EA041530B1 - COMPOSITIONS AND METHODS FOR REMOVING HYDROGEN SULFIDE AND OTHER CONTAMINANTS FROM HYDROCARBON-BASED LIQUIDS AND AQUEOUS SOLUTIONS - Google Patents

Description

Cross-references to related applications

This application claims priority under U.S. Provisional Applications 62/661289, filed April 23, 2018, and 62/702960, filed July 25, 2018, and under PCT/US 2018 International Application /050913, filed September 13, 2018, which claims priority under U.S. Provisional Application Serial Number 62/539699, filed August 1, 2017. The contents of these priority applications are incorporated herein by reference in their entirety.

Technical field

The present invention relates to novel treatment fluids and methods of using them to treat and remove sulfur-containing compounds, predominantly including hydrogen sulfide (H ₂ S), and other contaminants from hydrocarbon or oil-based fluids and contaminated aqueous solutions, substantially without precipitation. , solid deposits, etc. More specifically, the present invention relates to such treatment solutions and methods in which treatment solutions are added to hydrocarbon or petroleum based fluids or contaminated aqueous solutions in a controlled and efficient manner that safely and effectively reduces contaminant concentrations to acceptable levels. substantially free of precipitation, solid deposits, etc. and without other significant adverse effects on hydrocarbon or petroleum based fluids or contaminated aqueous solutions.

Prior Art

Sulfur compounds, including hydrogen sulfide (H ₂ S), have long been recognized as undesirable contaminants in hydrocarbon or petroleum-based fluids such as crude oil and liquefied petroleum gas (LPG; from English: liquified petroleum gas), as well as in contaminated aqueous solutions, such as solutions extracted from underground formations together with crude crude oil, natural gas, etc., and aqueous solutions may also contain significant concentrations of salts, and they can be considered brines. In the context of the present invention, the term hydrocarbon-based fluid is used to refer to any hydrocarbon-based fluid, including petroleum-based fluids. Examples of hydrocarbon based fluids that can be treated with the treatment solutions and treatment methods of the present invention include fluids containing CH ₉ to CH ₃₂ molecules. H2S is a particularly undesirable contaminant because it is highly toxic, corrosive, etc., and in general, petroleum-based fluids such as crude oil must contain less than 5 ppm H2S to be suitable for refining. or other processing. Although H2S content in hydrocarbon-based fluids can range from a few ppm to more than 100,000 ppm, crude oil recovered from a reservoir typically contains <40,000 ppm H2S, most commonly < 2000 ppm H2S, and is typically slightly acidic with a pH ranging from about 5 to about 6. H2S can be present in several forms, including H2S dissolved in liquid, H2S in the form of mercaptan sulfur, and H2S contained in vapors, but most of it is typically present in the form of H2S in the vapor, in particular in high concentrations, and the release of _H2S in vapor or gaseous form is particularly toxic and hazardous.

Typically, most of the H2S contained in a hydrocarbon-based fluid is in gaseous or vapor form. Gaseous H2S has much greater solubility in hydrocarbon-based fluids than in water, and at the high pressures at which crude oil is underground, crude oil can contain thousands to tens of thousands ppm H2S. However, if the oil is moved to ambient pressure or atmospheric pressure, most of the H2S gas it contains can be released from the crude oil by Henry's law, and so it becomes necessary to remove the H2S and prevent it from being released. The amount of soluble and gaseous H2S that can be contained in aqueous solutions is less than the amount that can be contained in hydrocarbon-based fluids, however, it can still be present in hundreds and thousands of ppm, and contaminated aqueous solutions in typically contain <1000 ppm H2S. In general, H2S is an acidic compound, crude oil recovered from the reservoir and containing a characteristic amount of H2S, for example - <2000 ppm, which is predominantly in the form of a gas dissolved in crude oil, has a moderately acidic pH ranging from about 5 to about 5.5. Gaseous H2S does not exist in solution at pH values greater than about 7.

There are many known methods for removing sulfur compounds, including H ₂ S, from crude oil and other fluids. For example, M. N. Sharak et al., Removal of Hydrogen Sulfide from Hydrocarbon Liquids Using a Caustic Solution, Energy Sources, Part A: Recovery, Utilization, and Environmental Effects, 37:791-798, 2015, discusses that : known methods include methods using amines, including treatment with monoethanolamine (MEA; from English: monoethanolamine), triazine, etc., methods using alkaline material; methods using iron oxide, zinc oxide, molecular sieve, potassium hydroxide, and a hydrodesulfurization method; amine treatment is usually the most cost-effective choice for gas desulfurization if it contains

- 1 041530 significant amounts of acid gases are present; hydrogen sulfide removal using sodium hydroxide solution is a widely used technology in oil refining applications; the alkali washing process is usually used as a preliminary step in the desulfurization of liquid hydrocarbons; and since the solvent used in this process cannot be easily recovered, caustic scrubbers are most often used where small volumes of acid gas (H2S) need to be treated.

H2S reduction is provided by a standard amine treatment process that uses an amine, such as monoethanolamine (MEA) or triazine, to treat H2S in crude oil. However, in the case of a conventional amine treatment, while the H ₂ S may be removed or reduced initially, the sulfur contained in the treated oil may undesirably revert back to H ₂ S over time, especially when the treated oil is oil is heated. Similarly, it is also known that there are bacteria that absorb sulfur compounds and therefore can reduce the content of sulfur-containing contaminants in liquids based on hydrocarbons or in contaminated aqueous solutions. However, as the bacteria die and decompose, sulfur is undesirably released back into hydrocarbon-based fluids or contaminated aqueous solutions.

Conventional alkali treatment used to remove H ₂ S from crude oil involves the use of alkaline aqueous solutions containing up to 20 wt.% NaOH. Water and alkaline material are used to extract H2S from crude oil into a solution where, at high pH, H2S dissociates to form an HS ion, which shifts the equilibrium of H2S gas from oil to water. HS ^- can then react, for example, with sodium to form NaHS (sodium bisulfide) or with S ^-2 to form Na2S (sodium sulfide) plus water as a by-product according to the following equations:

H ₂ S + NaOH NaHS + H ₂ O (1)

NaHS + NaOH -+ Na ₂ S + H ₂ O (2)

In general, conventional caustic treatments are limited to caustic solutions with NaOH concentrations of no more than 20 wt.%, since the conventional methods are designed and intended to partially provide liquid-liquid extraction and partially chemically convert gaseous H2S to solid sulfur-containing compounds. It is generally understood that some water is needed to bring the chemicals into contact with the crude oil or other petroleum based fluid. Large amounts of water contained in standard caustic solutions provide higher levels of liquid-to-liquid extraction. It is also known that the use of excessive amounts of NaOH can spoil the crude oil and damage the metal components used to handle the crude oil, such as pipes and tanks.

