group 14 metal or a transition metal; and (b) introducing a hydrocarbon formation or well treatment additive into the nanoparticle. 31. The method according to claim 30, in which in stages (a) and (b) there is no surfactant and/or piperazine-K,K'-bis(2-ethanesulfonic acid). 32. The method according to any one of claims 30, 31, wherein the method further includes removing water from the aqueous solution, preferably at a temperature of from 70 to 150°C for from 0.1 to 24 hours. 33. The method according to claim 32, in which the SiO ₂ content is from 0.2 to 5 wt.% and the metal content is from 0.18 to 0.22 M. 34. The method according to any one of claims 30, 31, in which step (b) includes contacting the nanoparticle with a well treatment additive to form a mixture and ultrasonic treatment of the mixture at a pH of 9 to 10 to form a nanoparticle containing the additive introduced therein for well treatment. 35. The method according to any one of claims 30, 31, wherein the solution of a Group 2 metal salt or a transition metal salt has a pH value of from 5.5 to 6.5, preferably 6. 36. The method according to any one of claims 30, 31, in which the nanoparticle in step (b) contains at least 0.1 wt.% of the additive, preferably from 2 to 15 wt.%, relative to the total weight of the nanoparticle containing the additive. 37. The method according to any one of claims 30, 31, in which the metal salt solution is an aqueous solution of calcium chloride. 38. The method according to any one of claims 30, 31, in which water is additionally removed by evaporation. 39. The method according to claim 38, in which the evaporation is carried out at a temperature of from 70 to 100°C. 40. A method of introducing an additive into a subterranean formation, comprising introducing a composition containing a nanoparticle according to any one of claims 1 to 22 into the subterranean formation. 41. The method of claim 40, wherein introducing the composition into the subterranean formation comprises introducing the composition into a drilling fluid. 42. The method of claim 40, wherein introducing the composition into a subterranean formation comprises introducing the composition into a fluid to enhance oil recovery.