Chemical compositions and methods for treating sulfur-containing compositions and other contaminants in fluids using the same

Abstract

A treatment method for remediation of a contaminant in a mixture of a contaminated fluid comprising at least one liquid fluid and at least one gaseous fluid, the treatment method comprising the steps of: preparing a treatment composition containing at least 80 vol% of an aqueous solution containing at least one hydroxide compound at a total concentration of 35-55 wt% of the treatment composition and at least one organic acid selected from the group consisting of fulvic acid and humic acid at a total concentration of 0.1-5 wt% of the treatment composition; adding a dose of the treatment composition to the mixture of the contaminated fluid comprising a liquid portion and a gaseous portion; and allowing the treatment composition to react with the mixture of the contaminated fluid for at least 10 minutes. The treatment composition has a pH of at least 12.0.

Description

[0001] Cross-references to related applications

[0002] This non-provisional application claims priority to U.S. Provisional Application Serial No. 63 / 185,808, filed May 7, 2021. The full subject matter of those priority applications is incorporated herein by reference. Background of the Invention 1. Technical Field

[0003] This disclosure relates to novel treatment compositions and methods for treating various contaminated fluids, including liquids, gases, and mixtures thereof, containing sulfur compounds (including H2S, thiols, thiophenes) and BTEX (benzene, toluene, ethylbenzene, xylene), as well as other contaminants (including CO2, SO2, metals, salts, etc.). Examples include hydrocarbon-based liquids and gases such as crude oil and natural gas; emissions from fossil fuel combustion; and so-called produced water extracted along with crude oil and natural gas. More particularly, this disclosure relates to such treatment compositions, novel pretreatment methods for contaminated gases using alkaline water washing solutions, and treatment methods in which the contaminated fluid and fluid mixtures are chemically reacted with the treatment composition, thereby effectively and cost-effectively treating virtually all contaminants in the fluid to very low levels that are considered safe. 2. Background Technology

[0004] Sulfur compounds (including hydrogen sulfide (H2S), thiols, and thiophene) and BTEX have long been considered undesirable contaminants in contaminated fluids, particularly hydrocarbon fluids such as crude oil and natural gas. H2S is especially undesirable due to its high toxicity and corrosiveness, and hydrocarbon fluids are generally expected to contain less than 5 ppm H2S. The management of H2S in hydrocarbon fluids has long been, and remains, a very important focus of the global oil industry, and typically, governments worldwide stipulate that natural gas intended for sale or use should contain no more than 4-5 ppm of H2S.

[0005] Treating contaminated fluids such as crude oil can be challenging, but numerous treatment compositions and methods for such purposes exist, including some previously proposed by the inventors, such as those disclosed in International Patent Applications PCT / US2018 / 050913 and PCT / US2018 / 064015, the entire contents of which are incorporated herein by reference. In such methods previously proposed by the inventors, a treatment composition may be added directly to or in combination with the contaminated liquid, such that the chemicals contained in the treatment composition (primarily hydroxide compounds) react with the contaminant to treat it into a less problematic, non-toxic compound that may remain in or precipitate out of the treated liquid.

[0006] As disclosed in PCT / US2018 / 050913, one of the inventors' prior proposals for treating contaminated liquids involves an aqueous treatment composition primarily containing high concentrations of one or more hydroxides such as sodium hydroxide (NaOH) and potassium hydroxide (KOH), for example, the total hydroxide content being 35-55% by weight, and preferably at least 45% by weight, of the treatment solution. This aqueous treatment composition reacts efficiently with H2S to convert it into a non-toxic substance. According to recent proposals, such treatment solutions are highly alkaline, with a pH of 13-14. In such treatment methods, a relatively small dose of treatment solution is added to the hydrocarbon-based liquid or aqueous solution being treated, for example, a standard dose rate of 0.25-6.0 ml treatment solution / L of the treated liquid, preferably 1.0-5.0 ml treatment solution / L of the treated liquid, which corresponds to approximately 125-3000 ppm of one or more hydroxides in the treated liquid. A particularly appropriate dosage rate depends on a number of factors, and one or more hydroxides in the solution efficiently treat H2S and other sulfur-containing compounds to low to acceptable levels over a relatively short period of time (such as 15 minutes to several hours) without adversely affecting hydrocarbon-based petroleum liquids or contaminated aqueous solutions in any other significant way.

[0007] Importantly, unlike previously known H2S removal compositions involving triazine or formaldehyde and methods for treating H2S and other contaminants in liquids (including crude oil) using said removal compositions, this previously proposed treatment method involving the treatment composition is irreversible for the H2S and other contaminants being treated. Furthermore, it is very important that the standard dosage of the treatment compositions discussed above is suitable for treating contaminated liquids (including crude oil) containing a wide range of contaminants, which is also very different from previously known H2S removal compositions involving triazine or formaldehyde, which required more specific dosage rates based on the amount of H2S and other contaminants being removed. Therefore, except for anomalous liquids containing very high amounts of contaminants, it is typically not necessary to adjust the dosage based on the specific amount of contaminants contained in the liquid to be treated, and the treatment process will not be adversely affected if the amount of contaminants in the treated liquid sometimes peaks during treatment.

[0008] As disclosed in PCT / US2018 / 064015, another prior proposal by the inventors involved the use of a water-based treatment composition similar to that disclosed in PCT / US2018 / 050913, but additionally containing appropriate amounts of one or more organic acids such as fulvic acid and humic acid. This treatment composition is added to the treated liquid at a dosage rate typically resulting in a concentration of one or more organic acids in the normal range of 0.01-10 ppm, preferably 0.1-3 ppm, whether the liquid is a hydrocarbon-based liquid or a contaminated aqueous solution. The one or more organic acids, such as fulvic acid and humic acid, effectively bind to the contaminants being treated and, prior to further processing in a refinery or the like, maintain the contaminated liquid in the treated liquid for a period of time (e.g., hours, days, or weeks) without forming any precipitates. Such a treatment method / composition may contain a small amount (e.g., less than 2 wt%) of a scale inhibitor, such as monoethanolamine (MEA).

[0009] Fulvic acid is actually a group of organic acids, but it can typically be identified as 1H,3H-pyrano[4,3-b][1]benzopyran-9-carboxylic acid, 4,10-dihydro-3,7,8-trihydroxy-3-methyl-10-oxo-;3,7,8-trihydroxy-3-methyl-10-oxo-1,4-dihydropyrano[4,3-b]chromene-9-carboxylic acid, with an average chemical formula of C. 135 H 182 O 95N5S2 typically has a molecular weight ranging from 100 to 10,000 g / mol. Similarly, humic acids are mixtures of several molecules, some of which are based on motifs (linked together) of aromatic nuclei with phenolic and carboxylic acid substituents, and typical structures are illustrated below. The molecular weight (size) of humic acids is typically much larger than that of fulvic acid and can vary from 50,000 to over 500,000 g / mol.

[0010]

[0011] The treatment composition and method according to the prior proposal involve a standard dosage of the treatment composition that generally corresponds to the standard dosage of the first prior proposal discussed above. This previously proposed treatment composition and method is also advantageously irreversible, and the standard dosage of the treatment composition discussed above is suitable for treating contaminated liquids containing a wide range of contaminants, including crude oil.

[0012] Although the inventors’ previously proposed solutions for treating contaminated liquids are far more effective, cost-effective, and practical than previously known treatment compositions and methods, improvements are still desired.

[0013] For a variety of reasons, treating contaminated gases is generally more challenging than treating contaminated liquids. While many known treatment compositions and methods exist for treating contaminated gases, in many cases, conventional compositions and methods are insufficient to effectively treat contaminated gases in a practical and cost-effective manner. For example, there are many known natural gas deposits worldwide that are heavily contaminated with H2S and other significant pollutants, including other types of sulfur compounds, carbon dioxide (CO2), ammonia (NH3), water (H2O), salts such as sodium chloride (NaCl), nitrogen (N2), crude oil, and various solids, including organic matter, which have proven to be among the most challenging. Using conventionally known treatment compositions and methods, it is impossible to adequately treat such highly contaminated natural gas in a practical and cost-effective manner to make it suitable for sale or use. Consequently, many known natural gas deposits and existing gas wells remain unexploited or closed.

[0014] Compared to the treatment of contaminated gases, including natural gas, one of the inventors previously proposed treatment compositions and methods for such purposes in U.S. Patent No. 10,913,911B2 ('911 Patent), the contents of which are incorporated herein by reference. The '911 Patent discusses several reasons why the treatment of contaminated gases is far more complex than the treatment of contaminated liquids such as crude oil and contaminated aqueous solutions, even when the primary contaminant to be treated in the gas is H2S (just as H2S is the primary contaminant to be treated in crude oil). The reasons primarily include some significant complexities associated with the continuous treatment of large volumes of contaminated natural gas, thus treatment compositions and methods used for treating contaminated liquids cannot be directly applied to the treatment of contaminated gases. For example, in addition to H2S, contaminated gases (such as natural gas) often contain significant amounts of other contaminants, such as carbon dioxide (CO2), nitrogen (N2), water (H2O), and sodium chloride (NaCl). This can lead to very low efficiency in gas treatment processes. Some contaminants (such as salts) may tend to precipitate from the contaminated natural gas during treatment, which can easily clog parts of the treatment system and otherwise adversely affect the process. Furthermore, the properties of natural gas differ greatly from those of crude oil and other liquids, including its much lower volumetric value. For instance, natural gas is typically discharged continuously from wells at high rates, pressures, and volumes of millions of cubic feet per well per day, and its handling and processing must be very different from those of liquids, adding further complexity to the treatment of these contaminated gases. For example, treatment methods for contaminated gases (such as natural gas) may only allow the treatment composition to come into contact with the contaminated gas for a few seconds or less, which is different from the treatment of contaminated liquids, which may simply involve adding an appropriate amount of treatment composition to the contaminated liquid and then allowing the liquid to stand for an appropriate time until the H2S and one or more other contaminants in the liquid are treated to low to safe and acceptable levels.

[0015] As discussed in the '911 patent, water-based treatment compositions can be used to treat H2S, CO2, and other problematic contaminants in gases to low to safe levels, but may require prior treatment of the natural gas to remove other contaminants, including salt and water, so that the treatment of H2S, CO2, and other problematic contaminants can be carried out continuously and efficiently. According to previous proposals by the inventors, treatment compositions such as those disclosed in the '911 patent are water-based and similar to those disclosed in PCT / US2018 / 064015. They contain a high concentration of hydroxides for treating H2S, CO2, etc., and smaller amounts of one or more organic acids (such as fulvic acid and humic acid) to prevent the formation and release of precipitates from the treated gas, and may further contain chelating agents, such as ethylenediaminetetraacetic acid (EDTA), which particularly increases the efficiency of the hydroxide compounds in treating H2S and other contaminants and helps to make the treatment of H2S irreversible; surfactants, such as sodium dodecyl sulfate; and buffers, such as potassium carbonate, etc. A certain amount of such treatment composition can be arranged in a reaction chamber or tower, and natural gas can be bubbled through the treatment composition, thereby treating H2S, CO2, and some other contaminants in the natural gas, resulting in little or no precipitation formation and release from the treated gas. However, prior to this treatment step, the treatment method may require additional preliminary treatment steps and equipment to remove water, salts, etc., from the natural gas before it reacts with the treatment composition. When the gas reacts with the treatment composition, if salts are present, they are likely to precipitate from the treated gas, and salt precipitates tend to cause blockages and other problems, making this part of the treatment process inefficient if they are present. Water in the natural gas will typically contain dissolved salts and will tend to undesirably dilute the treatment composition.

[0016] Compared to previously known treatment compositions and methods, the inventors' previously proposed treatment compositions and methods for treating contaminants in gases have proven to be far more practical and cost-effective in adequately treating H2S and other contaminants in gases such as natural gas. Similar to the inventors' proposed schemes for treating H2S and other contaminants in liquids, these treatment compositions and methods for treating contaminants in gases irreversibly treat H2S and other contaminants in gases, and standard doses of the treatment compositions advantageously and effectively treat a wide range of contaminant concentrations. However, the previously proposed gas treatment schemes and methods still require improvement. Treating mixtures of contaminated gases and contaminated fluids containing these gases to appropriate and safe levels in a practical and cost-effective manner remains a significant challenge in the field. Summary of the Invention

[0017] One of the inventors of this invention further investigated the treatment of contaminated fluids (including liquids, gases, and mixtures thereof) and discovered new treatment solutions / compositions and methods that can be used alone or in combination to treat contaminated fluids and to treat and / or remove substantially all types of contaminants very effectively, efficiently, and cost-effectively, reducing them to safe and acceptable levels. These contaminants include H2S, SO2, other sulfur-based contaminants (including thiols and thiophenes), CO2, NH3, salts, BTEX chemicals, etc., contained in contaminated gases, contaminated liquids, and mixtures of various liquids and gases.

