Method for introducing silica nanoparticles to reduce H2S in liquid or gas streams

Abstract

1. A method for reducing the amount of HS in a liquid or gas stream, the method comprising: a) operating an industrial process having HS in a liquid or gas stream, or in both the liquid and gas streams associated with the industrial process, the industrial process comprising connecting pipes that allow liquids and gases to move from one location to another within the process; b) injecting a silica nanoparticle mixture into a liquid or gas stream, or in both the liquid and gas streams associated with the industrial process, the silica nanoparticle mixture being in a colloidal or dry state; and c) providing a material in the silica nanoparticle mixture to react with the HS to result in a reduction of HS in the liquid or gas product fluid. In certain embodiments, the silica nanoparticle mixture comprises silica nanoparticles, with or without a surface treatment, and one or more chemicals selected from the group consisting of triazines, alcohols, polyols, ketones, aldehydes, and hemiacetals.

Description

[Technical Field]

[0001] Related patent applications This patent application claims priority to U.S. Provisional Patent Application No. 63 / 428,918, filed November 30, 2022, entitled "Method of Introducing Silica Nanoparticles to Reduce H2S in a Liquid or Gas Stream."

[0002] The present invention is in the field of methods for reducing H2S in liquid or gas streams. [Background technology]

[0003] Hydrogen sulfide (hereinafter "H2S") is present as an unwanted contaminant in many different types of liquid and gas streams, including, but not limited to, oil, natural gas, streams inside and outside refineries, tar sands, SAGD (SAGD stands for "Steam-assisted gravity drainage," an enhanced oil recovery technique used to extract heavy crude oil that is too deep or otherwise difficult to access), geothermal wells, etc.

[0004] Hydrogen sulfide scavenging, which refers to the introduction of a chemical that irreversibly reacts with H2S and subsequently removes it from a liquid or gas stream, is an increasingly popular method for addressing this issue. The primary type of commercially available scavenger is triazine, specifically 1,3,5-tris(2-hydroxyethyl)hexahydro-s-triazine (MEA-triazine). MEA-triazine will theoretically react rapidly with two or more equivalents of H2S to form 5-(2-hydroxyethyl)-hexahydro-1,3,5-dithiazine if H2S is the only acid gas present. MEA-triazine has fast kinetics, works well over a wide temperature range, and is inexpensive to produce.

[0005] However, the use of triazines has several significant drawbacks: aqueous triazine solutions have a high pH, ​​which can lead to carbonate scaling, and dithiazines react to form insoluble polymers that can lead to surface clogging. For these reasons, many companies have expressed interest in developing new H2S scavengers.

[0006] A recently published paper, "Simultaneous Control of Subsurface Scale, Corrosion, and H2S Using a Single Capillary String: A Real-World Chemical Application in the Permian Basin" (hereafter "Simultaneous Control"), SPE-210140-MS, (c)2022, Society of Petroleum Engineers, details the laboratory development and subsequent field testing of a downhole non-triazine H2S scavenger (DNTS) co-injected via a single capillary string (cap string) with an existing scale / corrosion inhibitor (CI / SI) combination product. The target sour gas production wells were configured with a single cap string, and it was deemed important to move the H2S suppression upstream of the tubular. This method was developed to improve overall control of H2S mitigation within high-risk sour gas production wells and throughout the upper reaches of these wells at high-risk sour gas production facilities. The dual injection approach is preferable to "one can" injection (combining all production chemicals in one fluid package) because it allows for more targeted and effective use of chemicals introduced for corrosion, scale, and H2S control in the receiving well and in the upper process.

[0007] The "Simultaneous Control" paper (internal citations removed) states: Hydrogen sulfide (H2S) is a common contaminant in oil field production scenarios worldwide, arising from organic (biological) acidification processes (i.e., the action of sulfate-reducing bacteria) in reservoirs and near wellbore areas and / or from inorganic processes occurring over geological time periods in the formations. H2S is unwanted, undesirable, and nuisance because it is highly toxic and can pose serious integrity and safety risks by worsening corrosion potential. H2S contamination levels can vary widely between oil fields, from a few ppm to over 100,000 ppm. The industry's response to high levels of sour gas contamination is to sweeten the product before export. Two chemical treatment methods commonly used in the oil industry to sweeten sour gas production are the continuous injection of H2S mitigation chemicals into the flowing stream of fluid(s) and / or gas, and the use of in-line gas contactors to pass sour gas through a vessel filled with a scavenger to remove H2S. Typically, the latter method is used when the H2S loading is high and residence time and reaction rate can be problematic in a continuous injection process.