In addition, some of the H2S may be converted to sulfur dioxide (SO2) gas, for example by agitation which allows air containing oxygen to enter the oil, and sulfur dioxide may be released from the treated oil-based fluid depending on the pressure the treated oil is under. liquid. In general, hydroxides, including NaOH, are reducing agents and do not produce sulfur dioxide or elemental sulfur unless the treated hydrocarbon fluid is exposed to air. However, if the oil is exposed to air, the sulphide/bisulfide may oxidize to SO2 or to elemental sulphur. All sulfide molecules have the same oxidation state (-2) and NaOH does not change the oxidation state. Similar reactions can occur with other hydroxides included in the treatment solution. For sulfur dioxide (SO2) gas and any other gases that may be released from the treated crude oil, as a safety measure, it may be necessary to provide a certain headspace in a closed tank or other closed container for transporting the treated fluid to ensure that the pressure is not will become too high.

The present inventors have recently proposed another treatment method, described in U.S. Provisional Application No. 62/539699 and International Application No. PCT/US 2018/050913, to effectively remove sulfur compounds, including H2S, from hydrocarbon-based fluids, including crude oil, and from contaminated aqueous solutions, in which an aqueous treatment solution is used, mainly containing a high concentration of one or more hydroxides, such as sodium hydroxide (NaOH) and potassium hydroxide (KOH), the total amount of hydroxides is from 35 to 55 wt. % and preferably it is equal to at least 45 wt.% of the mass of the treatment solution, which effectively reacts with H ₂ S to convert it into non-toxic compounds. Such a treatment solution according to a recent proposal is highly alkaline with a pH value ranging from 13 to 14. In this treatment method, the treatment solution is added to the hydrocarbon-based liquids or to the aqueous solutions to be treated in appropriate doses, which depend on many factors, and the hydroxide (or hydroxides) contained in the solution effectively reduces the content of H ₂ S and other sulfur-containing compounds to acceptable

- 2 041530 levels in relatively short periods of time and without any significant detrimental effects on hydrocarbon or oil based fluids or contaminated aqueous solutions. The recently proposed treatment solution may additionally include one or more other components selected depending on the specific characteristics of the fluids to be treated and other factors associated with the treatment method, however, a high concentration of hydroxide (or hydroxides) and efficient removal of H2S by hydroxides is the main aspect recent application.

A recently proposed treatment method by the present inventors is based on their discovery that standard treatment methods using an aqueous solution containing up to 20 wt.% NaOH are not effective in removing H2S, and that the H2S content in contaminated liquids can be much more effectively reduced using their proposed treatment solution containing a significantly higher total concentration of one or more hydroxides. The treatment method recently proposed by the present inventors is not a flushing type but involves fast chemical reactions that greatly reduce the mass transfer of gas into the aqueous phase. This treatment differs from standard H ₂ S reduction treatments in hydrocarbon-based fluids in that the initial amount of water added with the treatment solution is reduced to substantially the minimum effective amount.

Although it is known that gaseous H2S is more soluble in oil than in water, and that the step limiting the removal of _H2S from crude oil is typically the mass transfer of H2S from the oil phase to the water phase, the present inventors have discovered , What:

1) the liquid-liquid extraction aspect of standard methods is not really as important as the chemical reaction aspect, for example, because the initial solubility of H2S in water, according to Henry's law, is low;

2) the large amounts of water used in standard water treatment solutions also serve the function of diluting the NaOH and transferring H2S from the hydrocarbon liquid to the water without removing the H2S, which is undesirable because it slows down the process needed to produce ionized ^HS- and ^{S2 -} ions, which ensures the transition of a larger amount of H2S contained in oil liquids into solution; And

3) It is more cost-effective and removes H2S effectively, predominantly through a chemical reaction process and to a lesser extent through liquid-liquid extraction.

The inventors of the present invention also discovered that since water is formed in the chemical reactions occurring between hydroxides and H2S, for example, according to equations (1) and (2) above, the formed water, after its occurrence, can easily diffuse through the hydrocarbon-based liquid. because the alkaline solution shows a high tendency to migrate in many hydrocarbon-based fluids, and diffusion can also be accelerated by agitation and/or heating of the treated fluids. Accordingly, they determined that it is not necessary to add a significant amount of water to the treatment process, other than the water contained in the treatment solution, to effectively treat the hydrocarbon-based fluid to remove sulfur compounds, including H2S, and other contaminants. With regard to the discovery 1) of the present inventors, it should be noted that equation (2) above is reversible, so that large amounts of water hydrolyze sodium sulfide (Na ₂ S) back to NaOH and NaHS. In other words, equation (2) in reverse is a hydrolysis reaction.

The treatment method recently proposed by the present inventors may include the use of only one hydroxide, such as sodium hydroxide (NaOH) or potassium hydroxide (KOH), but may also include the use of a combination of hydroxides to more completely react with most or all of the sulfides in liquids based on oil, given that there are over 300 types of sulfur compounds, although hydrogen sulfide (H2S) is by far the main pollutant that needs to be removed. For example, some other types of undesirable sulfur compounds include ethyl mercaptan (CH ₃ CH ₂ SH), dimethyl sulfide (C 2 H 6 S), isobutyl mercaptan (C ₄ H ₁₀ S), and methylthiophene (C ₅ H ₆ S). Sodium hydroxide is very effective when used in a treatment solution because it does not damage petroleum based fluids when used in appropriate amounts and is relatively inexpensive. Potassium hydroxide is more effective than sodium hydroxide in reacting with certain types of sulfides. Accordingly, a treatment method in which potassium hydroxide (KOH) is used together with sodium hydroxide provides a more complete reaction with all sulfides contained in hydrocarbon-based fluids compared to using only a concentrated sodium hydroxide solution.

In an example of a treatment method for purifying contaminated liquids according to a recent proposal by the authors, the treatment solution can be added at a unit dose ranging from 0.25 to 6.0 ml of treatment solution per liter of liquid to be treated, preferably from 1.0 to 5.0 ml of treatment solution per liter of liquid to be treated, corresponding to about 125 to about 3000 ppm of hydroxide (or hydroxides) in the liquid to be treated, based on the indicated concentration of hydroxide (or hydroxides) in the solution. Specified standard

- 3 041530 dose is usually effective in reducing H2S concentrations to safe, tolerable levels. In some hydrocarbon-based fluids, such as crude oil, H2S concentrations of up to 40,000 ppm are possible, although contaminated aqueous solutions typically have a much lower H2S concentration, such as 2,000 ppm or less. If the amount of added treatment solution is less than 0.25 ml/L of the liquid to be treated, a sufficient decrease in the concentration of H2S may not be achieved, and the reaction between the treatment solution and sulfide compounds contained in the hydrocarbon-based liquid may not proceed quickly and/ or effectively. If the H ₂ S concentration is above 40,000 ppm, a corresponding dose increase of the recently proposed treatment solution may be required, which may generally include the possibility of linear scaling. Doses in excess of 6.0 ml of treatment solution per liter of fluid to be treated generally do not result in further reductions in H2S levels in treated fluids in which reaction time is not a critical factor, but may advantageously reduce reaction time required if desired.