[0018] The inventors' first discovery is that when previously proposed treatment compositions are used to treat mixtures and streams of contaminated fluids (including fluid mixtures highly contaminated with H2S and other contaminants), such fluid mixtures can be efficiently and effectively treated to control H2S and other contaminants by adding the treatment composition (such as one of the treatment compositions disclosed in PCT / US2018 / 064015 and variations thereof) to the contaminated fluid mixture at an appropriate dosage rate. Such treatment can be performed on continuously flowing streams of fluid mixtures, either relatively or with fixed quantities or batches of fluid mixtures. As an example, crude oil, natural gas, and contaminated water typically extracted simultaneously from a given well can be delivered directly to a refinery as a mixed stream, or the fluids can be separated from each other shortly after extraction from underground via a three-way separator, for example, the separator receiving the mixed fluid stream from the well and separating it into three distinct output streams. If the fluid mixture is transported directly to a refinery, one or more doses of one or more treatment compositions can be simply added to the mixture such that these compositions will treat the contaminants as the mixture flows toward the refinery, which may be miles away and could take more than an hour to reach. If the fluids are separated, crude oil and natural gas can be transported, stored, and refined, while contaminated water can be disposed of by treatment and / or injection underground. Crude oil and natural gas are typically transported in pipelines, which limit the H2S content in these fluids to relatively low levels, such as 5 ppm or less. However, some pipelines will receive mixtures of contaminated crude oil and contaminated natural gas for further processing in refineries, etc., even if the H2S content in the natural gas may be much higher than 5 ppm. Therefore, separated crude oil and natural gas streams from separators can be recombined in such pipelines for transport together.

[0019] The inventors' first discovery was that when a fluid mixture flows continuously in a pipeline, typically for several miles and over a period of one hour or longer, by adding an appropriate amount of a treatment composition (such as one of the compositions disclosed in PCT / US2018 / 064015 and the '911 patent) to the mixed fluid flow in the pipeline, the treatment composition reacts with and treats H2S and other contaminants in both the liquid and gaseous components of such a fluid mixture, resulting in a significant reduction in the levels of H2S and other contaminants, and virtually no sediment is discharged from the treated fluid in the pipeline. The added treatment composition will remain primarily in one or more liquid portions of the mixed fluid and accordingly have a greater effect in treating contaminants in said one or more liquid portions, but as the mixed fluid flows along the pipeline, there is significant mixing and comingling between the liquid and gaseous portions, and contaminants in said one or more gaseous portions are also treated to some extent. The inventors have determined that even when a contaminated fluid mixture contains relatively high levels of H2S, CO2, etc. (e.g., 60,000 ppm or up to hundreds of thousands of ppm), by adding an appropriate dose of a treatment composition to the mixture, the levels of H2S, CO2, and other contaminants in the liquid portion of the mixture (e.g., crude oil) can be reduced to a safe level below 5 ppm, and the levels of H2S, CO2, and other contaminants in the gaseous portion of the mixture (e.g., natural gas) will be significantly reduced, for example, to below 30,000 ppm. Discharging any amount of one or more precipitates from the treated fluid mixture in such pipelines is highly undesirable, as this could partially or completely clog the pipeline and require shutdown for corrective action. However, the treatment composition in question contains one or more organic acids, such as fulvic acid and humic acid, which advantageously and very effectively prevent the formation and release of precipitates from the treated fluid. Similar to the inventors' previous works on treating H2S, CO2, and other contaminants in liquids and gases, the pollution control achieved using these treatment compositions and methods is irreversible for H2S and other contaminants, and treatment compositions at standard dosages, such as those mentioned above, advantageously and effectively treat a wide range of contaminant concentrations, regardless of any peak levels of the contaminants. This treatment method is applicable to any mixture of contaminated fluids, which may contain more than two types; for example, the method can be applied directly to crude oil, natural gas, and so-called produced water discharged from wells and before they are separated by separators.

[0020] To implement such a treatment method according to the invention, the treatment composition can be added to the fluid mixture continuously or discontinuously, and the inventors have determined that a suitable manner of adding the treatment composition to the fluid mixture may optionally involve using a mixing chamber that continuously receives the fluid to be treated therein and also receives a flow of the treatment composition, for example, injecting the fluid and treatment composition at the lower part of the mixing chamber, and discharging some of the mixed fluid, containing a certain dose of the treatment composition, from the upper part of the mixing chamber into a pipeline that transports the mixed fluid to other locations, during which time the treatment composition treats contaminants in the fluid mixture. Another method simply involves pumping or injecting the treatment composition into a pipeline containing the fluid mixture at one or more suitable dosage rates. However, other methods of adding the treatment composition may be used. Furthermore, this treatment method can be applied to static, fixed-volume, non-flowing mixed contaminated fluids.

[0021] Similarly, the inventors have found that, for such treatment systems and methods, treatment compositions and variations thereof disclosed in PCT / US2018 / 064015 and the '911 patent are suitable for treating contaminated fluid mixtures because the components of these compositions will simultaneously perform similar treatment functions on all fluids in the mixture, as they would when treating liquids or gases individually, but with increased efficiency when treating mixtures. PCT / US2018 / 064015 discloses a concentrated aqueous hydroxide solution having 35-55 wt% of one or more hydroxide compounds as the main component of the new treatment composition, for example at least 80 wt% and preferably at least 90 wt%, and small amounts (e.g., 0.1-3 wt%) of organic acids, such as fulvic acid or humic acid, and possibly small amounts (e.g., 0.1-3 wt%) of MEA, and possibly antibacterial compounds, such as potassium silicate. One or more concentrated hydroxide compounds react with H2S, CO2, and other contaminants to treat them, while the function of organic acids (such as fulvic acid and humic acid) is to prevent the formation of any precipitates and their release from the treated fluid. If included as an optional component, MEA acts as a scale inhibitor. Alternatively, the treatment composition disclosed in the '911 patent may also be an aqueous solution primarily comprising a high concentration of one or more hydroxide compounds, for example, 35-55 wt% of one or more hydroxide compounds as the main component, for example, at least 80 wt% and preferably at least 90 wt% of the treatment composition, and: 0.1-3 wt% of one or more organic acids, such as fulvic acid or humic acid; a small amount (e.g., 0.5-4 wt%) of EDTA (C 10 H 16EDTA (N2O8) is a chelating agent that particularly helps improve the molar reactivity of one or more hydroxide compounds and helps prevent the formation of precipitates; and possibly a small amount (e.g., 0.01-0.1 vol%) of a surfactant, such as sodium dodecyl sulfate; and a buffer, such as potassium carbonate. The inventors have further discovered that, depending on the desired results of the treatment method, several other components can be included in the previously proposed treatment composition. The treatment composition may also contain a small amount (e.g., at least 0.5 wt%, preferably less than 2 wt%) of a polymer, which can also help prevent the release of precipitates from the treated fluid. Examples of such polymers are commercially available anionic polymers identified by product code 3640. The treatment composition may also contain 0.1 to 8.0 wt% of sodium sulfide (HNa2S) or its hydrate Na2S·9H2O, both of which are colorless solids. The inventors have significantly discovered that the inclusion of sodium sulfide in the new treatment composition can very effectively reduce the total sulfur content of the contaminated fluid.

[0022] Of course, the appropriate amount of such treatment composition will be based on the quantity of the mixed fluid being treated and the level of contaminants contained therein. For a typical oil well with a wellhead tubing diameter of 2-10 inches and continuous operation, this might involve 5,000-10,000 barrels of crude oil and 10-20 million ft... 3 The output of natural gas per day (24 hours) is such that the H2S content of the mixed fluid may be 60,000 ppm or as high as hundreds of thousands of ppm. The inventors have discovered that the appropriate amount of the treatment composition for such cases can be in the range of 5 to 20 gallons of treatment composition added per hour or 120 to 480 gallons of treatment composition added per day. The inventors have determined that under these conditions, if the fluid mixture initially contains 60,000 ppm or more of H2S, the treated crude oil in the mixed fluid will have less than 5 ppm of H2S and typically 0 ppm of H2S, while the treated natural gas in the mixed fluid will have less than 30,000 ppm of H2S, which is suitable for making the gas acceptable for pipelines transporting the gas to the refinery.

[0023] The simultaneous treatment of the mixed fluid according to the invention is particularly effective and advantageous because the dosage of the treatment composition added to the mixed fluid can correspond to an amount typically added to a liquid containing large amounts of H2S and other contaminants to reduce the contaminants to a safe and acceptable level, while the treatment composition remains in use for the liquid portion of the mixed fluid. However, as an additional benefit of this treatment method, the same treatment composition also functions to significantly reduce H2S and other contaminants in the gaseous portion of the fluid mixture.

[0024] A second discovery by one of the inventors of this invention relates to the treatment of contaminated gases. Such gases include: natural gas from wells, which may contain significant amounts of salt, CO2, H2S, NH3, SO2, other sulfur-based contaminants (including thiols and thiophenes), and metals; natural gas already partially treated according to the inventor's first discovery discussed herein; combustion gases from fossil fuels from various industries (including power plants), which typically have high concentrations of CO2 and SO2; gas streams containing water vapor with salts and metals, etc. Specifically, the inventors have discovered that if a washing solution is modified to have an elevated pH of above 8, preferably in the range of above 8 to about 11, by adding one or more alkaline substances (including hydroxide compounds), such alkaline washing solutions are unexpectedly and extremely effective in removing most contaminants from the contaminated gas during treatment, thereby bubbling or otherwise passing the gas through the alkaline washing solution for a contact time in the range of 0.5-10 seconds. The inventors have experimented with this treatment method using alkaline water washing solutions based on the second discovery and found that it is surprisingly very effective in removing and / or treating most salts, CO2, H2S, SO2, other sulfur-based contaminants (including thiols and thiophenes), and metals from contaminated gases. Furthermore, if the alkaline water washing solution is periodically replaced or re-strengthened to maintain its effectiveness, this treatment method can be used efficiently and cost-effectively to remove most contaminants from a variety of contaminated gas streams, including highly contaminated ones.

[0025] Water is typically effective for removing salts from contaminated gases because salts are highly soluble in water and readily transfer from the gas to the water when the gas comes into contact with the water in the washing solution. However, the inventors have discovered that if the water in the washing solution is made alkaline (pH above 8) by adding an alkaline substance (such as a hydroxide compound), the washing solution becomes surprisingly effective at removing virtually all salts from the gas, and also becomes very effective at removing and / or treating significant amounts of H2S and other sulfur-based contaminants, CO2, metals, and virtually all other contaminants from the gas. For example, the inventors have discovered that if the pH of the washing solution is increased to about 11 by adding an alkaline substance (such as one or more hydroxide compounds), and if a highly polluted gas, such as H2S, SO2, CO2, or salt, is passed through the alkaline washing solution for a suitable contact time of at least 0.5-10 seconds, and preferably at least 1.5 seconds: 1) substantially all the salts are transferred from the gas to the washing solution and precipitated from the alkaline washing solution; 2) many sulfur-based contaminants in the gas (including H2S, SO2, thiols, and thiophenes) react with the alkaline substance (such as one or more hydroxide compounds) added to the washing solution. The gases are treated and then precipitated from the gas and / or washing liquid as elemental sulfur and / or sulfur compounds produced by such treatment reactions; 3) Many carbon-based contaminants in the gas (including CO2 and CO) are treated by reacting with alkaline substances (such as one or more hydroxide compounds) added to the washing liquid and then precipitated from the gas / alkaline washing liquid, for example, as carbonate crystals; and 4) Many metallic contaminants in the gas also react with alkaline substances (such as one or more hydroxide compounds) added to the washing liquid and then precipitated from the gas / alkaline washing liquid. If the H2S and CO2 content in the gas is approximately 30,000 ppm before washing, their respective content can be reduced to approximately 5,000 ppm or lower after passing through the alkaline washing liquid.

[0026] By adding larger amounts of alkaline substances (such as hydroxide compounds), the pH of the washing solution can be increased to above 11, and such alkaline washing solutions will be very effective at removing most contaminants from contaminated gases. However, in terms of cost, in reality, increasing the pH to above 11 requires far more of this substance proportionally compared to increasing the pH of water from about 7 to 11. On the other hand, the more alkaline washing solutions are used (reflected in a decrease in pH), the worse they become at treating and removing contaminants from gases, and alkaline washing solutions may need to be replaced regularly to maintain their effectiveness in treating and removing contaminants from gases. For example, the inventors have determined through testing that when the pH of the washing solution drops below 10, the alkaline washing solution becomes increasingly inefficient in treating contaminants in the gas and / or precipitating them from the gas / washing solution. For instance, when the pH of the alkaline washing solution drops to about 9.5, some H2S and CO2 will begin to pass through. When the pH drops below 9, the ability of the alkaline washing solution to treat and remove contaminants from the gas is significantly reduced relative to its original ability at pH 10 or higher. And at about 8, the ability of the alkaline washing solution to further treat and remove contaminants from the gas is essentially exhausted, even if various precipitates released from the treated gas and washing solution are removed continuously or somewhat continuously. Therefore, alkaline water wash solutions may be most effective, possibly close to 100%, in removing and / or treating contaminants from contaminated gases if the solution is replaced whenever its pH drops below 10. However, this is not the most practical and cost-effective method for removing contaminants using water wash solutions because a significant amount of reactants still remains in the alkaline water wash solution when the pH drops below 10. The inventors have discovered that the most practical and cost-effective method for using alkaline water wash solutions is to initially raise the pH to approximately 11 by adding an alkaline substance (such as a hydroxide compound), use such a solution to remove contaminants from the contaminated gas stream until the pH of the solution drops to between 9 and 8, and then replace the solution with a fresh solution at a pH of approximately 11, repeating these steps as needed.