[0008] H2S scavengers fall into two broad classes defined by their chemical mechanism of action.

[0009] The oxidized form is the valence state of the sulfur atom in H2S (-2 valence), which is 0 ) or higher (SO4-2 +6 The oxidized forms include chlorine dioxide, sodium hypochlorite, hydrogen peroxide, per(oxy)acetic acid, potassium permanganate, etc. Although these are effective in sweetening sour gas products, they tend to be nonspecific in action, react with other production components, and present significant challenges in terms of handling and integrity.

[0010] Non-oxidizing scavengers react with H2S, converting it to product sulfide species where new (often irreversible) bonds are formed. Triazines (such as hexahydro-1,3,5-tris(hydroxyethyl)-s-triazine, or MEA-triazine) are the industry's preferred choice for H2S management and have dominated oilfield applications to date. There are several non-triazine options available to the industry that are gaining increasing popularity, including aldehyde-functional materials such as hemiacetals (formals), zinc carboxylates, oxazolidines, and glyoxals.

[0011] MEA-triazines have drawbacks, particularly with regard to the physical condition, chemical properties, and kinetics of the spent scavenger. Historically, non-triazine options have only been considered when the use of triazines posed additional fluidity assurance issues. Downhole chemical injection (DHCI) is the simplest delivery method, performed by injecting treatment chemicals into the annulus of a production well, and has long been available in industry. This technique has evolved somewhat over the years, and "backside injection" is now widely used throughout onshore North America. In this technique, one or more chemical compositions are injected into the "slipstream" of produced fluid (from the flowline), and the resulting mixture is then pumped downhole into the production well. The most commonly used downhole chemical injection technique worldwide is continuous downhole chemical injection (DHCI) via a specialized cap.

[0012] Chemical products introduced through the cap string must be formulated with low-volatility solvents (e.g., glycol) to avoid problems associated with solvent stripping caused by vacuum formation within the tubing due to thermal / hydrostatic imbalances. Modifying the physical properties (viscosity and density) of the DHCI product creates favorable hydrostatic conditions within the tubing, minimizing vacuum formation and creating uniform chemical delivery. In addition to cap string DHCI, chemicals can also be introduced downhole via a gas lift well system (GLCI). Formulated chemicals are injected into the lift gas stream at the surface and introduced into the wellbore annulus. While a pseudo-aerosol effect may initially be observed, sputtered chemical droplets quickly collect on the tubing surface and flow down the wellbore to the gas lift valve (GLV) sump, located several distances below the subsurface safety valve (SSSV). As the amount of chemical in the sump increases, the fluid level reaches the GLV inlet, allowing the chemical to flow through the valve and into the production line. Downhole injection via GLCI is problematic due to the diluted environment that the introduced chemicals are exposed to during their descent into the sump. The use of highly volatile solvents must be strictly avoided in this type of application to minimize problems associated with premature solvent loss, which leads to product viscosification and gunking.

[0013] Downhole application of H2S scavengers adds a new dimension to the challenge, as their application to multiphase systems is significantly more complex than that to single-phase systems, and multiphase partitioning effects must be addressed to achieve optimal trapping. In addition to being thermally robust, DHCI formulations must also be compatible with the brines most likely to be encountered during application, avoiding solid salt formation between the chemical and metal ions in the brine and / or phase separation of mineral scale in the brine due to pH changes. Therefore, DHCI chemical formulations tend to be pH neutral or slightly acidic. DHCI formulations with high pH (>7) are avoided, especially if the produced water they may come into contact with downhole has a significant potential for calcium carbonate scaling; an increase in pH can significantly increase the likelihood of CaCO3 scale formation. MEA-triazines are typically highly alkaline, which adversely affects brine pH and mineral scaling. For this reason, triazine-based scavengers are typically avoided for subsurface applications for H2S control. The literature provides few case studies of downhole H2S scavenger applications.