Within the specified standard dose range, the most appropriate dose of treatment solution to be added to the contaminated fluid during the treatment process can be determined based on several factors such as the amounts of H ₂ S and other contaminants in the fluid to be treated, others characteristics of the fluid, including its viscosity and density in API degrees (the API term, when used in the context of the present invention, is an abbreviation of the American Petroleum Institute (American Petroleum Institute)), the desired reaction rate or time, the specific desired result, including whether sediment and be removed from the fluid, and whether the treated fluid will be agitated and/or heated during the treatment process. For example, agitation at moderate to high speed to quickly distribute the treatment solution throughout the fluid being treated can reduce the required reaction time by 50%, while for some highly viscous fluids, such as marine fuel (bunker fuel), heating may be required. to ensure proper distribution of the treatment solution. A suitable dose may be substantially linearly scaled with most or all of the various characteristics within a standard dose range.

Advantageously, the newly proposed treatment method is generally cost-effective and efficient, since the amount of treatment solution added lies within the specified standard dosage range, regardless of whether the added amount of treatment solution is the most appropriate dose for the particular liquid to be processing or not. In addition, in some situations it may be desirable to use large amounts of treatment solution, and usually this does not create significant problems or complications, although high doses in general tend to cause precipitation (or precipitation) to form and fall out of the treated fluids, which can be undesirable for the present invention, which tries to avoid precipitation (or precipitation), hard deposits, and the like. from the liquid to be treated over a certain period of time. For example, the present inventors have also determined that if an excessive dose of the newly proposed treatment solution is intentionally added to the liquid to be treated, for example, a dose that is 2-5 times the standard doses indicated above, then this is very likely to cause prolapse removeable contaminants and other contaminants contained in the treated fluid to precipitate from the treated fluid, which may be desirable in some situations. Also, depending on how much excess treatment solution is used relative to the standard dose, various precipitates may form which separate from the treatment liquid so that the result can be controlled in the desired manner; for example, exceeding a standard dose of sodium hydrosulfide, such as Na ₂ S-9H ₂ O, can lead to precipitation from the treated liquid according to reaction (2) above, while at a higher dose, which is 3-5 times the standard dose, precipitation of elemental sulfur from the treated liquid is possible. On the other hand, excessive dosing of hydroxides into the treatment process increases the cost of treatment, but usually does not have significant adverse effects on the processed hydrocarbon-based fluids and aqueous solutions. However, the use of a solution in very large excess, such as 10 times the normal amount, can alkalinize the treated petroleum fluid, which can damage metals such as steel and aluminum used to store and transport treated fluids.

The reaction time in the treatment method recently proposed by the present inventors typically lies in the range of relatively short periods of time, for example, from 15 minutes to 24 hours after adding the treatment solution to the treated liquid at the indicated dose, regardless of whether the liquid to be treated is , a hydrocarbon-based liquid such as crude oil, or a contaminated aqueous solution. During this period of time, the hydroxide (or hydroxides) contained in the solution reduces the concentrations of H2S and other sulfur-containing contaminants to safe, acceptable levels, such as 5 ppm or less, without the formation or

- 4 041530 division of any especially harmful substances. For example, if the treatment solution contains sodium hydroxide (NaOH) as the main hydroxide, for example at least 90% of all hydroxides in the solution, then most of the H2S, for example at least 60%, is converted to sodium bisulfide (NaHS) according to reaction (1) above, which remains dissolved in the treated petroleum fluid and does not create significant problems that may need to be addressed. In addition, a portion of the H ₂ S may be converted to gaseous sulfur dioxide (SO ₂ ), which may be released from the treated oil-based fluid, depending on the pressure the treated fluid is under.

It is highly desirable that the recently proposed treatment method is generally not reversible with respect to the H2S and other sulfur contaminants that have been removed; for example, even if the treated fluid remains heated to 180°F for a period of several days or weeks, any removed sulfur compounds remaining in the treated fluids will not be converted back to H2S. Some conventional H2S removal treatments are undesirably reversible, including the standard amine treatment that uses an amine such as MEA or triazine to treat H2S in crude oil. For example, in the case of a conventional amine treatment process, although H ₂ S may be initially removed or reduced to acceptable levels, the sulfur contained in the treated oil may undesirably convert back to H ₂ S over time, especially if the treated oil is heated. In contrast, if the crude oil, which initially contained about 1000 ppm H2S, was treated by the treatment method using the treatment solution according to the present inventors' recent proposal at a dose of 3 ml/L of oil, and the H2S content was reduced to about 0 ppm and substantially no sulfur precipitated out of the oil, after heating the treated crude oil to a temperature in the range of 180 to 300°F (or 82.2 to 148.9°C), over periods of hours, days or weeks, the resulting oil still contained about 0 ppm H2S. Substantially none of the sulfur compounds contained in the treated liquid were converted back to H ₂ S.

The recently proposed treatment method can conveniently be carried out essentially anywhere where contaminated fluids may be present, such as in exposed reservoirs, in transport tankers or other reservoirs in which fluids are transported, at the wellhead through which fluids are extracted from the formation, in open or closed tanks, in a closed pipeline through which contaminated water or other liquid is transported, etc.

Although known methods for removing sulfur compounds, including H2S, from hydrocarbon-based fluids and aqueous solutions, in particular the methods and treatments according to the recent proposal of the present inventors, are generally effective in removing H2S and other contaminants from liquids, they can still be improved, in particular with regard to the prevention of precipitation (or precipitation), solid deposits, etc. from treated liquids. There remains a need in the art for treatment solutions and treatment methods for removing sulfur compounds, including H2S, from crude oil, other hydrocarbon-based fluids and from contaminated aqueous solutions, and these treatments and treatment methods must be improved with respect to their effectiveness for the complete removal of sulfide compounds and with respect to their effectiveness for the rapid removal of sulfide compounds at a reasonable cost, and essentially without precipitation (or precipitation), solid deposits, and the like. from treated liquids. There is also a need for flexibility in being able to carry out the treatment process at essentially any location, such as directly at the wellhead or in an oil field where crude oil is produced, during the transport of the crude oil to a refinery, or elsewhere.