[0027] A third discovery by one of the inventors of this invention also relates to a novel treatment composition for treating contaminated gases comprising a significant amount of one or more hydrocarbon-based liquids, said contaminated gases including: natural gas from wells; natural gas already partially treated according to the first discovery of the inventors discussed herein; combustion gases from fossil fuels typically having high concentrations of CO2 and SO2; gas streams containing water vapor, salts, and metals, etc., and when used in combination with an alkaline water scrubbing treatment method according to the second discovery of the inventors discussed herein, it is particularly effective and cost-efficient in completely treating contaminants such as H2S, CO2, and metals in the gases.

[0028] The treatment composition according to the inventor's third discovery is a novel alkaline hydrocarbon-based liquid treatment composition with a pH of about 14, and the treatment composition can be used to treat contaminated gases, for example, the contaminated gases can be passed through a volume of the treatment composition for a contact time of 0.5-10 seconds (preferably at least 1.5 seconds) to achieve the treatment of H2S and other pollutants in the gas. Many types of hydrocarbon-based liquids can be used in the novel treatment composition, including one or more relatively light liquids, including alcohols, toluene, hexane, xylene, etc., and mixtures of these liquids, provided that one or more hydroxide compounds and any other components contained in the treatment composition can be completely dissolved or dispersed in the hydrocarbon-based liquid. Alcohols are suitable as hydrocarbon liquids because they are polar, making other components of the one or more treatment compositions generally soluble and / or miscible therein. Lighter alcohols (including methanol (CH3OH), ethanol (C2H5OH), and n-propanol (C3H8O)) may be more suitable due to lower cost and / or higher vapor pressure. Toluene, hexane, and xylene are also suitable as hydrocarbon liquids because hydroxide compounds and other components can be dissolved or dispersed therein. Their relatively high vapor pressures are desirable because the vapors may contain more of one or more reactive hydroxide compounds, which react better with gaseous pollutants, including H₂S and CO₂. Other hydrocarbon liquids besides alcohols, toluene, hexane, and xylene can be used, provided that one or more hydroxide compounds and other components can be dissolved or dispersed therein. Furthermore, the hydrocarbon liquid should have a higher vapor pressure than water.

[0029] By using a hydrocarbon-based liquid as the base solvent for the treatment composition, the vapor pressure of the treatment composition at standard temperature and pressure (STP) can be greater than that of the water-based treatment compositions previously proposed by the inventors at STP. Accordingly, more of the treatment composition can be in the gas phase and can have correspondingly greater contact with contaminants, including H2S and CO2, which tend to be in the gas phase at STP, even when H2S and CO2 are in a mixed fluid flow containing both liquid and gaseous fluids, and the treatment composition can treat H2S and CO2 more effectively and efficiently. When contaminated fluids (such as crude oil, produced water, and natural gas) are extracted from underground through wells, the fluid may be at a temperature of 90°F to 120°F when it reaches the Earth's surface, but as the fluid flows through pipelines to separators, refineries, or other destinations, it will cool to the ambient temperature around the pipeline, making it important that the treatment composition can effectively treat contaminants, including H2S and CO2, at STP. The novel treatment composition effectively treats H2S, CO2 and other contaminants in contaminated fluids under STP, but one or more treatment reactions may proceed faster at elevated temperatures.

[0030] Generally, all hydroxide compounds can be used, provided they are soluble or dispersible in one or more hydrocarbon liquids in all compositions. However, some hydroxide compounds, such as NaOH and KOH, are less expensive and, if used, can make the composition and the treatment method using the composition more economically advantageous. Furthermore, if the treatment composition is used for fluids containing a large amount of NaCl, such as crude oil and / or natural gas, where the NaCl will typically dissolve in any water contained in the fluid, it may be desirable to use little or no NaOH to help prevent any salts from precipitating from the treated fluid. The treatment composition may contain 30-50 wt% of one or more hydroxide compounds in total. Importantly, in addition to the one or more hydrocarbon liquids, the components in the composition should be soluble, dispersible, and / or miscible in one or more hydrocarbon-based liquids used in the treatment composition, because when used in the treatment method of the present invention, there should be no precipitates, etc., from the treatment composition itself.

[0031] The novel treatment composition may contain water, even a substantial amount, up to 50% by volume. However, the presence of water in the treatment composition may increase the likelihood of precipitate formation and release from the treated fluid, which is undesirable in many cases. Hydroxides tend to bind more strongly to water than to hydrocarbon liquids, and when the novel treatment composition is added to a contaminated fluid containing water and salts and / or other contaminants dissolved or dispersed in the water, the water-bound hydroxides may cause the release of salts and other contaminants from the treated fluid.

[0032] The novel treatment composition may also contain amounts of other chemical compounds, depending on the specific characteristics of the contaminated fluid being treated and the desired outcome, including whether there is a concern about the formation and release of precipitates in the treated fluid. However, the amounts of these other chemical compounds will be significantly less than the amounts of one or more hydroxide compounds in the treatment composition. For example, the novel treatment composition may contain 0.01 to 6 wt% of one or more organic acids, such as fulvic acid and humic acid, which the inventors have found to be very effective in preventing the precipitation of substances formed by the treated H2S and other contaminants from the treated fluid. The treatment composition may contain 0.01 to 6 wt% of a chelating agent, such as ethylenediaminetetraacetic acid (EDTA). EDTA, in particular, increases the efficiency of the hydroxide compounds in treating H2S and helps to make the H2S treatment using the novel treatment irreversible. The treatment composition may also contain 0.1 to 8.0 wt% of sodium sulfide (HNa2S) or its hydrate Na2S·9H2O, both of which are colorless solids. The inventors have significantly found that the inclusion of sodium sulfide in the novel treatment composition can very effectively reduce the total sulfur content of the contaminated fluid. The treatment composition may also contain a small amount (e.g., 0.5% at least to 5 wt%, preferably less than 2 wt%) of a polymer that can also help prevent precipitates from being released from the treated fluid. Examples of such polymers are commercially available anionic polymers identified by product code 3640. Small amounts (e.g., 0.02% at least 1 wt%) of surfactants (such as sodium dodecyl sulfate) and buffers (such as potassium carbonate) may be added.

[0033] When treating contaminated gas using a new treatment composition by passing a certain volume of the composition through it, the pH of the composition will decrease as it is used, and the inventors have determined that when the pH of such a composition drops to between 10 and 9, it is essentially depleted and should be replaced. NaOH can be used as a hydroxide compound in hydrocarbon-based liquid treatment compositions, but it is not preferred because the formation and release of any precipitates and scale from the treated natural gas and / or from the hydrocarbon-based liquid treatment solution is undesirable, as precipitates and scale tend to accumulate rapidly and clog parts of the treatment system and pipelines receiving the treated gas. Na is a common component of salts, which are common precipitates. For the purpose of contacting the contaminated gas with the alcohol-based treatment solution, a certain amount of the treatment composition can be arranged in a bubble column or other reaction chamber at ambient temperature and pressure, and the gas can be bubbled or otherwise passed through the composition such that there is an appropriate contact time between the gas and liquid composition as discussed above, and wherein there is a top space above the treatment composition in the bubble column or other reaction chamber, in which the vapor of the treatment composition and the gas being treated will come into contact with each other to further, and in most cases completely, treat any contaminants that may remain in the gas, such as H2S and CO2.

[0034] This novel hydrocarbon-based liquid treatment composition is particularly efficient and effective at treating gaseous contaminants in gases because it has a relatively high vapor pressure at ambient temperature and pressure, much higher than that of water-based treatment compositions according to the inventors' first and second discoveries discussed herein. One or more hydroxide compounds in the treatment composition are also included in the vapor of the composition, ensuring sufficient contact with gaseous contaminants (including H2S and CO2) in the gas, not only as the gas passes through the liquid treatment solution but also in the headspace above the treatment solution in the reaction chamber. This contact between the gaseous contaminants and the vapor of the treatment composition differs from the contact between the gaseous contaminants and a liquid that is sprayed or injected into the gas in the form of atomized fine droplets. The contact between the gaseous contaminants and the vapor of the treatment composition is far greater than the contact between the gaseous contaminants and the fine atomized droplets because vapor molecules are much smaller than fine droplets, and this results in more efficient and effective treatment of the contaminants. The treatment compositions and methods according to the inventors' third discovery have proven to effectively and completely treat substantially all contaminants in gases, including H2S, CO2, and metals, including natural gas, combustion gases from fossil fuels, typically with high concentrations of CO2 and SO2, etc. Gases (including natural gas) processed using new hydrocarbon-based liquid compositions and methods are very clean, allowing consumers to use them directly and safely without further processing. Therefore, for example, if the processing is carried out at or near the well where the natural gas is produced, the processed gas can be directly compressed into LPG at the same location, and as an added benefit, the transportation and storage costs of the processed natural gas can be significantly reduced.

[0035] Furthermore, the inventors have determined that the treatment compositions and methods according to the inventors' third discovery are particularly effective and efficient in completely treating substantially all contaminants in gases when used in combination with the alkaline water scrubbing solution according to the inventors' second discovery discussed herein. When used in series, the treatment compositions and methods according to the inventors' second and third discoveries have proven highly suitable and cost-effective for treating contaminated gases (including natural gas) in a continuous manner at high flow rates, regardless of the levels of H2S, CO2, and one or more other contaminants in the contaminated gas. The alkaline water scrubbing solution according to the second discovery is highly effective at removing all salts and many other contaminants from gases at a relatively low cost, even though this may require periodic or regular replacement of the alkaline water scrubbing solution when it is depleted or continuous reinforcing of the alkaline water scrubbing solution, since the alkaline water scrubbing solution mainly contains water and alkaline substances, such as relatively inexpensive hydroxides. Although the hydrocarbon-based treatment compositions used in the treatment method according to the third discovery may have a significantly higher cost per unit volume than alkaline water washing solutions, the amount of contaminants removed using such hydrocarbon-based treatment compositions and methods is relatively small compared to the amount of contaminants initially removed by alkaline water washing solutions. Accordingly, hydrocarbon-based treatment compositions can be used to remove all or most of the residual contaminants from a much larger volume of gas before the alcohol-based treatment composition is depleted and must be replaced or re-enhanced. Furthermore, the hydrocarbon liquids in the depleted solution can be recovered and reused relatively inexpensively by distillation or other known methods. To any extent that the hydrocarbon-based treatment solution replaced by the method according to the invention contains any unused hydroxide compounds and organic acids remaining therein, these can be mixed with produced water extracted from the well along with crude oil and natural gas to reduce the content of H2S and other contaminants contained in the produced water before it is injected back into the ground.

[0036] For example, the inventors have determined that for quantities between five million and ten million ft 3A continuous flow of natural gas containing approximately 60,000 ppm of each of H2S and CO2, as well as higher concentrations of other sulfur-based contaminants (including thiols and thiophenes), BTEX compounds, water vapor, salts, and metals, can be adequately treated using two bubble column reactors (one for an alkaline water wash and the other for a hydrocarbon-based treatment composition) to remove and / or treat all contaminants to safe, acceptable levels. Each such reactor may be four (4) feet in diameter and twenty (20) feet high, one containing approximately 1,410 gallons of alkaline water wash and the other containing approximately 1,410 gallons of an alcohol-based treatment composition, which will fill the lower fifteen (15) feet of each reactor, leaving five (5) feet of top space. Similarly, when the pH drops from an initial value of about 11 to a value between 9 and 8, the alkaline washing solution is considered to be depleted and should be replaced, typically about once per hour, and when the pH drops from an initial value of 14 to a value between 10 and 9, the hydrocarbon-based treatment solution is considered to be depleted and should be replaced, which could be about every eight (8) to ten (10) hours for treating this volume of contaminated gas.

[0037] In summary, the combination of treatment compositions and methods according to the inventors' second and third discoveries is highly effective and efficient in removing and / or treating contaminants from gases, even highly polluted gases, in a practical and cost-effective manner. Importantly, this combination of the inventors' second and third discoveries can be successfully used to treat currently unexploited or closed natural gas reserves worldwide, for which no previously known cost-effective treatment methods exist. Furthermore, if the inventors' first discovery was initially used to treat mixtures of crude oil and natural gas, this would add further benefits and cost-efficiency to the treatment of these fluids. Additionally, the combination of treatment compositions and methods according to the inventors' second and third discoveries can be effectively and economically used in carbon sequestration / mitigation strategies. For example, if the contaminated gas contains 80,000 ppm or more CO2 / CO, such as a volume of 13 million ft... 3 The combined treatment methods discovered in the second and third findings can remove 57,058 kg or 63 tons of CO2 per day from natural gas streams or fossil fuel combustion gases from power plants, which would otherwise be released into the atmosphere. Similarly, alkaline water scrubbing solutions can remove most of the CO2 themselves and can be used accordingly for carbon sequestration / mitigation strategies.

[0038] Public Intent

[0039] Although the following disclosure provided for public dissemination is detailed to ensure adequacy and aid in understanding the invention, it is not intended to diminish the purpose of the patent, which is to cover every new inventive concept therein, regardless of how it may subsequently be obscured by formal changes or the addition of further improvements. The claims at the end of this document are the primary aids in achieving this purpose, as it is these claims that satisfy the requirement to indicate the improvements, combinations, and methods in which the inventive concept was discovered. Attached Figure Description

[0040] Figure 1 This is a schematic diagram of a mixing chamber, which can be used in an exemplary embodiment of the invention to combine a treatment composition according to the invention with a mixture of contaminated fluids, such that the treatment composition according to an exemplary embodiment of the invention can treat contaminants in all fluids.