[0014] Additional references describe alternative chemical treatments for H2S scavengers in liquid or gas wells.

[0015] Dorf Ketal has reported a new technology, MAXSCAV™-Dorf Ketal, for improving the performance of non-regenerative H2S capture chemical formulations. This new technology can be used to reduce costs and improve efficiencies for most chemical formulations used in applications ranging from upstream production and transportation to crude oil refining and transportation of end products such as asphalt / bitumen.

[0016] MAXSCAV™ Second Generation catalyst technology is specifically designed for the treatment of H2S in natural gas in contact columns, bubble columns and Dorf Ketal's proprietary UltraFab™ system.

[0017] MEA-triazine is the most commonly used chemical formulation for applications requiring a non-regenerative H2S scavenger. While other chemical formulations (MMA-triazine, glyoxal, zinc-based, iron-based, etc.) are available, MEA-triazine has the highest market share due to the lowest solution usage cost. Triazine has a low usage cost despite the fact that the molar efficiency of the chemical in capturing H2S is significantly below the theoretical maximum efficiency.

[0018] Quaternary ammonium compounds promote the reaction between MEA-triazine and HS, improving molar efficiency, but significant inefficiencies remain, including excessive cost, increased pH and scale formation, and increased problems in downstream purification, which can include reduced desalter performance and increased overhead corrosion risk.

[0019] MAXSCAV™ is a new, patent-pending technology that dramatically increases the molar efficiency of MEA-triazine and other chemical formulations, including MMA-triazine, glyoxal, and zinc-based scavengers. The reduction in MEA-triazine required for HS capture can potentially reduce expenditure items by up to 25%-50%. The reduction in chemical overload can also reduce the cost of scale formation and downstream purification issues. Again, see MAXSCAV™ - Dorf Ketal.

[0020] Canadian Patent No. 2991180C, "Hydrogen sulfide scavenging additive compositions, and medium comprising the same," issued April 23, 2019, and assigned to Dorf Ketal, describes and claims an invention related to a hydrogen sulfide scavenging additive composition, the composition comprising: a. Additive 1 comprising at least one compound selected from the group consisting of zinc compounds, zinc soaps, and zinc salts of organic acids; and b. at least one activator comprising one or more hydroxyl alkylated amines. In one embodiment, the composition further comprises Additive 2 comprising polyphosphoric acid (PPA). In one embodiment, the present invention also relates to a method of using the hydrogen sulfide scavenging additive composition of the present invention to scavenge hydrogen sulfide in a medium. In one embodiment, the present invention also relates to a method of scavenging hydrogen sulfide in a medium by using the hydrogen sulfide scavenging additive composition of the present invention. In one embodiment, the present invention also relates to a medium comprising the hydrogen sulfide (HS) scavenging additive composition of the present invention.

[0021] Descriptions of other techniques for removing H2S from process streams can be found in the following references: "Formation, Chemical Characterization, and Oxidative Dissolution of Amorphous Polymeric Dithiazine (apDTZ) during the Use of the H2S Scavenger Monoethanoloamine-Triazine," by Wylde, Taylor, Sorbie, and Samaniego, Energy Fluids, 2020, 34, 9923-9931; US2013 / 0004393A1, "Synergistic Method for Enhanced H2S / Mercaptan Scavenging," assigned to Baker Hughes Incorporated, published January 3, 2013; and US2018 / 0291284A1, "Microparticles for Capturing Mercaptans," assigned to Ecolab USA Inc., first published October 11, 2018, includes a colloidal nanoparticle substrate made of silica or alumina, and the colloidal substrate contains iron(II) (Fe 2+ ) and Zn 2+ The present invention describes and claims sulfide-trapping nanoparticles coated with a sulfide-reactive metal selected from the group consisting of:

[0022] What is needed are additional materials and methods for reducing the amount of H2S in liquid or gas streams to overcome these problems. Summary of the Invention