The essence of the invention

The object of the present invention is to satisfy these needs in the technical field.

According to the first aspect of the present invention, the treatment solution and the treatment method according to the recent proposal of the present inventors are modified to include other components, or they are used in combination with other components, which in general do not participate in the removal of H ₂ S and other contaminants, but help to prevent precipitation, solid deposits, etc. from the treated hydrocarbon-based fluids or contaminated aqueous solutions. over a period of time equal to several hours, days or months. It is especially important that according to the first aspect of the present invention, an appropriate amount of one or more organic acids, such as fulvic acid and humic acid, is added to the liquids to be treated, together with an appropriate dose of the treatment solution according to a recent proposal of the present inventors. The use of an organic acid (or acids) in conjunction with a newly proposed treatment solution not only reduces the concentration of unwanted contaminants, including H2S, in treated fluids in a safe, controlled and effective manner to levels recognized as safe or below, but does so without

- 5 041530 falling sediment (or sediments), solid deposits, etc., even if the liquids are processed, transported and stored for a period of time equal to several hours, days or weeks.

In the treatment method according to the first aspect of the present invention, the sulfide compounds to be removed generally remain in the treated fluids, but in the form of other sulfur compounds that are not toxic or highly hazardous, unlike H2S prior to removal.

In the treatment method according to the first aspect of the present invention, the organic acid (or acids) and the newly proposed treatment solution can be added to the liquid to be treated separately, or alternatively, the organic acid (or acids) can be added to the newly proposed treatment solution to obtain a modified solution for treatment, which is then added to the treated liquid in an appropriate dose. The alternative approach is more convenient from a practical point of view, since the modified treatment solution can be prepared in advance at any convenient location, transported in one container to another location where it is added to the liquid to be treated, and this allows all components to be added to the treated liquid in the form one dose. In addition, the test shows that even when several components are mixed together to form a modified treatment solution and the modified solution is stored for a month or so, there is no noticeable change in the composition of the modified solution and it remains effective for use. in cleanable contaminated liquids based on hydrocarbons and in contaminated aqueous solutions.

In the treatment method according to the first aspect of the present invention, the standard dose of the newly proposed by the present inventors of the treatment solution, that is, the dose lying in the range from 0.25 ml to 6.0 ml/l of the liquid to be treated, preferably in the range from 1.0 ml to 5.0 ml/L of treated fluid is effective in safely and economically reducing H2S and other contaminant concentrations to acceptable levels over a period of time ranging from 15 minutes to 24 hours without causing significant problems with treated fluids, per se. the same as in the recently proposed processing method. The most appropriate dose within the indicated range will again be based on the specific characteristics of the liquid to be treated and on the other factors indicated above. However, according to the first aspect of the present invention, an appropriate amount of organic acid (or acids) is also added to the treated fluid at a dose that typically results in a concentration of the organic acid (or acids) in the treated fluid in the normal range of 0.01 to 10 hours. ./million, preferably from 0.1 to 3 ppm, if the liquid is a hydrocarbon-based liquid or a contaminated aqueous solution. Within this range, the most appropriate dose of the organic acid (or acids), as well as the most appropriate dose of the recently proposed treatment solution, mainly depends on:

1) the content of H2S and other sulfur-containing contaminants in the treated liquid;

2) fluid viscosity and

3) the allowable reaction time of the treatment solution with the fluid to be treated, although heating and/or stirring the fluid to be treated will reduce the viscosity of the fluid and also reduce the amount of time needed to properly reduce the concentration of H ₂ S and other contaminants in the fluid.

The dose of organic acid (or acids) can be essentially linearly scaled in the specified range based on these factors.

In a recently proposed treatment method in which only a standard dose of treatment solution according to the recent proposal of the present inventors is added to the treatment fluid, little or no sediment (or precipitation), solid deposits, etc. may fall out of the treated fluids. , however, even small amounts of sediment (or sediments), solid deposits, etc. may not be desirable or acceptable in some situations. However, in the method according to the first aspect of the present invention, the organic acid (or acids) which are also added to the treated fluids ensure that the treated fluids do not substantially precipitate (or precipitate), solid deposits, etc., even if they processed, transported and/or stored for a certain period of time, for example within a few hours, days or weeks. In addition, if there is an increased likelihood of precipitation (or precipitation), solid deposits, etc. from the fluid being treated, for example, if the fluid being treated has a particularly high content of H2S and other sulfides, requiring a higher dose of treatment solution according to the recent proposal of the present inventors, and/or if the fluid being treated has a high content of fibrous components, such as organic matter, to an increased amount of organic acid (or acids) outside the normal range of 0.01 to 10 ppm, preferably 0.1 to 3 ppm, can be added to the treated fluid to ensure substantially no precipitation (or precipitation), solid deposits, etc.

A specific application in which it is very important that from treated fluids based on

- 6 041530 hydrocarbons do not precipitate, solid deposits, etc., is the case when crude oil is transported directly from the reservoir in a tank car or other tank to the main pipeline that transports crude oil to the refinery. Crude oil containing more than 5 ppm H2S is generally not acceptable in the main pipeline. When crude oil is treated with a standard dose of treatment solution according to a recent proposal by the present inventors, the H2S content can be effectively reduced to 5 ppm or below, but it is likely that some precipitation and/or solid deposits will fall or be deposited on the surfaces of a tank car or other tank. in which crude oil is transported, which may be undesirable. However, by additionally adding an appropriate amount of organic acid (or acids) to the treated fluid according to the first aspect of the present invention, a substantially complete absence of precipitation or solid deposits from the treated hydrocarbon-based fluids, including crude oil, is provided. Importantly, the treatment solution and method of the present invention does not have any detrimental effects on the treated fluids, but significantly improves some of the characteristics of the treated fluid other than reducing H2S and other contaminant concentrations to safe, acceptable levels. For example, a treated hydrocarbon-based fluid, such as crude oil, will not only have H2S concentrations reduced to substantially zero, but will also have a substantially neutral pH of about 7 so that it will create fewer shipping problems. tank, pipeline and distillation process compared to untreated crude oil, which typically contains up to 2000 ppm H2S and has a slightly acidic pH in the range of 5 to 5.5. In addition, a test carried out on treated crude oil shows that the benzene content of the light ends components of the treated crude oil is generally improved, i.e. increases slightly due to the processing. Furthermore, improved performance refined crude oil is generally more valuable than untreated crude oil and can be sold at a higher price, such as $5 to $10 per barrel. Although the treated crude oil may contain some residual amounts of hydroxide (or hydroxides), organic acid (or acids) and/or other components added during the treatment process, this is not particularly detrimental to the crude oil, transport tank and main pipeline.