[0041] Figure 2 This is a schematic diagram of a water-washing reaction chamber, which can be used in another exemplary embodiment of the invention to remove most of the pollutants from a contaminated gas according to a second embodiment of the invention.

[0042] Figure 3 This is a schematic diagram of a PSA reaction chamber, which can be used in another exemplary embodiment of the invention to remove most or all of the pollutants from a contaminated gas according to a third embodiment of the invention.

[0043] Figure 4 This is a schematic diagram illustrating how different embodiments of the present invention can be used together to efficiently treat contaminants in mixed fluid flows (such as flows of crude oil and natural gas from wells). Detailed Implementation

[0044] Exemplary embodiments of the present invention will now be described.

[0045] A key aspect of the invention relates to the use of novel treatment compositions in a treatment method, according to exemplary embodiments, to treat contaminated liquid and gaseous mixtures (such as mixtures of crude oil and natural gas from wells) and to remove and treat contaminants in contaminated gases. Figure 1 This is a schematic diagram of a mixing chamber, which can be used in exemplary embodiments of the invention to combine a treatment composition according to the invention with a mixture of contaminated fluids, such that the treatment composition can treat contaminants in all fluids; Figure 2 This is a schematic diagram of a water-washing reaction chamber, which can be used to remove most of the contaminants from contaminated gas using an alkaline water washing solution according to another exemplary embodiment of the present invention; Figure 3This is a schematic diagram of a bubble column-type reaction chamber, which can be used to treat most or all of the contaminants in a contaminated gas using an alcohol-based treatment composition according to another exemplary embodiment of the invention; Figure 4 This is a schematic diagram illustrating how different embodiments of the present invention can be used together to efficiently treat contaminants in mixed fluid flows (including flows of crude oil and natural gas from wells).

[0046] Systems and methods for treating contaminated liquid and gas mixtures

[0047] The first aspect and exemplary embodiments of the invention relate to the inventors' discovery that by adding an appropriate amount of a treatment composition, such as one disclosed in PCT / US2018 / 064015 and US Patent 10,913,911, to a contaminated fluid mixture (comprising a mixture of one or more contaminated liquids and one or more contaminated gases), a treatment composition can react with and treat H2S and other contaminants in both the liquid and gaseous components of such a fluid mixture, resulting in a significant reduction in the levels of H2S and other contaminants, and substantially no sediment discharge from the treated fluid into the pipeline. The combination of the treatment composition with the contaminated fluid mixture can be achieved in various ways, including by injecting a dose of the treatment composition directly into the mixed fluid stream or into a volume of one of the fluids (whether flowing or not), or by using a mixing chamber. For example, see reference to... Figure 1 A system 100 is shown for combining a mixture of contaminated fluids with a treatment composition to treat contaminants in the mixture according to an exemplary embodiment of the invention. The system 100 may generally include: a horizontal mixing chamber 102 that receives a mixture of contaminated fluids from a source 104; a discharge nozzle 106 that discharges the mixed fluid into the mixing chamber; a discharge outlet 108 that discharges the fluid mixture in which the treatment composition has been added from the mixing chamber; a treatment composition supply source 110; and a recirculation pump 112 that draws a portion of the mixed fluid from the mixing chamber 102 via a discharge outlet 114 at the bottom of the mixing chamber, adds some of the treatment composition from the supply source 110 to this portion of the mixed fluid, and then adds the fluid mixture and the treatment composition to a stream of untreated fluid mixture flowing into a reactor from the source 104. A controller 116, such as a programmable electronic processing unit (ECU), may be provided for controlling the operation of the system 100.

[0048] The mixing chamber 102 can be formed of a suitable material (such as carbon steel) that is resistant to reaction with the mixed fluid and contaminants (including H2S) in the mixed fluid, and can have appropriate dimensions based on the volume of the mixed fluid being treated. For example, if the volume of the mixed fluid being treated is 5,000-10,000 barrels of crude oil and 10 million-20 million ft³ of natural gas per day (24 hours), then appropriate dimensions for the reactor 102 could be 4-10 feet in diameter and 12-25 feet in length. The discharge nozzle 106 can include one or more pipes extending longitudinally along the lower part of the mixing chamber and having a plurality of small openings formed in said one or more pipes, whereby the fluid mixture will enter the mixing chamber as a small fluid flow containing bubbles in the mixture. The pressure and bubbles of the mixed fluid flow will cause the fluid flow discharged from the small openings to flow upward through the larger volume of the mixed fluid and treatment composition already in the mixing chamber, thereby thoroughly mixing it with them. When the mixed fluid and treatment composition reach the upper part of the reactor, a portion of it is discharged through outlet 108, whereby the mixed fluid and treatment composition are combined in a fairly homogeneous mixture.

[0049] The recirculation pump 112 can be any suitable type of pump, but the inventors have found that a pneumatic diaphragm works appropriately not only to recirculate and mix the mixed fluid with the treatment composition from supply source 110, but also to maintain an appropriate desired concentration of the treatment composition in the mixing chamber and in the mixed fluid discharged from the reactor through outlet 108. A portion of the mixed fluid in the mixing chamber can be continuously drawn from the lower part of the mixing chamber, mixed with another treatment composition, and then flowed back into the mixing chamber together with another mixed fluid from source 104. To continuously add the treatment composition to the mixing chamber, the concentration of the treatment composition in the mixed fluid drawn from the mixing chamber can be monitored and determined by a sensor (not shown). If it is necessary to adjust the rate of addition of the treatment composition based on the sensed value, the rate of addition of the treatment composition via the recirculation pump 112 can be appropriately adjusted by the controller 116.

[0050] The inventor has discovered that when using, such as Figure 1The treatment system and method shown can efficiently and effectively treat such fluid mixtures to remove H2S and other contaminants when using previously proposed treatment compositions and variations thereof disclosed in, such as PCT / US2018 / 064015 and USSN 16 / 857,884, to treat large volumes of continuously flowing fluid mixtures highly contaminated with H2S and other substances. After being combined with the treatment composition in mixing chamber 102 and discharged from outlet 108, the fluid mixture can continue to flow in a pipeline to another pipeline that delivers the fluid mixture to a refinery, for example, typically for several miles and for a period of several hours. The treatment composition will react with and remove H2S and other contaminants from both the liquid and gaseous components of such fluid mixtures, such that the levels of these contaminants are reduced to appropriate levels when the fluid mixture reaches the pipeline leading to the refinery. Importantly, virtually no sediment is discharged from the treated fluid, largely due to the presence of one or more organic acids, such as fulvic acid and humic acid, in the treatment composition. Discharging any amount of one or more precipitates from the treated fluid is highly undesirable, as it could partially or completely clog pipelines and require pipeline shutdown for corrective action. The inventors have determined that even if a contaminated fluid mixture initially contains relatively high levels of H2S, such as 40,000 ppm or higher, this treatment method can reduce the H2S content in the liquid portion of the mixture (e.g., crude oil) to below 5 ppm and the H2S content in the gaseous portion of the mixture (e.g., natural gas) to below 20,000 ppm.

[0051] Treatment compositions and variations thereof disclosed in, such as PCT / US2018 / 064015 and U.S. Patent 10,913,911, are suitable for treating contaminated fluid mixtures. PCT / US2018 / 064015 discloses a concentrated aqueous hydroxide solution having 35-55 wt% of one or more hydroxide compounds as the main component of the novel treatment composition, for example at least 80 wt% and preferably at least 90 wt%, and a small amount (e.g., 0.1-2 wt%) of organic acids, such as fulvic acid or humic acid, and possibly a small amount (e.g., 0.1-3 wt%) of MEA, and possibly an antibacterial compound, such as potassium silicate. The concentrated one or more hydroxide compounds react with H2S to treat it, while the organic acids (such as fulvic acid and humic acid) function to prevent the formation and release of any precipitates from the treated fluid, and the MEA functions as an antiscalant. On the other hand, the treatment composition disclosed in U.S. Patent 10,913,911 may also be an aqueous solution mainly comprising a high concentration of one or more hydroxide compounds, for example, 35-55 wt% of one or more hydroxide compounds as the main component, for example, at least 80 wt% and preferably at least 90 wt% of the treatment composition, and: a small amount (e.g., 0.5-4 wt%) of ethylenediaminetetraacetic acid or EDTA (C10H16N2O8), EDTA being a chelating agent that particularly helps to improve the molar reactivity of one or more hydroxide compounds and helps to prevent the formation of precipitates; and possibly a small amount (e.g., 0.01%-0.1% by volume) of a surfactant, such as sodium dodecyl sulfate; and a buffer, such as potassium carbonate. The pH of such treatment compositions according to the invention is about 14.

[0052] The inventors have determined that the treatment composition may further comprise a small amount (e.g., 0.1 wt% at least 5 wt%, preferably less than 2 wt%) of a polymer that can help prevent any salts in the treated fluid from precipitating out; and / or comprise 0.1 to 8.0 wt% of sodium sulfide (HNa2S) or its hydrate Na2S·9H2O, both of which are colorless solids and help reduce the total sulfur content of the contaminated fluid. Examples of such polymers are commercially available anionic polymers identified by product code 3640. The inventors believe that such polymers and other similar polymers can encapsulate salts in the treated fluid, and this prevents or helps prevent salts and other contaminants from precipitating out. While adding sodium sulfide for the purpose of reducing the sulfur content of contaminated fluids may seem counterintuitive, the inventors of this invention have found that adding sodium sulfide or its hydrate to the treatment composition can help reduce the total sulfur content in a variety of contaminated fluids, including liquids and gases treated with the treatment composition. In particular, the inventors have discovered that in the treatment composition, sodium sulfide promotes the reaction with sulfur and sulfur-containing compounds, thereby converting most of the sulfur into sulfur dioxide (SO2). Sulfur dioxide is typically released as a gas from the treated fluid at standard temperature and standard pressure (STP). Although the presence of sodium sulfide in the treatment composition may also lead to the formation and release of relatively small amounts of sulfur-containing precipitates, which the inventors have identified as C using gas chromatography. 18 H8N4O5S2. SO2 is irritating to humans and will be captured and / or further processed, and, if necessary and as required, the precipitate will be removed from pipelines or other structures containing the treated fluid or in which the treated fluid flows. Sodium sulfide and its hydrates are readily soluble in water (e.g., at a concentration of 15-25 wt%) and in hydrocarbon-based liquids used in the treatment compositions of this invention.

[0053] Of course, the appropriate amount of such treatment composition will be based on the quantity of the mixed fluid being treated. This applies to outputs of 5,000-10,000 barrels of crude oil and 10 million to 20 million ft... 3For typical oil wells producing natural gas per day (24 hours) and where the mixed fluid contains 40,000 ppm or higher H2S, the inventors have found that an appropriate amount of the treatment composition can be added in the range of 5 to 20 gallons per hour or 120 to 480 gallons per day. Under these conditions, the treated crude oil in the mixed fluid will have less than 5 ppm H2S and typically 0 ppm H2S, while the treated natural gas in the mixed fluid will have less than 20,000 ppm H2S, which is suitable for making the gas marketable and usable for delivery to refinery pipelines. Furthermore, it should be noted that bacteria often grow in the pipelines through which the mixed crude oil and natural gas flow, for example, bacteria adhering to the pipeline walls, and such bacteria can be a problem because they may help retain or regenerate H2S and other sulfur-based contaminants in the mixed fluid. Therefore, the amount of the treatment composition added to the mixed crude oil and natural gas according to the present invention can initially be at a higher rate within the discussed range of 5 to 20 gallons of treatment composition per hour, such that the treatment composition can kill bacteria, and after a period sufficient to kill bacteria, the dosage rate can be reduced to a lower value within the range. Compared to adding 5 to 20 gallons of treatment composition per hour for the flowing crude oil and natural gas mixture discussed above, for a static, non-flowing fluid mixture, the treatment composition can be added at a dosage proportional to the volume of the fluid being treated, although the dosage may be increased for various reasons, including whether the fluid mixture is highly contaminated, whether a faster treatment time is desired, etc.

[0054] While the examples given above pertain to flowing crude oil and natural gas mixtures, the invention is not limited to this and can be used to treat any contaminated fluid mixture in both continuous and discontinuous manner. For discontinuous treatment, a treatment composition can be added to the fluid mixture, and the combination of the fluid mixture and the treatment composition can then be allowed to react for an appropriate period of time, such as 15-120 minutes. The treatment mixture can be agitated and / or heated to help enhance the contact between the treatment composition and the fluid mixture.

[0055] An important discovery by the inventors regarding the treatment method according to the invention is that, when one or more water-based treatment compositions are added to a contaminated fluid mixture stream, it is crucial to control and monitor the pH of the treated fluid mixture stream to prevent the formation and / or release of precipitates. Typical fluid mixtures produced from oil / gas wells may have an initial pH of 5-6, but due to the highly alkaline nature of the one or more water-based treatment compositions, the pH of the mixed fluid stream will increase when one or more treatment compositions are added, particularly in small, localized fluid stream pockets where one or more hydrocarbon-based liquid treatment compositions are being added to the fluid stream. Typically, the final pH of the fluid stream treated according to the invention can be approximately 7.0-7.3, but when the treatment composition is added to the fluid stream pockets, these fluid mixtures in such pockets will temporarily spike to a much higher pH, which may lead to the formation and release of precipitates from these pockets. The inventors have discovered that when treating a mixed fluid stream using one or more water-based treatment compositions, controlling the pH of the treated mixed fluid stream (including the fluid stream bag) to remain below about 10 can avoid concerns about the formation and / or release of precipitates from the mixed fluid stream. As discussed in PCT / US2021 / 058610, the inventors previously discovered that, in order to prevent the formation and / or release of one or more precipitates from the mixed fluid stream, the pH of the treated fluid stream should not increase to a value above about 10, even in small, localized fluid stream bags where one or more water-based treatment compositions are added to the fluid stream.