[0023] A first aspect of the claimed invention is a method for reducing the amount of H2S in a liquid or gas stream, comprising the steps of: a) operating an industrial process having H2S in a liquid or gas stream, or in both the liquid and gas streams associated with the industrial process, the industrial process comprising connecting pipes that allow the liquids and gases to move from one location to another within the process; b) injecting the silica nanoparticle mixture into a liquid or gas stream, or an industrial process having H2S in both the liquid and gas streams associated with the industrial process, the silica nanoparticle mixture being in a colloidal or dry state; and c) providing a material in the silica nanoparticle mixture to react with H2S to result in a reduction of H2S in the liquid or gas product fluid.

[0024] A second aspect of the claimed invention is the first aspect of the claimed invention, wherein the silica nanoparticle mixture comprises silica nanoparticles and one or more chemicals selected from the group consisting of triazines, alcohols, polyols, ketones, aldehydes, and hemiacetals.

[0025] A third aspect of the claimed invention is the first aspect of the claimed invention, wherein the silica nanoparticle mixture includes both non-surface-treated nanoparticles and surface-treated nanoparticles.

[0026] A fourth aspect of the claimed invention is the first aspect of the claimed invention, wherein the silica nanoparticles react with H2S under turbulent flow conditions, and the flow conditions have a Reynolds number of 4000 or greater.

[0027] A fifth aspect of the claimed invention is the first aspect of the claimed invention, wherein the liquid or gas stream is selected from the group consisting of oil, natural gas, refinery, tar sands, SAGD, geothermal well, and combinations thereof.

[0028] A sixth aspect of the claimed invention is the fifth aspect of the claimed invention, wherein the liquid or gas stream is selected from the group consisting of a petroleum stream and a natural gas stream.

[0029] A seventh aspect of the claimed invention is the third aspect of the claimed invention, wherein the nanoparticle mixture has at least 95% non-surface-treated nanoparticles and at least 5% surface-treated nanoparticles.

[0030] An eighth aspect of the presently claimed invention is the third aspect of the presently claimed invention, wherein the nanoparticle mixture has at least 85% non-surface-treated nanoparticles and at least 15% surface-treated nanoparticles.

[0031] A ninth aspect of the claimed invention is the third aspect of the claimed invention, wherein the nanoparticle mixture has at least 75% non-surface-treated nanoparticles and at least 25% surface-treated nanoparticles.

[0032] A tenth aspect of the claimed invention is the third aspect of the claimed invention, wherein the nanoparticle mixture has at least 60% non-surface-treated nanoparticles and at least 40% surface-treated nanoparticles.

[0033] An eleventh aspect of the present claimed invention is the third aspect of the present claimed invention, wherein the nanoparticle mixture has at least 35% non-surface-treated nanoparticles and at least 65% surface-treated nanoparticles. DETAILED DESCRIPTION OF THE INVENTION

[0034] A first aspect of the claimed invention is a method for reducing the amount of H2S in a liquid or gas stream, comprising the steps of: a) operating an industrial process having H2S in a liquid or gas stream, or in both the liquid and gas streams associated with the industrial process, the industrial process comprising connecting pipes that allow the liquids and gases to move from one location to another within the process; b) injecting the silica nanoparticle mixture into a liquid or gas stream, or an industrial process having H2S in both the liquid and gas streams associated with the industrial process, the silica nanoparticle mixture being in a colloidal or dry state; and c) providing a material in the silica nanoparticle mixture to react with H2S to result in a reduction of H2S in the liquid or gas product fluid.

[0035] In the present invention, the industrial process stream, including a liquid stream or a gas stream, is selected from the group consisting of petroleum, natural gas, streams inside and outside refineries, tar sands, SAGD, geothermal wells, and combinations thereof. These industrial process streams are well known to those skilled in the art. Each of these industrial process streams has piping that connects different parts of the process and is used to move material(s) through the process. Each piping configuration may be similar or different depending on the material being moved. Consistent with all of these processes is that the liquid or gas in the process stream contains H2S, and the H2S needs to be removed before the material in the process stream comes into contact with the transportation piping that moves the material.