According to the second aspect of the present invention, the treatment method according to the recent proposal of the present inventors is further modified by adding also a small amount of monoethanolamine (MEA; C2H7NO) to the liquid to be treated, together with the appropriate amounts of the recently proposed treatment solution and the organic acid(s) discussed in connection with the first aspect of the present invention. A corresponding low amount of MEA added in the process of the present invention typically corresponds to a concentration in the range of 0.5 to 15 ppm, preferably 1.0 to 10 ppm MEA in the treated fluid based on hydrocarbons or in aqueous solution. Again, in this range, the most appropriate dose of MEA primarily depends on several factors, for example, 1) the content of H ₂ S and other sulfur-containing contaminants in the treated fluid; 2) the viscosity of the fluid to be treated; and 3) the allowable reaction time of the treatment solution with the fluid to be treated, although note that heating and/or agitating the fluid to be treated will typically reduce the viscosity of the fluid and also reduce the reaction time needed to sufficiently reduce the concentration of H2S and other contaminants. in processed liquids. The dose of MEA can usually be linearly scaled in the specified range based on these three factors.

MEA added in small amounts to the treatment fluids according to the second aspect of the present invention functions as an effective anti-scale agent and is also more effective in removing certain types of sulfur compounds than the hydroxide (or hydroxides) in the recently proposed treatment solution. Accordingly, the treatment method including MEA according to the present invention provides a more complete removal of various types of sulfur-containing compounds.

This method differs from the conventional amine treatment method in which relatively large amounts of MEA are added as a main component to hydrocarbon-based liquids such as crude oil to reduce the H ₂ S concentration in the hydrocarbon-based liquids. MEA reacts exothermically with hydroxide (or hydroxides) such as NaOH and KOH. Accordingly, the higher the dose of MEA added to treat a fluid in the treatment process of the present invention, the more hydroxide (or hydroxides) in the newly proposed treatment solution, which is also added to the treatment fluid as part of the treatment process, will react with the MEA, and not with H2S and other sulfur-containing contaminants contained in the treated fluid. This would be unproductive and undesirable. Accordingly, only a small amount of MEA within this range is typically added to the treatment solutions according to the second aspect of the present invention, i.e. an amount sufficient to function as an antiscale agent, but not so large as to significantly reduce the effectiveness of the hydroxide. (or hydroxides) in relation to removal

- 7 041530

H2S and other sulfur-containing contaminants. As with the organic acid(s), MEA may be added to the newly proposed treatment solution to form a modified treatment solution, which is then added to the treatment fluid, or MEA may be added to the treatment fluid separately from the newly proposed treatment solution and from organic acid (or acids). Again, even if MEA is added to the newly proposed treatment solution and stored for a month or so, tests show that there is no noticeable change in the content of the components of the modified treatment solution.

Purpose of the description of the invention

Although the following description of the invention, which is intended for general distribution, is detailed in order to ensure the adequacy of the description and contribute to the understanding of the invention, it should not be taken as limiting the essence of the patent, which should cover the inventive concept in all aspects, no matter how it may be later implemented by changing the shape or adding further improvements.

The claims at the end of the description serve this purpose as they meet the requirement to indicate improvements, combinations and methods in which inventive concepts are discovered.

Information supporting the possibility of carrying out the invention Treatment solutions and methods of treatment - illustrative embodiments

According to exemplary embodiments of the present invention, treatment solutions and treatment methods are provided in which treatment solutions are used to treat hydrocarbon or petroleum based fluids such as crude oil, diesel fuel, and the like, as well as to treat contaminated aqueous solutions, such as water extracted from underground formations together with crude oil and natural gas, in order to reduce the concentration of hydrogen sulfide (H2S), other sulfur compounds and other contaminants contained in these fluids to acceptable levels while ensuring an essentially complete absence of precipitation, solid deposits, etc. from processed liquids over a period of time equal to hours, days or months.

Removal of H2S is a major focus and benefit of the treatment fluids and treatment methods of the illustrative embodiments of the present invention because H2S is highly toxic and corrosive, commonly found in elevated concentrations in crude oil and natural gas recovered from subterranean formations and in aqueous solutions. extracted from underground formations together with crude oil or natural gas, and the allowable content of H2S in hydrocarbon-based fluids and aqueous solutions is severely limited and regulated. The treatment solution and treatment method recently proposed by the present inventors are very effective and cost effective in reducing the concentration of H2S in hydrocarbon-based fluids and contaminated solutions, as described in PCT/US 2018/050913. However, in addition to the removal of H2S, in some situations it is also very important that substances formed during the removal of H ₂ S and other sulfur-containing compounds, as well as other contaminants present in the treated fluids, do not separate from the treated fluids in the form of a precipitate (or precipitates), solid deposits, etc. during processing, transport or storage for certain periods of time, and this is another important focus of the present invention. A particular application in which it is very important that the treated hydrocarbon-based fluids do not precipitate, solid deposits, etc., is the case where crude oil is transported directly from a subterranean formation in a tank car or other tank to a main pipeline, which transports crude oil to the refinery. With regard to treated aqueous solutions, such solutions are sometimes used in industrial applications including boilers, refrigeration, leather tanning processes, wood pulp and paper processes, etc., where it is important that no precipitation or they did not form precipitation, solid deposits, etc.

The treatment solution and treatment method according to the illustrative embodiments of the present invention are modifications of the treatment solutions and treatment methods recently proposed by the present inventors as described in PCT/US 2018/050913, and generally involve the use of the newly proposed treatment solution to effective reduction of concentrations of H ₂ S and other contaminants in hydrocarbon-based fluids and aqueous solutions, together with one or more additional substances, the function of which is to prevent the release of removable contaminants and other contaminants contained in the treated fluids in the form of a precipitate (or precipitates), solid deposits, etc. The treatment methods of the present invention use an appropriate amount of a newly proposed treatment solution and provide a reduction in the concentrations of H2S and other contaminants contained in the treated fluids to acceptable levels essentially the same as described in PCT/US 2018/050913, then as an additional substance (or substances) are added in an appropriate amount, and their function is to ensure that essentially none of the contaminants removed and

- 8 041530 other contaminants contained in the processed liquids have not been released from the processed liquids in the form of sediment (or sediments), solid deposits, etc. during handling, transportation or storage of these liquids for certain periods of time. According to an exemplary embodiment of the present invention, such additional substances primarily include at least one organic acid, such as fulvic acid and humic acid. If such an organic acid (or acids) is also added to the liquids to be treated, even at relatively low concentrations, such as 3 ppm or less, they are very effective in preventing precipitation, solid deposits, and the like. from processed liquids. Another substance that can also be used in an embodiment of the processing method of the present invention is monoethanolamine (MEA). If it is also added to process fluids at relatively low concentrations, such as 15 ppm or less, then MEA functions effectively as an anti-scale agent and also performs other useful functions, including the removal of certain other contaminants, as indicated in this publication.