[0056] To properly control the pH of the mixed fluid stream in the processing method of the present invention, it is also advantageous to add or inject the treatment composition into the mixed fluid stream in multiple smaller doses and / or at multiple locations and / or at different times, such that no portion of the treated fluid will experience a temporary pH increase even above 10.5, as this could lead to the release of precipitates. In other words, it is desirable not to inject the full dose of the water-based treatment composition at a single location and / or at a single time, as this is likely to cause the pH of the mixed fluid stream or the pH of the mixed fluid stream bag to temporarily rise above 10.5. Even a temporary pH increase above 10.5 could lead to the undesirable formation and / or release of precipitates from the treated fluid stream. The specific dose can be determined based on the pH of the mixed fluid stream, or the pH can be monitored at multiple locations along the flow path of the mixed fluid stream. The pH of the treated mixed fluid stream generally corresponds to the amount of residual unreacted treatment composition remaining in the mixed fluid stream, and accordingly, as the mixed fluid stream continues to flow to a refinery or other destination, such pH monitoring allows one or more additional appropriate doses of the treatment composition to be added to the mixed fluid stream if needed. By adding smaller doses of the treatment composition at multiple locations and / or at different times in the mixed fluid flow, it is ideally possible to add more treatment composition to the mixed fluid flow without concern about causing the formation and / or release of precipitates.

[0057] Treatment method for removing most pollutants from contaminated gases using modified washing solutions.

[0058] The second aspect and embodiments of the invention relate to a novel treatment method for efficiently and cost-effectively removing substantially all contaminants typically present in contaminated gases, including: natural gas from wells, which may contain significant amounts of salts, CO2, H2S, other sulfur-based contaminants (including thiols and thiophenes), and metals; natural gas already partially treated according to the first aspect and embodiments of the invention discussed herein; combustion gases from fossil fuels, typically having high concentrations of CO2 and SO2, NH3; gas streams containing water vapor with salts and metals, etc., regardless of the amount of contaminants in the gas. This treatment method is based on the inventors' discovery that if a washing solution is modified to be alkaline by adding one or more alkaline substances (including hydroxide compounds), having an elevated pH above 8 (preferably in the range of above 8 to about 11), such alkaline washing solutions are surprisingly highly effective treatment compositions for removing substantially all contaminants from contaminated gases when the gas is bubbled or otherwise passed through the alkaline washing solution for a contact time in the range of 0.5-10 seconds (preferably at least 1.5 seconds). Based on extensive experimentation, the inventors have determined that this treatment method using the alkaline water washing solution according to the second embodiment is surprisingly effective in removing most salts, CO2, H2S, other sulfur-based contaminants (including thiols and thiophenes), NH3, and metals from contaminated gases. Furthermore, if the alkaline water washing solution is periodically replaced or re-fortified to maintain its effectiveness, it can be used efficiently in a practical and cost-effective manner to remove most contaminants from a variety of contaminated gas streams, including highly contaminated gas streams.

[0059] Various alkaline substances can be added to the washing solution to increase its pH to a desired value of approximately 11. These alkaline substances include one or more hydroxide compounds, such as potassium hydroxide (KOH), ammonium hydroxide (NH4OH), lithium hydroxide (LiOH), magnesium hydroxide (Mg(OH)2), and manganese hydroxide (Mn(OH)2, Mn(OH)4), all of which are readily soluble in water. Thus, for example, if KOH is added to the washing solution to increase the pH of the water from approximately 7 to approximately 11, the inventors have found that this can be achieved by combining a certain amount of concentrated (45 wt%) aqueous KOH solution with a certain amount of water in a ratio of approximately 1:7 to 1:8, or by adding an equivalent amount of KOH powder or KOH hydrate flakes to the water. NaOH can also be used as one of the hydroxide compounds in the washing solution, but it is not preferred because salts are the main type of contaminant that is being removed in alkaline washing solutions, and Na is also a major component of NaCl salts. NH4OH is a suitable compound for raising the pH of the washing solution, but should not be the only compound used for this purpose, as it can release ammonia (NH3) into the gas being treated, and governments impose limits on the NH3 content in gases; for example, natural gas should contain no more than 14 ppm of NH3. Therefore, for example, a larger amount of KOH or LiOH can be used with a smaller amount of NH4OH to increase the pH of the washing solution. NH4OH not only works effectively in the alkaline washing solution when the gas is bubbled through it, but also advantageously increases the vapor pressure of the alkaline washing solution, allowing contaminants remaining in the treated gas after passing through the washing solution to be further treated by NH4OH vapor in the headspace above the washing solution in the reactor. Other substances that can optionally be added to the washing solution to improve its effectiveness and / or stability in removing contaminants from the gas include small amounts (e.g., less than 1% by volume) of surfactants (such as sodium dodecyl sulfate) or commercially available anionic polymers, buffers such as phosphoric acid (H3PO4), etc.

[0060] Water is typically effective at removing salts from contaminated gases because salts are highly soluble in water and readily transfer from the gas to the water when the gas comes into contact with the water in the washing solution. However, the inventors have discovered that if the water in the washing solution is made alkaline (pH above 8) by adding an alkaline substance (such as a hydroxide compound), the washing solution unexpectedly removes virtually all salts from the gas far more effectively and also becomes very effective at removing larger amounts of H2S and other sulfur-based contaminants, CO2, and metals from the gas. For example, the inventors have discovered that if the pH of the washing solution is increased to about 11 by adding an alkaline substance (such as one or more hydroxide compounds), and a highly polluted gas, such as H2S, CO2, SO2, or salt, is passed through the alkaline washing solution for a suitable contact time in the range of 0.5-10 seconds (preferably at least 1.5 seconds): 1) substantially all salts are transferred from the gas to the washing solution and / or precipitated from the washing solution; 2) many sulfur-based contaminants in the gas (including H2S, SO2, thiols, and thiophenes) react with the alkaline substance (such as one or more hydroxide compounds) added to the washing solution. The pollutants are treated and then precipitated from the gas and / or washing liquid as elemental sulfur and / or sulfur compounds produced by such treatment reactions; 3) Many carbon-based pollutants in the gas (including CO2 and CO) are treated by reacting with alkaline substances (such as one or more hydroxide compounds) added to the washing liquid and then precipitated from the gas / alkaline washing liquid, for example, as carbonate crystals; and 4) Many metallic pollutants in the gas also react with alkaline substances (such as one or more hydroxide compounds) added to the washing liquid and then precipitated from the gas / alkaline washing liquid, for example, as metal sulfides. If the concentrations of H2S, SO2, and CO2 in the gas are 30,000 ppm or more before washing, their concentrations can be reduced to approximately 5,000 ppm or lower after passing through the alkaline washing liquid. It should be noted that pollutants, including H2S, SO2, and CO2, may be present in the contaminated gas at concentrations of 60,000 ppm, 100,000 ppm, and several hundred ppm.

[0061] When gas passes through an alkaline washing solution, salts are removed from the gas because they are highly soluble in the solution, and once saturated, they precipitate out as salt crystals. Besides salt removal, several reactions occur between one or more hydroxide compounds in the alkaline washing solution and various contaminants in the gas. These reactions result in the treatment and / or removal of other contaminants as the gas passes through the washing solution, including reactions with H2S, CO2, and metals (including Fe, Al, Cr, V, etc.). Under the low redox conditions for natural gas formation and within the pH range of 8-11 for the alkaline washing solution, metal hydroxides and metal sulfides are favorable and will precipitate until, or unless a significant amount of carbonate is absorbed from CO2, metal carbonates can precipitate. If KOH is used to increase the pH of the washing solution, KOH will react with H2S and treat it according to the following equation to form potassium sulfide (K2S):

[0062] KOH + H₂S → K₂S + H₂O.......(1)

[0063] Unlike metal sulfides, K₂S is highly soluble. If the contaminated gas contains metals (e.g., Fe, Al, V, etc.), metal sulfides containing these metals will also precipitate from the alkaline washing solution. The type and solubility of the metal are functions of pH, redox potential, carbonate content, and the concentration of both the metal and the salt. CO₂ can be removed from the contaminated gas by contacting it with the alkaline washing solution according to the following reaction that forms bicarbonate crystals, as well as through other reactions:

[0064] CO2 + OH- → HCO3- - .......(2),K + +HCO3 - →KHCO3.......(3)

[0065] In a test of the treatment method according to the second embodiment of the present invention, potassium bicarbonate (KHCO3) crystallizes out of the solution because the salt is collected in the alkaline washing solution and the brine absorbs CO2. A similar reaction occurs if other hydroxide compounds besides KOH are used in the alkaline washing solution.

[0066] Although the upper limit of the pH range of the alkaline washing solution according to the second embodiment is approximately 11, in reality, by adding a larger amount of alkaline substances (such as hydroxide compounds), the pH of the washing solution can be increased to above 11, and such alkaline washing solutions will also be very effective at removing most contaminants from contaminated gases. However, in terms of cost, in practice, increasing the pH of the washing solution to above 11 requires far more of such alkaline substances proportionally compared to increasing the pH of water from approximately 7 to 11, making the upper limit of approximately 11 optimal for cost efficiency. On the other hand, the more alkaline washing solution is used (reflected in a decrease in the pH of the washing solution), the less efficient it becomes in treating and removing contaminants from the gas, thus the alkaline washing solution may need to be replaced periodically to maintain its effectiveness in treating and removing contaminants from the gas. For example, the inventors have determined through important tests that when the pH of the washing solution drops below 10, the alkaline washing solution becomes increasingly inefficient in treating contaminants in the gas and / or precipitating them from the gas / washing solution for removal. For instance, when the pH of the alkaline washing solution drops to approximately 9.5, some H2S and CO2 will still remain in the treated gas. When the pH drops below 9, the ability of the alkaline washing solution to treat and remove contaminants from the gas is significantly reduced relative to its original ability at pH 10 or higher, and at approximately 8, the ability of the alkaline washing solution to further treat and remove contaminants from the gas is essentially exhausted—depleted, even with continuous or semi-continuous removal of various precipitates released from the treated gas and washing solution. Therefore, while the alkaline washing solution may be most effective, approaching 100%, in removing contaminants from contaminated gases if it is replaced whenever the solution's pH drops below 10, this is not the most practical and cost-effective method for removing contaminants using a washing solution. The inventors have discovered that the most practical and cost-effective method of using alkaline water washing solutions is to initially increase the pH to about 11 by adding an alkaline substance (such as a hydroxide compound), then use such a solution to remove contaminants from the contaminated gas stream until the pH of the solution drops to between 9 and 8, and then replace the solution with a fresh solution at a pH of about 11, while repeating these steps as much as possible as needed.

[0067] Reference Figure 2 A schematic diagram of a water-washing reaction chamber is depicted, which can be used in a treatment method according to a second embodiment of the present invention to remove most of the contaminants from contaminated gas. Figure 2As shown, a reaction chamber, such as a bubble column 200, can be used to contain a certain amount of alkaline water washing solution 202 with a pH of about 11, which fills most of the reaction chamber, while the upper part of the reaction chamber defines a top space 204 above the solution 202. The size of the reaction chamber 200 can depend on the amount of contaminated gas being treated and / or the amount of contaminants contained in the gas that will be treated and removed by the alkaline water washing solution. For example, if a large continuous volume of contaminated gas, such as from a well at a rate of three (3) million to fifteen (15) million ft, is to be treated in the reaction chamber. 3 For a daily output of natural gas, the reaction chamber can have a diameter of (4) feet, a height of twenty (20) feet, and a volume of 1880 US gallons, of which solution 202 can fill 3 / 4 of the volume or 1410 gallons. Based on Stokes' Law, the flow of contaminated gas 205 into the bottom of the reaction chamber can be controlled for bubble formation and rise, with a desired liquid contact time, for example, 0.5 to 10 seconds, preferably at least 1.5 seconds. This can involve an exhaust nozzle 206 having a number of small exhaust openings defined therein, and can also involve some type of means for interrupting the gas flow through the reaction chamber so that the gas cannot flow uninterruptedly through the wash solution in the form of a stream or large bubbles, and thus will have a much larger surface area to react with the treatment composition. Such interruption means can involve filling the reaction chamber or a portion thereof with a fine non-reactive medium (e.g., stainless steel wool, pea gravel, porous plate, etc.) through which the natural gas will pass when it flows through the wash solution.