[0036] As used herein, the term "nanoparticle" refers to a particle having a diameter of about 1 to about 100 nanometers. In some embodiments, the term "nanoparticle" refers to a cluster of atoms or molecules with a radius of less than 100 nanometers. In some embodiments, the term nanoparticle applies to inorganic materials, such as silica. As used herein, the term "silica" may refer to a silica particle or a silica dispersion. As used herein, the term "silica" may refer to silica particles derived from colloidal silica or fumed / dried silica. As used herein, the term "nanoparticle" can refer to both multiple individual nanoparticles as well as a population of a particular type of nanoparticle. Nanoparticles can also refer to nanometer-sized particles, and nanopowders are aggregates of nanoparticles. In some embodiments, the term "nanofluid" refers to a base fluid, such as water or oil, containing nanoparticles, including fluids in which some or all of the nanoparticles are suspended.

[0037] All silica nanoparticles are commercially available from Nissan Chemical America Corporation under the trademark "SNOWTEX." Evonik's colloidal silica nanoparticles are commercially available under the trademark "IDISIL." Evonik's commercially available fumed and precipitated silica nanoparticle products are branded "AEROSIL" and "SIPERNAT," respectively. Cabot markets fumed silica nanoparticles under the brand name "CAB-O-SIL." Akzo Nobel markets nanoparticle silica products under the Nouryon trademark (label) and uses the product name "LEVASIL," which is a colloidal silica product. Akzo operates a pulp and paper business through its subsidiary, Eka, whose new colloidal silica nanoparticle products have the new brand name "COMPOZIL." Silica nanoparticles are also available from Ecolab.

[0038] It is known that silica nanoparticles can aggregate when exposed to fluids containing salt brine. When fluids in oil or gas wells contain salt brine, a silica nanoparticle mixture may contain both non-surface-treated silica nanoparticles and surface-treated nanoparticles, with the surface treatment selected to make the surface-treated silica nanoparticles brine-resistant. See U.S. Pat. No. 10,557,078, issued February 11, 2020, entitled "Brine Resistant Silica Sol," and U.S. Pat. No. 11,130,906, issued September 28, 2021, entitled "Brine Resisting Silica Sol," both of which are incorporated herein by reference in their entireties for their description and claims of suitable surface-treated silica nanoparticles.

[0039] In one embodiment, the nanoparticle mixture has at least 95% non-surface-treated silica nanoparticles and at least 5% surface-treated nanoparticles.

[0040] In one embodiment, the nanoparticle mixture has at least 85% non-surface-treated silica nanoparticles and at least 15% surface-treated nanoparticles.

[0041] In one embodiment, the nanoparticle mixture has at least 75% non-surface-treated silica nanoparticles and at least 25% surface-treated nanoparticles.

[0042] In one embodiment, the nanoparticle mixture has at least 60% non-surface-treated silica nanoparticles and at least 40% surface-treated nanoparticles.

[0043] In one embodiment, the nanoparticle mixture has at least 35% non-surface-treated silica nanoparticles and at least 65% surface-treated nanoparticles.

[0044] The following materials may also be present in the silica nanoparticle mixture:

[0045] Corrosion inhibitors include, but are not limited to, the following categories: Anodic inhibitors work by forming a protective oxide film on the surface of the metal. This causes a large anodic shift, moving the metal surface into a passive region and lowering the corrosion potential of the material. Some examples are chromates, nitrates, molybdates, and tungstates.

[0046] Cathodic inhibitors inhibit the cathodic reaction and limit the diffusion of reduced species to the metal surface. Cathodic poisons and oxygen scavengers are examples of this type of inhibitor.

[0047] Mixed inhibitors are film-forming compounds that reduce both the cathodic and anodic reactions. The most commonly used mixed inhibitors are silicates and phosphates, which are used in domestic water softeners to prevent rust formation.

[0048] Volatile corrosion inhibitors (VCIs) are compounds that are transported from a source to a corrosion site by a process of volatilization in a confined environment. For example, in a boiler, volatile compounds such as morpholine or hydrazine are transported with the steam to prevent corrosion of the condenser tubes.