For a complete understanding of the present invention, the following are: (I) a discussion of the recently proposed by the present inventors of the treatment solution and treatment method disclosed in PCT/US 2018/050913 to remove H ₂ S and other contaminants, and (II) discuss the options implementation of the treatment solution and treatment method of the present invention, in which an additional substance (or substances) are used in conjunction with the recently proposed authors of the present invention treatment solution and treatment method for treating various contaminated liquids to reduce concentrations of H ₂ S and other contaminants in liquids with the prevention of the formation of sediment (or sediments), solid deposits, etc.

(I) Solution for treatment and method of treatment according to the proposal of the authors of the present invention

The main aspects of the treatment solution and the treatment method according to the recent proposal of the present inventors disclosed in the publication PCT/US 2018/050913 are explained above, including that the treatment solution is an aqueous-based solution, and above all, it may contain one or more hydroxides in a total high concentration ranging from 35 to 55 wt.%, preferably equal to at least 45 wt.%; that the treatment method is very cost effective and efficient in reducing the concentration of H ₂ S and other contaminants in hydrocarbon-based fluids and aqueous solutions; that the treatment method includes the steps of adding a standard dose of treatment solution in the range of 0.25 ml to 6.0 ml/l of the liquid to be treated, preferably in the range of 1.0 ml to 5.0 ml/l of the liquid, to be treated, which corresponds to a hydroxide content (or hydroxides) in the fluid to be treated, ranging from about 125 to 3000 ppm, and reacting the solution to be treated with the fluid to be treated, for a period of time, lying in the range from 15 min to 24 h; that in some situations it may be desirable to add excessively high doses of treatment solution to the fluids to be treated, but tend to precipitate (or precipitate) and the like. from the treated liquid, which may be undesirable for the present invention; etc. Some additional details regarding the recently proposed treatment solution and treatment method are provided below.

Again, the most appropriate or optimal dose of the newly proposed treatment solution within the specified range will vary, usually in a linear scalable manner, based on several factors. Two important factors are the specific contaminants and the concentrations of contaminants in the fluids. Although H2S is a major contaminant that typically needs to be removed from process fluids such as crude oil, it may be necessary or desirable to remove contaminants other than H2S from the fluids as well, and other contaminants may also be difficult to remove. H2S. In general, if the fluid being treated is a medium or light crude oil and the H2S content is relatively low, such as 20 to 100 ppm, then the most appropriate dose may lie towards the lower end of the standard range, whereas if the H2S content is relatively high, for example from 20,000 to 40,000 ppm, the most appropriate dose may lie towards the upper end of the standard range, and the most appropriate doses in the case of average H ₂ S concentrations will be, respectively, the average values in the standard range.

Another important factor, especially in the case of some hydrocarbon-based fluids, is the viscosity of the fluid. The treatment solution has good migration characteristics when added to contaminated aqueous solutions or thin, low-viscosity hydrocarbon-based liquids, such as liquids with an API gravity of 33° or more, and can be easily dispersed in liquids after being added to them, although liquids can be heated and/or agitated to increase the speed and/or uniformity of dispersion, which will reduce the required reaction time to remove H2S. In the case of medium-viscosity hydrocarbon-based fluids with an API gravity ranging from about 23° to about 33°, mixing by mixing at low to moderate speeds, such as in the range of 100 to 500 rpm, or

- 9 041530 in another suitable manner and/or heating to temperatures below the flash point of the liquids aids in the dispersion of the treatment solution in the liquids. In the case of highly viscous hydrocarbon-based fluids with an API gravity of 15° or less, heating to temperatures below the flash point of the fluids, along with agitation, is generally required to sufficiently disperse the treatment solution in the fluids. Different types of hydrocarbon fluids include light crude oil (API gravity >31.1°), medium crude oil (API gravity 23.3 to 31.1°), heavy crude oil (API gravity <23, 3°), bunker fuel (API gravity is about 6°), diesel fuel (API gravity is about 34°), etc. Hydrocarbon based fluids with an API gravity less than 10° heavier than water are exceptionally viscous and will settle to the bottom in water. With regard to treatment solution doses, if the hydrocarbon-based fluid contains 2000 ppm H ₂ S or less, then for low viscosity (API gravity of 33° or more) hydrocarbon-based fluids such as diesel fuel, the most appropriate dose may be in the range of 1 ml to 2 ml/l of the base fluid, while for medium viscosity fluids (API gravity ranging from 20° to 30°) such as light, medium and heavy crude oils, the most suitable the dose may be in the range of 2 ml to 3.5 ml/l of hydrocarbon-based fluid, and for highly viscous fluids (API gravity of 15° or less), such as bunker fuel, the most appropriate dose may be in the range of 5 ml to 6 ml/l hydrocarbon-based liquid.

With regard to the allowable reaction time, there is no particular limitation here, and the treatment solution can react for any suitable time, for example from 15 minutes to 24 hours, at the most appropriate dose based on the concentration/amount of H2S contained in a particular liquid, and viscosity (API density) of the fluid in the processing method according to a recent proposal of the authors of the present invention. However, there may be situations in which the reaction time is limited, such as being limited to the time required to transport the hydrocarbon-based fluid to the desired discharge site after the treatment solution has been added to the fluid, or limited based on the desired throughput of the treatment process, etc. d. In such situations, the dose of treatment solution added to the fluid during treatment may be increased beyond the standard dose, for example, increased to an amount that will substantially remove the H2S contained in the particular fluid within a reasonable reaction time. For example, if the normal reaction time required to completely remove the H2S contained in a particular liquid is 2 hours, and the allowable reaction time is only 1 hour, then a dose of twice the standard dose based on the concentration may be most appropriate. /the amount of H2S contained in a particular liquid and the viscosity of the liquid. Again, stirring and/or heating the liquid to be treated also generally shortens the required reaction time.

According to a study performed by the present inventors, if crude oil containing about 1000 ppm H2S was treated with a treatment solution according to a recent proposal of the present inventors, which contained NaOH in an amount of about 99% of the total hydroxides, KOH as the remaining 1% hydroxides, and the total concentration of hydroxides in which was equal to about 50 wt.%, adding 0.25 ml of treatment solution per liter of crude oil took about 12 hours to remove H2S or reduce its concentration to about 0 hours / ppm, while adding 5 ml of treatment solution per liter of crude oil took about 30 minutes to reduce the H2S concentration to about 0 ppm. In another study performed on the same crude oil, substantially the same results were obtained when a treatment solution containing KOH at about 99% of the total hydroxides, NaOH as the remaining 1% hydroxides, and total the concentration of hydroxides in solution, equal to about 50 wt.%, was used in the same doses for the treatment of crude oil.