[0068] When the gas passes through the alkaline washing solution, most of the contaminants are removed as discussed above, and the treated gas can then pass through a baffle 208 or similar, which may be located in the top space 204, to help remove some of the alkaline washing solution remaining in the gas, and finally the treated gas is discharged from the upper part 210 of the reaction chamber. Water and treatment chemicals (such as hydroxide compounds) can be introduced into the reaction chamber through inlets 212, 214 to form the alkaline washing solution. A level sensor 215 can be used to set and control the level of solution 202 in the reaction chamber, and a sensor 216 can be used to monitor the pH of solution 202. As the contaminated gas flows through the alkaline washing solution in the reaction chamber, the alkaline chemicals in the solution (such as one or more hydroxide compounds) react with the contaminants in the gas, the pH of the solution gradually decreases, the solution becomes saturated with contaminants (such as salts), and eventually precipitates including salt crystals, metal sulfides, and carbonate crystals are released from the solution and may accumulate at the bottom of the reaction chamber. Once the pH of the solution drops to between 9 and 8, the solution is considered depleted according to the treatment method, and the depleted solution and any precipitates released from it can be removed, for example, through waste discharge outlet 218 at the bottom of the reaction chamber. Another volume of alkaline washing solution can then be introduced into the reaction chamber, and the treatment method can continue by repeating these steps whenever desired. The treatment method can be automated using a controller 220 (such as a programmed ECU), which receives input from sensors 215, 216 and controls the flow of solution and gas into and out of reaction chamber 200 by opening and closing various solenoid valves associated with the corresponding inlets and outlets of reaction chamber 200. The depleted washing solution and precipitates can be discarded in an appropriate manner, or, depending on the economics of the situation, some precipitates can be recycled, purified, and sold.

[0069] It should be understood that the treatment method using an alkaline water washing solution according to embodiments of the present invention can be used effectively and cost-effectively to remove contaminants from a variety of contaminated gases. The natural gas industry is a prime example, noting that prior to this invention, no known conventional method could effectively and cost-effectively treat some highly contaminated natural gas from existing wells and known underground deposits, thus there are many closed wells and unexploited deposits worldwide. Another type of contaminated gas that can be efficiently and cost-effectively treated using an alkaline water washing solution according to embodiments of the present invention is combustion gases from fossil fuels (such as coal) and petroleum-based liquids and gases, which typically contain large amounts of CO2, SO2, etc., as used in various enterprises including power plants. Therefore, such a treatment method can be used cost-effectively, for example, as a carbon sequestration / carbon mitigation strategy, noting that if fossil fuel-burning power plants operate at 13 (13) million ft... 3If a combustion gas containing 80,000 ppm CO2 is continuously output per day, then treating it using the aforementioned method will remove 57,058 kg or 63 tons of CO2 per day from the gas. Currently, governments reward companies with carbon credits for reducing CO2 emissions, and these credits can be equivalent to a substantial amount of money. The same principle applies to SO2 and other pollutants commonly found in gases.

[0070] A novel hydrocarbon-based liquid treatment composition and the use of said novel hydrocarbon-based liquid treatment composition for treatment Methods for treating polluted gases

[0071] A third embodiment of the invention also relates to the treatment of contaminated gases, said contaminated gases including: natural gas from wells; natural gas that has been partially treated according to the first and / or second embodiments of the invention discussed herein; combustion gases from fossil fuels, typically having high concentrations of CO2 and SO2; gas streams containing water vapor with salts and metals, etc., and is particularly effective and cost-efficient for the complete removal and / or treatment of all contaminants in the gases, including H2S, CO2, and metals, etc., when combined with the treatment method involving alkaline water scrubbing solutions according to the second embodiment discussed herein.

[0072] A novel hydrocarbon-based liquid treatment composition according to an exemplary embodiment of the present invention comprises one or more hydrocarbon-based liquids and one or more hydroxide compounds (e.g., 30-45 wt%) dissolved or dispersed in the one or more hydrocarbon-based liquids at a relatively high overall concentration, and optionally one or more other components as discussed herein. The hydrocarbon-based liquids used in the one or more novel treatment compositions impart an increased vapor pressure to the treatment compositions compared to the inventors' previously proposed water-based treatment compositions (including those discussed herein). The inventors have determined that such treatment compositions can more effectively and efficiently treat a variety of contaminated fluids (both liquids and gases), and in some cases, contaminated fluid mixtures, of H2S and other contaminants compared to the inventors' previously proposed water-based treatment compositions, and that the novel hydrocarbon-based liquid treatment compositions can more effectively prevent the formation and release of precipitates in the treated fluids compared to the inventors' previously proposed water-based treatment compositions, which may be very important. The novel treatment compositions effectively treat contaminants in the treated fluids over a wide temperature range (e.g., -30°C to 300°C) and a wide pressure range (e.g., from below atmospheric pressure to several atmospheres, including STP). In addition, the new treatment composition.

[0073] The novel treatment composition comprising a hydrocarbon-based liquid differs significantly from the previously proposed treatment compositions of the inventors, which are water-based liquid compositions that do not contain any hydrocarbon-based liquids. However, the other components of the treatment composition may be the same as or similar to those contained in the previously proposed water-based treatment compositions of the inventors.

[0074] For example, the novel treatment composition may also contain varying amounts of water, from little or none to up to 50 wt%, and water can facilitate the easy dissolution or dispersion of one or more hydroxide compounds and other optional components into the hydrocarbon-based liquid. If the novel hydrocarbon-based liquid treatment composition also contains a certain amount of water, or even a significantly large amount, the inventors have determined that, compared to the inventors' previously proposed water-based treatment compositions, the novel composition can still more effectively and efficiently treat some contaminated fluids or fluid mixtures, as well as prevent the formation and release of precipitates in various contaminated fluids and mixtures of contaminated fluids. Furthermore, when treating contaminated crude oil and contaminated natural gas from wells, which typically contain a certain amount of water, it may be appropriate to include additional water in the treatment composition. Such treatment compositions containing both one or more hydrocarbon liquids and water still have significantly higher vapor pressures than the inventors' previously proposed treatment compositions that do not contain one or more hydrocarbon-based liquids. In some cases, the presence of water in the treatment composition can increase the likelihood of precipitates being released from the fluid being treated. Hydroxides tend to bind more strongly to water than to hydrocarbon liquids, and when a new treatment composition is added to a contaminated fluid containing water and salts and / or other contaminants dissolved or dispersed in the water, the water-bound hydroxides may cause the salts and other contaminants to be released from the treated fluid.

[0075] Whether the treatment composition contains other chemical compounds may depend on the specific characteristics of the contaminated fluid being treated and the desired outcome, including whether it is desirable to cause or prevent the formation and release of precipitates from the treated fluid. Other possible components of the treatment composition include: one or more organic acids, such as fulvic acid and humic acid; polymers, such as anionic polymers with product code 3640; chelating agents, such as EDTA; and sodium sulfide (HNa2S). For example, the novel treatment composition may contain 0.01 to 6 wt% of one or more organic acids, such as fulvic acid and humic acid, which the inventors have found to be very effective in preventing the precipitation of substances formed by treated H2S and other contaminants from the treated fluid. The use of such organic acids is further discussed in PCT / US2018 / 064015 and U.S. Patent No. 10,913,911 relative to the inventors' previously proposed water-based treatment compositions, but the discussion also applies to the novel treatment composition.

[0076] The treatment composition may contain 0.01 to 6 wt% of a chelating agent, such as ethylenediaminetetraacetic acid (EDTA). EDTA particularly increases the efficiency of hydroxide compounds in treating H2S and helps to make H2S treatment irreversible using fresh treatment. However, if the fluid being treated contains a large amount of one or more salts, EDTA at higher levels in the range discussed can react with said one or more salts to form a gel, which precipitates out of the fluid being treated. This is typically undesirable because the gel can cause blockages in the lines through which the fluid flows and will have to be removed. Furthermore, if the gel remains in the lines or other devices through which the fluid flows or is transported for an extended period of time, the gel may solidify, making gel removal even more difficult.

[0077] The treatment composition may also contain a small amount (e.g., 0.1 at least 5 wt%, preferably less than 2 wt%) of a polymer that may help prevent any salts in the treated fluid from precipitating out. Examples of such polymers include commercially available anionic polymers identified by product code 3640. The inventors believe that such polymers and other similar polymers can encapsulate salts in the treated fluid, and this prevents or helps prevent the precipitation of salts and other contaminants from the treated fluid.

[0078] The treatment composition may also contain 0.1 to 8.0 wt% sodium sulfide (HNa2S) or its hydrate Na2S·9H2O, both of which are colorless solids. While adding sodium sulfide for the purpose of reducing the sulfur content of contaminated fluids may seem counterintuitive, the inventors have found that adding sodium sulfide or its hydrate to the treatment composition can help reduce the total sulfur content in a variety of contaminated fluids, including liquids and gases treated with the treatment composition. In particular, the inventors have found that in the treatment composition, sodium sulfide promotes a reaction with sulfur and sulfur-containing compounds, thereby converting most of the sulfur into sulfur dioxide (SO2), which is typically released as a gas from the treated fluid at standard temperature and standard pressure (STP). Although the inclusion of sodium sulfide in the treatment composition may also result in the formation and release of relatively small amounts of sulfur-containing precipitates, which the inventors have identified as C using gas chromatography. 18 H8N4O5S2. SO2 is irritating to humans and will be captured and / or further processed, and, if necessary and as required, the precipitate will be removed from pipelines or other structures containing the treated fluid or in which the treated fluid flows. Sodium sulfide and its hydrates are readily soluble in water (e.g., at a concentration of 15-25 wt%) and in hydrocarbon-based liquids used in the treatment compositions of this invention.

[0079] The new treatment composition may contain small amounts (e.g., less than 1 wt%) of surfactants (such as sodium dodecyl sulfate) and buffers (such as potassium carbonate).

[0080] By using a hydrocarbon-based liquid as the base solvent for the new treatment composition, the vapor pressure of the treatment composition at STP will be greater than that of the inventors' previously proposed water-based treatment compositions at STP. Accordingly, more of the treatment composition will be in the vapor phase and can have correspondingly greater contact with contaminants, including H2S and CO2, which tend to be in the vapor phase at STP, even when H2S and CO2 are in a fluid mixture containing both liquid and gaseous fluids. Therefore, the new composition can more effectively and efficiently treat contaminants, including H2S and CO2, that tend to be in the gaseous or vapor phase at STP. When contaminated fluids (such as crude oil, produced water, and natural gas) are extracted from underground through wells, the fluid may be at a temperature of 90°F to 120°F when it reaches the Earth's surface, but as the fluid flows through pipelines to separators, refineries, or other destinations, it will cool to the ambient temperature around the pipeline, making it important that the treatment composition can effectively treat contaminants, including H2S and CO2, at STP. The novel treatment composition effectively treats H2S, CO2, and other contaminants in contaminated fluids under STP conditions, but one or more treatment reactions in the treatment methods involving the treatment composition may proceed faster at elevated temperatures.

[0081] Many types of hydrocarbon-based liquids can be used in the novel treatment composition, including one or more relatively light liquids, including alcohols, toluene, hexane, xylene, and other hydrocarbon-based liquids with vapor pressures greater than water, as well as mixtures of these liquids, provided that one or more hydroxide compounds and other possible components of the treatment composition can be dissolved or dispersed therein. Alcohols are suitable as hydrocarbon liquids because they are polar, making other components of the composition generally soluble and / or miscible therein. Lighter alcohols (including methanol (CH3OH), ethanol (C2H5OH), and n-propanol (C3H8O)) may be more suitable due to lower cost and / or higher vapor pressure. Toluene, hexane, xylene, and other such liquids, which are commonly used as solvents, can also be used as hydrocarbon liquids because they have relatively high vapor pressures, which is desirable because the vapors may contain more of one or more reactive hydroxide compounds, in which they can react better with gaseous pollutants, including H2S and CO2. The hydroxide compounds and other possible components of the treatment composition can also be dissolved or dispersed in these liquids. Importantly, in addition to the one or more hydrocarbon liquids, the components of the composition should be soluble, dispersible and / or miscible in one or more hydrocarbon-based liquids used in the treatment composition, because when used in the treatment method of the present invention, there should be no precipitates or the like from the treatment composition itself.

[0082] Generally, all hydroxide compounds can be used, provided they are soluble or dispersed in one or more hydrocarbon liquids in all compositions. However, some hydroxide compounds, such as NaOH and KOH, are less expensive and, if used, can make the composition and the treatment method using the composition more economically advantageous. If the treatment composition is used to treat fluids containing high levels of salts (including NaCl), such as crude oil and / or natural gas, where the salts are typically dissolved in any water contained in the fluid, it may be desirable to use very little or no NaOH to help prevent any salts from precipitating from the treated fluid. The treatment composition may contain 30-50 wt% of one or more hydroxide compounds in total.

[0083] The inclusion of water and hydrocarbon-based liquids in the treatment compositions of the present invention facilitates the dissolution or dispersion of hydroxide compounds and other possible components into the new composition. However, if it is desired that the treatment composition contain very little or no water, the one or more hydroxide compounds and other possible components can be directly dissolved and / or dispersed in one or more alcohols or other hydrocarbon-based liquids used as the solvent / base of the treatment composition. For example, the one or more hydroxide compounds can be in the form of hydrates, such as KOH hydrate and NaOH hydrate, which are solid materials, while organic acids (such as fulvic acid and humic acid), chelating agents (such as EDTA), and sodium sulfide or their hydrates can also be in solid or powder form, all of which readily dissolve in alcohols and other hydrocarbon-based liquids discussed for use in the new treatment compositions. Polymers such as 3640 polymers readily disperse in alcohols. By directly dissolving and / or dispersing one or more hydroxide compounds and other components in one or more alcohols and / or other hydrocarbon liquids used as the base of the treatment composition, the water content in the treatment composition can be kept to a minimum, such as 5 wt% or less. The lower the water content in the treatment composition, the more effectively and / or efficiently it can treat contaminated fluids.