[0049] In one embodiment, the corrosion inhibitor includes an amine-based chemical with H2S scrubbing activity. These may include an imidazole or a quaternary amine-type moiety. In one embodiment, the corrosion inhibitor is an imidazole.

[0050] Oilfield scaling is the precipitation and accumulation of insoluble crystals from incompatible aqueous phase mixtures in petroleum processing systems. These crystals precipitate and grow over time, which can block or impede flow through pipelines, valves, pumps, etc., significantly reducing production rates. The most common types of oilfield scale are calcium carbonate, barium sulfate, and calcium sulfate. In one embodiment, scale inhibitor-type chemical formulations include, but are not limited to, phosphonates. Phosphonates are commercially available.

[0051] Additional corrosion and scale inhibitors are described in the following references: EP3277771B1, "Composition and Method for Inhibition of Sulfide Scales," assigned to Clariant International, Ltd., first published May 8, 2019; EP3475385B1, "Amorphous Diathiazine Dissolution Formulation and Method for Using the Same," published February 26, 2020, assigned to Clariant International Ltd.; US2022 / 0119699A9, "Synergized Acetals Compositions and Method for Scavenging Sulfides and Mercaptans," assigned to Clariant International, Ltd., published April 21, 2022; first published April 9, 2020, as US2020 / 0109329A1.

[0052] The silica nanoparticle mixture can be added to the tubing string either dry or mixed with a carrier fluid. When a carrier fluid is used to add the silica nanoparticles, the carrier fluid can be liquid or gaseous.

[0053] When the carrier fluid is gaseous, the gas can be any gas that does not cause a problematic reaction. In one embodiment, the gas is selected from the group consisting of natural gas, liquefied natural gas (LNG), methane (CH), nitrogen (N), helium (He), and mixtures thereof. In one embodiment, the gas is selected from the group consisting of carbon dioxide (CO) and mixtures with other gases.

[0054] In one embodiment, a mixture containing silica nanoparticles is added to achieve a Reynolds number ("Re") of 4000 or greater. The Reynolds number (Re) helps predict flow patterns in various fluid flow situations by measuring the ratio of inertial to viscous forces. At low Reynolds numbers, flow tends to be predominantly laminar (sheet-like), while at high Reynolds numbers, flow tends to be turbulent. Turbulence occurs due to differences in fluid velocity and direction, sometimes resulting in cross currents or even moving in the opposite direction to the overall flow (vortices). These vortices begin to churn the flow, wasting energy in the process and, in the case of liquids, increasing the likelihood of cavitation. The Reynolds number is an important dimensionless quantity in fluid mechanics.

[0055] When the Reynolds number is above 4000, the fluid is moving in what is called a "turbulent flow." Turbulence helps to enhance contact between the H2S and the nanoparticle mixture, and enhanced contact promotes the removal of H2S. [Example]

[0056] Laboratory Test Methods First test method. Setup: 10% (100,000 ppm) H2S in N2 is bubbled into a vessel containing 300 mL of the test formulation at a flow rate of 475 mL / min.

[0057] 1. An H2S sensor measures the concentration of H2S in the eluted gas stream. 2. Stop the measurement when the concentration of H2S in the gas stream reaches a concentration of 40 ppm. Record the time it takes to reach a H2S concentration of 40 ppm and record the time for each test formulation.

[0058] Second test method There are several standard laboratory tests, such as the gas breakthrough test and the Parr reactor. Additionally, there has been growing interest in measuring the kinetics of the scavenging reaction using sulfide-sensing electrodes. All of these tests can evaluate the performance and capacity of H2S scavengers by measuring the rate of H2S depletion. Each of these tests was developed as a laboratory simulation of a different field application. The gas breakthrough test is a simulation of a contactor. The Parr reactor, which can evaluate the performance and capacity of scavengers under high temperature and pressure, provides information on multiphase and downhole capture. However, in the case of direct injection, there is still a gap between laboratory predictions of scavenger performance and actual field results. It is known that the injection method plays a major role in scavenger distribution and therefore performance, but none of the laboratory-based methods incorporate this feature.