A complicating factor in the treatment of natural hydrocarbon-based fluids such as crude oil and aqueous solutions extracted from subterranean formations along with crude oil or natural gas is that such fluids typically have widely varying characteristics that must be taken into account. For example, even in the case of the same oil well or gas well, crude oil and aqueous solutions extracted from it may have characteristics that may vary significantly, for example, crude oil produced from a given well at a certain time of a certain day may contain quantities H ₂ S and various types and amounts of other contaminants, which will be significantly different from their amount in crude oil obtained from the same well on the same day but at a different time.

In an advantageous aspect of the recently proposed treatment fluid and treatment method, a specific or standard treatment fluid composition can be used to treat a wide range of different hydrocarbon or water based fluids and to treat fluids having widely varying characteristics. For example, adding a treatment solution dose in the upper half of the standard dose range, or even adding moderately

- 10 041530 an overdose exceeding the standard dose range will generally reduce H2S and other contaminant concentrations to acceptable levels without significantly adversely affecting the treated fluid. Accordingly, it may be advantageous and/or convenient to add such dosages of a standard treatment solution composition to a particular fluid to ensure that H ₂ S and other contaminant concentrations are sufficiently reduced to acceptable levels, rather than carefully analyzing the fluid and determining the most appropriate dosage of solution for processing based on the results of the analysis. Although the cost of processing may increase due to the use of additional processing solution, these additional costs may be acceptable in some situations. On the other hand, it is an object of the present invention to avoid the formation and precipitation of liquids to be treated, so the use of too excessive doses should generally be avoided, and it may be desirable to also increase the doses of organic acid (or acids) and / or MEA with an increase in the dose of hydroxide (or hydroxides ) during liquid handling.

Although there are many different common hydroxide compounds (OH ^- ) that can be used in the treatment solution according to a recent proposal, many of them have undesirable characteristics, including they can introduce other contaminants into the treated fluids, which may require an additional step (or stages) removal, increase costs, etc. For example, iron, other metals, calcium, barium and chlorides interfere with heating and cracking in petroleum refining processes and may need to be removed from treated crude oil prior to distillation. On the other hand, sodium, potassium, magnesium and manganese are acceptable in oil refining processes if their content is not too high, so the hydroxides of these elements can be used if the treatment solution is used to treat crude oil. For example, a study performed showed that in the case of a crude oil with an initial Na concentration of about 8 ppm, which contains about 1000 ppm H2S, after treatment with 3 ml of a treatment solution according to a recent proposal of the authors of the present invention on liter of crude oil, final concentrations were about 40 ppm for Na and 0 ppm for H2S. Sodium has no adverse effects in the crude oil refining process as the sodium concentration is typically <250 ppm. Potassium hydroxide (KOH), magnesium hydroxide (Mg(OH) ₂ ) and manganese hydroxide (Mn(OH) ₂ , Mn(OH) ₄ ) are other suitable hydroxides for use in a recently proposed treatment solution in crude oil processing. For the treatment of contaminated aqueous solutions, there are fewer restrictions on the hydroxides that can be included in the recently proposed treatment solution, although price is usually an important factor, and sodium hydroxide and potassium hydroxide are relatively cheap.

The use of a combination of hydroxides is preferred for more complete reaction or removal of most or all of the sulfides found in hydrocarbon-based fluids and contaminated aqueous solutions because there are over 300 types of sulfides and NaOH is not the most suitable hydroxide to remove all of these various sulfides. Of course, hydrogen sulfide H2S is usually the main pollutant that needs to be removed. Potassium hydroxide (KOH), for example, is more effective than sodium hydroxide at reacting with certain types of sulfides. Accordingly, if the treatment solution according to the recent proposal of the authors of the present invention contains some potassium hydroxide (KOH) together with sodium hydroxide, then the treatment solution provides a more complete reaction with all sulfur compounds contained in oil-based fluids, compared with using a solution for treatment containing only sodium hydroxide. For example, a treatment solution according to a recent proposal may contain a mixture of 50 to 99.9 parts NaOH and 0.1 to 50 parts KOH, with a total hydroxide concentration in the treatment solution ranging from 35 to 55 wt.%. , preferably equal to at least 45 wt.%.

In addition, aqueous solutions of different hydroxides freeze at different temperatures, even if the solutions have the same total concentrations of different hydroxides, and this can be important. For example, if the treatment process is to be carried out at ambient temperatures close to 0°C or below, it may be desirable to use a treatment solution containing a high total concentration of one or more hydroxides, ranging from 35 to 55 wt.%, preferably equal to at least 45 wt.%, while the treatment solution has a freezing point below ambient temperature, so that temperature-related complications such as freezing or gelling of the treatment solution and/or the liquid to be treated are excluded; for example, the treatment solution containing KOH as the basic hydroxide has a freezing point below the freezing point of the treatment solution containing NaOH as the basic hydroxide.

The recently proposed treatment solution may contain other components, again depending on the presence of other contaminants in the treated fluids to be removed, and also depending on the desired results of the treatment process. These other components can also be included in the treatment solution and treatment method of the present invention.

- 11 041530 niyu. For example, a small amount of silicate, such as potassium silicate, can be added to the treatment solution to provide an antibacterial function, which may be desirable for killing microbes, in particular sulfur-eating microbes. For example, 2 to 10 ml of an aqueous solution of potassium silicate containing 29 to 45 wt.% potassium silicate in water can also be added per liter of a recently proposed treatment solution containing a high concentration of hydroxide (or hydroxides), and then the treatment solution , containing hydroxide (or hydroxides) and potassium silicate, can be added to the liquid to be treated in appropriate doses within the specified standard dose range. Alternatively, appropriate doses of potassium silicate solution and treatment solution can be added to the liquid to be treated. Potassium silicate exists in various SiO ₂ :K ₂ O ratios, but is often represented as K ₂ SiO ₃ .

Other suitable antibacterial agent or antibacterial agents can be used in addition to silicates or as an alternative to silicates, depending on the particular fluid to be treated. For example, you can add <100 ppm barium (Ba) to the liquid to be treated, whether it is a hydrocarbon-based liquid or an aqueous solution, and it will perform an antibacterial function. Barium is generally more suitable for use in lighter hydrocarbon-based fluids, including diesel fuel, and for treating aqueous solutions, while potassium silicate is generally more suitable for use in heavier hydrocarbon-based fluids, including crude oil. In addition, the use of barium is prohibited in those hydrocarbon-based fluids that must be refined, since barium has an adverse effect on the refining process. Therefore, barium is not preferred for the practice of the present invention when hydrocarbon-based liquids such as crude oil are being treated.