[0084] However, the inventors have discovered that even when the new treatment composition contains a significant amount of water, such as up to about 50 wt%, and a hydrocarbon-based liquid, the treatment composition can still very effectively treat H2S, CO2, and other contaminants in a variety of contaminated fluids and mixtures of contaminated fluids. For example, if the one or more hydroxide compounds and other possible components (including organic acids such as fulvic acid and humic acid, chelating agents such as EDTA, sodium sulfide, etc.) are initially dissolved or dispersed in water, then one or more aqueous solutions containing these materials can be mixed with one or more alcohols and / or other hydrocarbon liquids used as the base of the treatment composition, and the resulting treatment composition can still very effectively and efficiently treat H2S, CO2, and other contaminants in a variety of contaminated fluids and mixtures of fluids, as well as prevent the formation and release of precipitates from the treated fluid. When the treatment composition contains water, for example to promote the dissolution or dispersion of hydroxide compounds and other components into the treatment composition, the water content can be reduced or minimized by dissolving or dispersing one or more hydroxide compounds and other components in water at a relatively high concentration. Hydroxide compositions (such as NaOH and KOH) can be dissolved in water at high concentrations of 35-55 wt%, while organic acids (such as fulvic acid and humic acid) and chelating agents (such as EDTA) can also be dissolved in water at concentrations above 40 wt%.

[0085] The treatment method according to the inventor's third discovery may involve an alkaline hydrocarbon-based liquid treatment composition with a pH of about 14, through which contaminated gas is passed for a contact time of 0.5-10 seconds (preferably at least 1.5 seconds). When the pH of the hydrocarbon-based liquid treatment composition drops from an initial value of 14 to a value between 9 and 10, it can be considered depleted and should be replaced or re-enhanced.

[0086] A crucial aspect of the treatment composition according to the third embodiment is that it is based on hydrocarbon liquids rather than water, such as the treatment compositions previously proposed by the inventors and discussed in PCT / US2018 / 064015 and '911 patents. Alcohols such as methanol, ethanol, and isopropanol have much higher vapor pressures than water, thus this new treatment composition will have a much higher vapor pressure than previously proposed treatment compositions, and based on this, gaseous contaminants in the treated gas can be treated more efficiently. For example, due to its much higher vapor pressure, a larger amount of the treatment composition vapor will accumulate in the top space above the liquid treatment composition in the reaction chamber, especially if the treatment composition is at a standard temperature and pressure of about 25°C and one atmosphere. Such composition vapor will contain some alkaline substances, such as one or more hydroxide compounds, and these substances will continue to react with and treat any gaseous contaminants remaining in the gas after the gas has passed through the liquid treatment composition, thereby achieving complete treatment of polluting gases such as H2S and CO2. Furthermore, the vapor and gas mix very thoroughly, much better than the mixing of gas and liquid, resulting in greater contact between gaseous contaminants and the vapor of the treatment composition in the headspace of the reaction chamber. This leads to more efficient treatment of contaminants and extends the usable life of the alcohol-based treatment composition in treating contaminants in gases. This contact between gaseous contaminants and the vapor of the treatment composition differs from the contact between gaseous contaminants and liquids sprayed or injected into the gas in the form of atomized fine droplets. The contact between gaseous contaminants and the vapor of the treatment composition is much greater than the contact between gaseous contaminants and fine atomized droplets because vapor molecules are much smaller than fine droplets, and this results in more effective and efficient treatment of contaminants. Preferably, the alcohol-based treatment composition will contain less than 1% by volume of water.

[0087] To minimize the amount of water contained in hydrocarbon-based liquid treatment compositions, the inventors have determined that suitable types of one or more hydroxide compounds that can be added to the alcohol base of the composition are hydrated hydroxide compounds, such as KOH hydrate, LiOH hydrate, etc. These hydrated hydroxide compounds are typically in solid form, such as flakes, readily soluble in hydrocarbon-based liquids containing alcohols (such as methanol, ethanol, and isopropanol), and relatively large amounts of these compounds can dissolve in such alcohols without forming precipitates of the compound in the alcohol-based composition, which helps to increase the usable life of the treatment composition. For example, the inventors have determined that if potassium hydroxide monohydrate (H3KO2) and methanol are used to prepare a treatment composition with a pH of 14, this can be achieved by adding at least 333 g H3KO2 / L methanol, but substantially more H3KO2 can be added, for example, up to at least 800 g H3KO2 / L methanol, without any precipitation from the composition. This corresponds to a H3KO2 concentration of approximately 4.5 to 11.25 moles in the treatment composition.

[0088] The novel treatment composition may contain KOH and methanol, and the KOH may be dissolved or dispersed in the methanol to produce methoxide ions (CH3O4). - The methoxide ion is even larger than OH-. - A stronger base, which is the reactive ion in the water-based treatment compositions discussed in PCT / US2018 / 064015 and '911 patents. Potassium methoxide can react with H2S according to the following equation:

[0089] CH3KO+H2S→K2S+CH3OH.....(4).

[0090] Similarly, potassium sulfide (K2S) can be retained in the treatment composition without forming any precipitate due to the presence of organic acids such as fulvic acid and humic acid. Furthermore, hydroxides in methanol-based treatment compositions can react with CO2 to produce potassium carbonate according to equations (2) and (3) discussed herein, but such compounds will also be retained in the treatment composition without forming carbonate crystal precipitates due to the presence of organic acids such as fulvic acid and humic acid, provided that the treatment composition does not become oversaturated with carbonate compounds. This is ensured by considering the treatment composition depleted when the pH of the treatment composition drops to between 10 and 9 and replacing it with a fresh treatment composition at pH 14. As an alternative formulation to a new treatment composition comprising methanol, KOH, and water, the composition can be prepared by first dissolving one or more appropriate amounts of one or more hydroxide compounds in water to form an aqueous hydroxide solution, and then combining an appropriate volume of such solution with methanol. For example, 15%–50% by volume of methanol can be combined with 50%–85% by volume of an aqueous solution containing 35–55 wt% KOH. This exemplary treatment composition also has a pH of about 14.

[0091] There is a type called Rectisol TM The method is a conventional approach that uses methanol to absorb H2S. Rectisol TM The method uses cooled methanol (cooled to at least below the freezing point of water and typically much lower) for absorption, thereby removing H2S based on the fact that H2S is more soluble than other gases (such as CO2). This is quite different from the inventors' treatment method according to a third embodiment of the invention, in which the treatment can be carried out at standard temperature and pressure, and in which the methanol-based treatment composition not only adsorbs or dissolves H2S, but also treats H2S by reacting with methanol salt ions.

[0092] NaOH or NaOH hydrate can also be used as a hydroxide compound in alcohol-based treatment compositions; however, this is not preferred because the formation and release of any precipitates and scale from the treated natural gas and / or from the alcohol-based treatment solution is undesirable, as precipitates and scale tend to accumulate rapidly and clog parts of the treatment system and pipelines receiving the treated gas. Na is a component of NaCl salts, and salts are common contaminants that tend to precipitate from the treated gas. NH4OH is a suitable hydroxide compound to include in alcohol-based treatment compositions, but should not be the only hydroxide compound used, as it can release ammonia (NH3) into the treated gas, and governments limit the NH3 content in gases; for example, natural gas should contain no more than 14 ppm of NH3. Therefore, for example, a larger amount of KOH or LiOH can be used in the treatment composition along with a smaller amount of NH4OH. NH4OH not only works effectively in treating contaminants in the composition when the gas is bubbled through it, but also advantageously increases the vapor pressure of the composition, allowing contaminants remaining in the treated gas after passing through the composition to be further treated by NH4OH vapor in the headspace above the composition in the reactor. Of course, NH3 may also be one of the main contaminants in the gas that must be removed or treated, and for such contaminated gases, the use of NH4OH would likely be inappropriate.

[0093] Treatment methods involving novel treatment compositions may involve contacting contaminated gas with a hydrocarbon-based liquid treatment solution. For example, a quantity of the treatment composition may be arranged in a bubble column or other reaction chamber at ambient temperature and pressure, and the gas may be bubbled or otherwise passed through the composition, allowing for a suitable contact time between the gas and liquid composition, e.g., 0.5 to 10 seconds, preferably at least 1.5 seconds. A top space exists above the treatment composition in the bubble column or other reaction chamber, in which the vapor of the treatment composition and the gas being treated will come into contact with each other to further, and in most cases, completely treat any contaminants that may remain in the gas, such as H2S and CO2, before the treated gas is discharged from the reaction chamber. Similarly, when the pH of the hydrocarbon-based liquid treatment composition drops from an initial value of 14 to a value between 9 and 10, it is considered depleted and should be replaced or re-enhanced. Reaction chambers (such as...) Figure 2The reaction chamber 200 can be used as a bubble column type reaction chamber to contain an alcohol-based treatment composition according to a third embodiment of the invention, wherein a certain volume of the treatment composition, instead of an alkaline water washing solution, will fill about 1 / 2 to 3 / 4 of the space inside the reaction chamber, and the contaminated gas will be bubbled through the treatment composition for a suitable contact time of 0.5 to 10 seconds. However, in treatment methods involving hydrocarbon-based liquid treatment compositions, very little or no precipitate will form and be released.

[0094] The size of the reaction chamber used can depend on the amount of contaminated gas being treated and / or the amount of contaminants contained in the gas that will be treated and removed by an alkaline water washing solution. For example, if a large, continuous volume of contaminated gas, such as from a well at a rate of three million (3) to fifteen (15) million ft, is to be treated in the reaction chamber... 3 For a daily output of natural gas, the reaction chamber could have a diameter of four (4) feet, a height of twenty (20) feet, and a volume of 1880 US gallons, in which the treatment composition could fill 3 / 4 of the volume or 1410 gallons. Based on Stokes' law, the flow of contaminated gas into the bottom of the reaction chamber can be controlled for bubble formation and rise, with a desired liquid contact time, for example, 0.5 to 10 seconds, preferably at least 1.5 seconds. This could involve exhaust nozzles, such as nozzle 206, having a number of small exhaust openings defined therein, and could also involve some type of means for interrupting the gas flow through the reaction chamber, such that the gas cannot flow uninterruptedly through the wash solution in the form of a stream or large bubbles, and thus will have a much larger surface area to react with the treatment composition. Such interruption means could involve filling the reaction chamber or a portion thereof with a fine non-reactive medium (e.g., stainless steel wool, peagravel, perforated plate, etc.) through which the natural gas will pass when it flows through the wash solution.

[0095] Another type of treatment method according to the invention for treating contaminated gases using an alcohol-based treatment composition according to a third embodiment is called a pressure swing adsorption (PSA) method. According to an exemplary PSA method, an alcohol-based treatment composition is partially filled into a horizontally arranged reaction chamber such that a large headspace exists above the treatment composition in the reaction chamber. A volume of contaminated gas is introduced into the reaction chamber at an elevated pressure (e.g., about 100-120 psi). The reaction chamber is then closed for a short period, e.g., about 15-120 seconds, allowing the vapor of the treatment composition to react with the contaminants in the gas. The treated gas is then released from the reaction chamber. These steps can be repeated with an additional volume of contaminated gas, and the treatment composition is considered depleted and should be replaced when the pH drops to between 9 and 10. Such PSA methods are generally more efficient at completely removing all contaminants from gases compared to treatment methods involving continuously operated bubble column reaction chambers, as discussed herein, but require more control and may be less cost-effective than treatment methods involving continuously operated bubble column reaction chambers.

[0096] Figure 3 A schematic diagram of an exemplary PSA reaction chamber 300 that can be used according to a third embodiment of the present invention is shown. Figure 3 As shown, a certain amount of treatment composition 302 with a pH of about 14 can be partially filled into the reaction chamber, filling the lower half of the reaction chamber, while the upper half of the reaction chamber defines a top space 304 above the treatment composition 302. Similarly, the size of the reaction chamber 300 can depend on the amount of contaminated gas being treated and / or the amount of contaminants contained in the gas that will be treated and removed by an alkaline water washing solution. For example, if a continuous large volume of contaminated gas, such as from a well at three (3) million to fifteen (15) million ft, is to be treated in the reaction chamber... 3For a daily output of natural gas, the reaction chamber can have a diameter of four (4) feet, a length of twenty (20) feet, and a volume of 1880 US gallons, in which solution 302 can fill 1 / 2 to 3 / 4 of the volume or 940-1410 gallons. For this treatment method, the treatment of contaminants occurs primarily in the headspace 304, where the vapor of the treatment composition mixes with the gas being treated 305; therefore, it is appropriate for the headspace to occupy 1 / 2 or more of the reaction chamber volume. Based on Stokes' law, the flow of contaminated gas 305 into the bottom of the reaction chamber can be controlled for bubble formation and rise, with a desired liquid contact time, for example, 0.5 to 10 seconds, preferably at least 1.5 seconds. This may involve an exhaust nozzle 306 defined therein with numerous small exhaust openings, and may also involve some type of means for interrupting the gas flow through the treatment composition in the reaction chamber, such as the interruption means discussed herein. Alternatively, gas 305 can be introduced directly into the headspace 304 without bubbling through the treatment composition.