[0059] The industry has recognized the need to better predict the in-situ performance of scavengers, especially for direct chemical injection, which has led to the development of simulation software that can also consider flow conditions within the pipe. Several large-scale devices have been reported that have been developed to simulate various types of liquid and gas installations, covering applications such as subsea pipelines, multiphase and gas pipeline loop injection of scavengers, and are capable of evaluating scavengers' performance.

[0060] However, each experiment requires significant quantities of liquid or gas and scavenger, neither of which is trivial, and therefore can only be considered in the later stages of development. What is missing in this field are laboratory-scale tests that incorporate the physics of chemical sparge, gas flow, and mass transfer processes associated with direct injection treatment of sour gas fields. This paper describes the development of such a device and how it can be used to overcome these issues. "Laboratory Simulation of Gas Sweetening" was written by Murison, Schneider, Muller, Punga, Low, Peerlings, Feustel, Aylor, Wylde, and Kelly, and was published as a preprint citation of "View of A new method to simulate acidic gas sweetening on a laboratory scale" (engrxiv.org) and subsequently as a book on December 13, 2016 (hereafter "Murison").

[0061] Example 1 (Comparative Example) A sample of gas containing H2S is obtained and the initial concentration of H2S is measured. The gas is contacted with MEA-triazine using a first test method. The concentration of H2S is measured after contact with MEA-triazine. A measurable reduction in the amount of H2S is detected.

[0062] Example 2 Example 1 is repeated, except that a mixture of colloidal silica containing at least 85% untreated silica nanoparticles and at least 15% surface-treated nanoparticles is mixed with MEA-triazine, and the mixture is then tested by the first test method. A measurable reduction in the amount of H2S is detected.

[0063] Example 3 The composition of Example 2 is tested using the "Murison" test method (second test method) and is found to reduce detectable amounts of H2S.

Claims

1. H in the liquid or gas stream ２ 1. A method for reducing the amount of S, comprising the steps of: a) H in liquid or gas streams, or both liquid and gas streams, associated with industrial processes ２ operating the industrial process having S, the industrial process comprising connecting pipes that allow liquids and gases to move from one location to another within the process; b) H in liquid or gas streams, or both liquid and gas streams, associated with industrial processes ２ injecting a silica nanoparticle mixture into the industrial process having S, the silica nanoparticle mixture being in a colloidal or dry state; and c) Adding the materials in the silica nanoparticle mixture to the H ２ H in the liquid product fluid or the gas product fluid by reacting with S ２ providing a solution to effect said reduction in S.

2. 10. The method of claim 1, wherein the silica nanoparticle mixture comprises silica nanoparticles and one or more chemicals selected from the group consisting of triazines, alcohols, polyols, ketones, aldehydes, and hemiacetals.

3. The method of claim 1 , wherein the silica nanoparticle mixture comprises both non-surface-treated and surface-treated silica nanoparticles.

4. The silica nanoparticles are heated under turbulent conditions with H ２ The method of claim 1, wherein the reaction is with S and the Reynolds number of the flow condition is 4000 or more.

5. 10. The method of claim 1, wherein the liquid stream or the gas stream is selected from the group consisting of oil, natural gas, internal and external refinery streams, tar sands, SAGD, geothermal wells, and combinations thereof.

6. 6. The method of claim 5, wherein the liquid stream or the gas stream is selected from the group consisting of a petroleum stream and a natural gas stream.

7. 4. The method of claim 3, wherein the nanoparticle mixture has at least 95% non-surface-treated silica nanoparticles and at least 5% surface-treated nanoparticles.

8. 4. The method of claim 3, wherein the nanoparticle mixture has at least 85% non-surface-treated silica nanoparticles and at least 15% surface-treated nanoparticles.

9. 4. The method of claim 3, wherein the nanoparticle mixture has at least 75% non-surface-treated silica nanoparticles and at least 25% surface-treated nanoparticles.

10. 4. The method of claim 3, wherein the nanoparticle mixture has at least 60% non-surface-treated silica nanoparticles and at least 40% surface-treated nanoparticles.

11. 4. The method of claim 3, wherein the nanoparticle mixture has at least 35% non-surface-treated silica nanoparticles and at least 65% surface-treated nanoparticles.

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