[0097] As the gas passes through the treatment composition, some contaminants are removed as discussed above, and the contaminants are then further treated by the treatment composition vapor in the top space 304, after which the treated gas is discharged from the upper part 310 of the reaction chamber. A hydrocarbon-based liquid treatment composition can be introduced into the reaction chamber through inlet 312. A level sensor 315 can be used to set and control the level of the treatment composition 302 in the reaction chamber, and a sensor 316 can be used to monitor the pH of the composition 302. As the contaminated gas stream is treated in the reaction chamber, alkaline chemicals in the solution (such as one or more hydroxide compounds) will react with the contaminants in the gas, and the pH of the composition will gradually decrease. Although little or no precipitate will form or be released into the treatment composition due to the presence of organic acids such as fulvic acid and humic acid in the composition, once the pH of the solution drops to between 10 and 9, the treatment composition is considered depleted according to the treatment method, and the depleted composition can be discharged, for example, through the waste discharge outlet 318 at the bottom of the reaction chamber. Another volume of treatment composition can then be introduced into the reaction chamber, and the treatment method can be continued by repeating these steps whenever desired. The processing method can be automated using a controller 320 (such as a programmed ECU), which receives input from sensors 315, 316 and controls the flow of solution and gas into and out of reaction chamber 300 by opening and closing various solenoid valves associated with corresponding inlets and outlets of reaction chamber 300. Alcohols in the depleted processing composition can be recovered and reused by distillation or other suitable methods. Alternatively, to some extent, some unreacted one or more hydroxide compounds and / or one or more organic acids remain in the depleted processing composition, which can be added to produced water extracted from the ground along with crude oil and natural gas to reduce the H2S and other contaminants in the produced water before it is injected back into the ground. Reducing the amount of H2S and other contaminants in the produced water before it is injected back into the ground may have commercial value.

[0098] The treatment compositions and methods according to a third exemplary embodiment of the present invention have proven to efficiently and cost-effectively remove contaminants such as H2S, CO2, and metals from gases including natural gas, combustion gases from fossil fuels typically having high concentrations of CO2 and SO2, etc. Gases (including natural gas) treated using the alcohol treatment compositions and methods are very clean, allowing consumers to use them directly and safely without further treatment. Therefore, for example, if the treatment method is carried out at or near the well where the gas is produced, the gas can be directly compressed into LPG at the same location using suitable equipment, and as another benefit of the treatment method, once compressed into LPG, the transportation and storage costs of the treated natural gas can be significantly reduced.

[0099] Furthermore, the inventors have determined that the treatment compositions and methods according to the inventors' third discovery are particularly effective and efficient in completely treating contaminants in gases, such as H2S, CO2, and metals, when used in combination with an alkaline water scrubbing solution according to the second exemplary embodiment of the invention discussed herein. Used in series, the treatment compositions / solutions and methods according to the second and third exemplary embodiments have proven highly suitable and cost-effective for treating contaminated gases (including natural gas) in a continuous manner at high flow rates, regardless of the content of H2S, CO2, and one or more other contaminants in the contaminated gas. The alkaline water scrubbing solution according to the second embodiment is highly effective at removing all salts and many other contaminants from gases at a relatively low cost. Although this may require periodic or regular replacement of the alkaline water scrubbing solution when it becomes depleted, or re-intensification of the alkaline water scrubbing solution on a continuous basis, the alkaline water scrubbing solution primarily contains water and alkaline substances, such as one or more relatively inexpensive hydroxide compounds. On the other hand, while the hydrocarbon-based treatment composition used in the treatment method according to the third embodiment may have a significantly higher cost per unit volume than an alkaline water washing solution, if the two treatment methods are carried out in series, the amount of contaminants removed using such an alcohol-based treatment composition and method is relatively small compared to the amount of contaminants initially removed by the alkaline water washing solution. Compared to alkaline water washing solutions, which help maintain the practicality and cost-effectiveness of the treatment method, when the treatment methods according to the second and third embodiments are carried out in series, the hydrocarbon-based treatment composition can be used to remove all or most of the remaining contaminants from a much larger volume of contaminated gas before the hydrocarbon-based treatment composition is exhausted and replaced or re-intensified.

[0100] For example, the inventors have determined that for quantities between five million and ten million ft 3A continuous flow of natural gas containing approximately 30,000 ppm of each of H2S and CO2, as well as larger amounts of other sulfur-based contaminants (including thiols and thiophenes), BTEX compounds, water vapor, salts, and metals, can be adequately treated using two bubble column reactors (one for an alkaline water wash and the other for an alcohol-based treatment composition) to remove and / or treat all contaminants to levels as low as safe and acceptable. Each such reactor may be four (4) feet in diameter and twenty (20) feet high, one containing approximately 1,410 gallons of alkaline water wash and the other containing approximately 1,410 gallons of an alcohol-based treatment composition, which will fill the lower fifteen (15) feet of each reactor, leaving five (5) feet of top space. Similarly, when the pH drops from an initial value of about 11 to a value between 9 and 8, the alkaline washing solution is considered depleted and should be replaced, typically about once per hour, and when the pH drops from an initial value of 14 to a value between 10 and 9, the hydrocarbon-based treatment solution is considered depleted and should be replaced, which under the conditions discussed may be about every eight (8) to ten (10) hours.

[0101] In summary, the combination of treatment compositions and methods according to the second and third embodiments of the present invention is highly effective and efficient in removing and / or treating contaminants from gases, even highly polluted gases, in a practical and cost-effective manner. Importantly, this combination of the inventors' second and third discoveries can be successfully used to treat even currently unexploited or closed natural gas reserves worldwide, for which no previously known cost-effective treatment methods exist. Furthermore, if the inventors' first discovery was initially used to treat mixtures of crude oil and natural gas, this would add further benefits and cost-efficiency to the treatment of these fluids. Moreover, the combination of treatment compositions and methods according to the inventors' second and third discoveries can be effectively and economically used for carbon sequestration / mitigation strategies. For example, if the contaminated gas contains 80,000 ppm or more CO2 / CO, such as a volume of 13 million ft... 3 The combined treatment methods discovered in the second and third findings can remove 57,058 kg or 63 tons of CO2 per day from natural gas streams or fossil fuel combustion gases from power plants, which would otherwise be released into the atmosphere. Similarly, alkaline water scrubbing solutions can remove most of the CO2 themselves and can be used accordingly for carbon sequestration / mitigation strategies and for obtaining valuable carbon credits.

[0102] Contaminated natural materials treated by a combination of treatment compositions and methods according to the second and third embodiments Examples of Qi

[0103] The inventors have treated highly contaminated natural gas from wells using the treatment solutions / compositions and methods according to the second and third exemplary embodiments of the invention discussed herein. The natural gas initially contained 60,000 ppm H2S and approximately 160,000 ppm CO2, as well as several other contaminants, including water, salts, other sulfur-containing compounds (such as thiols and thiophenes), BTEX chemicals, and metals. After treatment according to the second and third exemplary embodiments of the invention discussed herein, the treated natural gas was particularly free of contaminants and readily marketable and safe for consumer use, as confirmed by gas chromatography (GC) analysis of the treated gas. As reflected in the GC analysis results, the original gas had 58 peaks, reflecting the desired levels of natural gas and various contaminants. After treatment with an alkaline water wash solution according to the second embodiment of the invention (which treats and / or removes most of the contaminants), the treated gas had 61 peaks, an increase from the original gas's 58 peaks, indicating that some components and / or contaminants in the original gas were masked by other components and revealed by treatment with the alkaline water wash solution. Finally, after further treatment using the alcohol-based treatment composition and method according to the third embodiment of the invention, the treated gas has only 17 peaks, all of which are substantially all of the desired components of natural gas, indicating that the treated gas is extremely clean and safe to use. Similarly, such clean gases can be sold for direct and safe use by consumers and can be compressed into LPG to further reduce costs associated with the storage and transportation of clean gases.

[0104] Cost-effective processing strategies for crude oil and natural gas from wells

[0105] While the combination of treatment solutions / compositions and treatment methods according to the second and third exemplary embodiments of the invention discussed herein is highly efficient and economical for treating contaminated gases (such as natural gas as discussed above), this would add further benefits and cost-efficiencies for the treatment of these fluids if the inventors’ first discovery had been initially used to treat mixtures of crude oil and natural gas. (Refer to this document) Figure 4This is a schematic diagram illustrating how different embodiments of the invention can be used together to efficiently treat contaminants in mixed fluid flows, such as flows of crude oil and natural gas from a well. As shown, crude natural gas, crude oil, and produced water (SWD) are extracted from well 1 and flow into a three-way separator 2, which separates these materials into three different output streams. The natural gas and crude oil streams can be recombined to flow together in a single line 4, while the produced water SWD can be treated by being injected back underground. Then, a suitable dose of a first treatment composition (such as any of those previously proposed by the inventors as discussed in PCT / US2018 / 064015 and '911 patents) can be injected from composition source 6 into the mixed flow of oil and gas in line 4 using pump 5. After the mixed flow of oil and gas, along with the treatment composition flow, has traveled along pipeline 4 for a distance or time (e.g., one mile or more, or 15-120 minutes), the crude oil and natural gas are separated into two distinct streams. The crude oil enters the treated oil tank group 9 or other locations, while the natural gas continues its journey for further treatment and removal of contaminants. At this point, the contaminants in the crude oil (including H2S and CO2) have been adequately or completely treated by the first treatment composition injected into pipeline 4. Although the treated contaminants remain in the crude oil without precipitating due to the organic acids (such as fulvic acid and humic acid) in the first treatment composition, such treated crude oil is readily accepted by the refinery and pipelines flowing to the refinery.

[0106] Some contaminants in the natural gas stream are partially removed and / or treated by the first treatment composition injected into pipeline 4, but may still contain significant amounts of contaminants, including salts, H2S, and CO2. The natural gas is then treated in an alkaline water washing solution contained in a first reaction chamber 7 (such as bubble column #1) according to a second exemplary embodiment of the invention, whereby most of the contaminants in the natural gas are treated and / or removed by the alkaline water washing solution. Finally, according to a third exemplary embodiment of the invention, the natural gas is treated using a second alcohol-based treatment composition in a second reaction chamber 8 (such as bubble column #2), whereby all or substantially all contaminants remaining in the natural gas (including H2S and CO2) are treated to levels as low as safe and government-acceptable, and most contaminants are treated to levels as low as undetectable, although the treated contaminants remain in the natural gas without precipitating out due to organic acids (such as fulvic acid and humic acid) in the alcohol-based treatment composition. At this point, the treated natural gas discharged from the second reaction chamber is perfectly safe for direct consumer use and / or compression into LPG.

[0107] The above description is provided merely for clarity and should not be construed as limiting anything unnecessarily, as modifications within the scope of this invention will be obvious to those skilled in the art and are covered by the appended claims.

Claims

1. A method for treating contaminants in a mixture of at least one liquid fluid and at least one gaseous fluid, the method comprising the following steps: A liquid treatment composition is prepared, the liquid treatment composition comprising at least 80 vol% of an aqueous solution, the aqueous solution comprising at least one hydroxide compound at a total concentration of 35-55 wt% of the liquid treatment composition and at least one organic acid at a total concentration of 0.1-5 wt% of the liquid treatment composition, the organic acid being selected from the group consisting of fulvic acid and humic acid; a certain dose of the liquid treatment composition is added to a stream of a mixture of contaminated fluid comprising a liquid portion and a gaseous portion, such that the liquid treatment composition and the liquid and gaseous portions of the mixture of contaminated fluid are mixed; The liquid treatment composition is allowed to react with the mixture of the contaminated fluid for at least 10 minutes, wherein the pH of the liquid treatment composition is at least 13.0, and the aqueous solution contains at least one of sodium hydroxide and potassium hydroxide. The contaminated fluid mixture is in the form of a flowing fluid mixture stream; and The addition step includes adding at least one dose of the liquid treatment composition to the fluid mixture stream to bring the pH of the mixture of contaminated fluids in a local bag, wherein the liquid treatment composition has been added, to about 10 but not more than 10.5, wherein the liquid treatment composition is added to the fluid mixture stream in the local bag, such that the fluid mixture stream in which the liquid treatment composition has been added flows through a pipeline to allow the liquid treatment composition to treat contaminants in the fluid mixture stream; The liquid treatment composition is added to the fluid mixture stream at multiple locations.

2. The processing method according to claim 1, wherein the fluid mixture stream contains a liquid water component, a liquid hydrocarbon component, and a natural gas component, and the processing method further comprises the following steps: After the step of flowing the fluid mixture stream, the liquid water component is separated from the liquid hydrocarbon and natural gas components of the treated fluid mixture stream; The liquid hydrocarbon components and the natural gas components are combined into a new fluid mixture flow; Add at least one additional dose of the liquid treatment composition to the new fluid mixture stream; And allows the liquid treatment composition to further treat contaminants in the new fluid mixture stream.

3. The processing method according to claim 2, wherein the liquid concentration is based on 200-1000 gallons / hour and 416,667-2,083,333 ft. 3 The volume of the gas fluid mixture stream per hour, and the total dosage of at least one liquid treatment composition added to the fluid mixture stream and the new fluid mixture stream is 2 to 10 gallons of liquid treatment composition added per hour.

4. The processing method according to claim 1, wherein the fluid mixture initially contains more than 1,000 ppm of each of H2S and CO2.

5. The processing method according to claim 1, wherein the mixture of the contaminated fluid comprises crude oil and natural gas.

6. The treatment method according to claim 1, wherein water and the at least one hydroxide compound account for at least 90 wt% of the liquid treatment composition.

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