Another component that can be included in or used in conjunction with our recently proposed treatment solution is sodium bisulfite (NaHSO ₃ ). When added at a relatively low concentration, such as 0.001 to 0.05 ppm per liter of fluid to be treated, bisulfite is very effective in displacing dissolved gases such as methane (CH ₄ ) contained in contaminated aqueous solutions during treatment. and transportation using tank trucks, pipelines or other means so that the displaced gas can be captured, collected and sold. This, of course, is highly desirable and beneficial. Accordingly, for example, if contaminated wastewater generated or produced during the production of methane/natural gas from a well contains 5 vol.% methane/natural gas dissolved in it, then this may represent a significant amount of methane/natural gas that can be recovered which will significantly increase the overall productivity of the well. The aqueous sodium bisulfite solution may be highly concentrated, for example 70 to 90% by weight, and may be added to the recently proposed treatment solution in an appropriate amount to give a concentration ranging from 0.001 to 0.05 ppm per liter liquid to be processed. While the addition of sodium bisulfite may be particularly suitable for treating aqueous solutions, it can also be added to a treatment solution used to treat hydrocarbon-based fluids. However, it is important that when sodium bisulfite is to be used to treat crude oil or other hydrocarbon-based fluids, it must be added in a hydrated form, whether powder or liquid, to function effectively.

In addition, hydrocarbon-based fluids such as crude oil and contaminated aqueous solutions typically contain various impurities and varying amounts of impurities, many of which must or must be removed along with H ₂ S and other sulfur-containing contaminants. These impurities include ammonia (NH ₃ ), carbon dioxide gas (CO2), and various particulate matter including dead/decomposed organic matter, total suspended solids (TSS) or fibers, which are normally include various minerals and other inorganic substances attached to hydrocarbons, bottom sediment and water (BSW; from English: bottom sediment and water), heavy metals, etc. Accumulated ammonia can be released from the treated liquid in the form of a gas, which is toxic and undesirable. To remove ammonia, it is possible to adjust the pH of the liquid to be treated to a level between 8.5 and 7.0, at which the ammonia is converted to the ammonium ion (NH4+) and therefore the release of ammonia in gaseous form is prevented. This pH level is consistent with the treatment method according to a recent proposal, since, for example, at standard doses of the treatment solution, the pH of the treated crude oil rises to about 7.0. However, lowering the pH of the treatment solution can also affect the reactions between hydroxide and H2S. Below pH 7.0, the S ^2- ions in the liquid are converted to HS ^- ions, which are one step closer to H2S, so that the liquid can have more residual H2S at lower pH and less residual H2S at higher pH. Of course, the removal of H2S is the main focus of the invention, and it should typically be the main factor in determining the appropriate pH of the liquid to be treated. It should also be noted that with a significant overdose of the recently proposed treatment solution, the pH value can exceed 9, and this increases the risk of getting more ammonia gas and forming

- 12 041530 precipitation and precipitation (or precipitation). Accordingly, this is another reason why the dose of the newly proposed treatment solution should be kept within the standard range in connection with the present invention. An alternative approach to removing ammonia from process fluids is to remove ammonia from the aqueous portion of the fluid using an ion exchange process.

If the fluid to be treated is crude oil and it contains a significant amount of carbon dioxide (CO2), this may affect the treatment process because the hydroxide (or hydroxides) contained in the recently proposed treatment solution may react with carbon dioxide in the presence of trace amounts of water according to equation (3) below, which may require additional hydroxide (or hydroxides) to be used to treat the crude oil, for example by increasing the dose of the recently proposed treatment solution added to the crude oil.

CO ₂ + NaOH (aqueous solution) -► NaHCO ₃ (3)

With regard to fibrous impurities in liquids to be treated, they can be conveniently and effectively removed from liquids using the same treatment solution and treatment method according to a recent proposal of the present inventors, which are used to react with H2S and other sulfur-containing compounds contained in the liquid. . However, as discussed in PCT/US 2018/050913, this may include the addition of a higher dose of the newly proposed treatment solution compared to the standard dose used to remove H ₂ S and other sulfide compounds, and/or the addition of other substances that cause the formation of precipitates and the like, such as components such as ferric chloride (FeCl ₃ ) and/or ionic polymers. For example, adding a dose of 2 to 5 times the standard dose of a recently proposed treatment solution to a hydrocarbon-based fluid typically causes sulfur compounds, fibrous impurities, and other impurities remaining in the hydrocarbon-based fluid to be treated to precipitate out of the fluid, if desired, while the addition of ferric chloride (FeCl ₃ ) and/or ionic polymers to the treated fluid may cause flocculation which traps/binds contaminants and causes them to precipitate from the treated fluids. Of course, the formation of deposits is contrary to one of the objectives of the present invention, which is to ensure that removed sulfur compounds and other contaminants are retained in the treated fluid for a certain period of time without the formation of deposits, solid deposits, etc.

Similarly, an exemplary treatment method according to a recent proposal by the present inventors may include additional steps for collecting, destroying, and treating precipitates and/or gases generated from reactions between the treatment solution and hydrocarbon-based fluids. However, again, an important aspect of the treatment method using the modified treatment solution of the present invention is that deposits, solid deposits, and the like are essentially not formed in the treated liquids. during their processing, transport and storage for a predetermined period of time, for example from 30 minutes to one or more days. Therefore, the processing method of the present invention typically does not require the steps of collecting, disposing and treating precipitates deposited from the liquids to be treated, since such precipitates, solid deposits, and the like. should not be generated.

(II) Treatment solution and treatment method of the present invention

The treatment method of the present invention also includes using a dose of the treatment solution according to a recent proposal, lying within the specified standard range, to effectively reduce the concentrations of H ₂ S and other contaminants in fluids to safe, acceptable levels in essentially the same way as discussed in publication PCT/US 2018/050913, but it also includes the use of an additional substance (or substances) to ensure that the treated liquids do not form or fall out of the precipitate (or precipitates), solid deposits, etc. during processing, transport and storage of liquids for periods of time equal to hours, days and weeks, and there will be no significant problems with the processed liquid. In a treatment method involving the addition of a newly proposed treatment solution within a standard dosage range to a contaminated fluid, typically little or no sludge (or deposits), solid deposits, etc. is formed, but to ensure that such As a result, the treatment method of the present invention includes the use of one or more additional substances in conjunction with a dose of the newly proposed treatment solution lying within the standard dose range.

Additional substance (or substances) for use with the recently proposed treatment solution according to an illustrative embodiment of the present invention may primarily include one or more organic acids, such as fulvic acid and humic acid. In the processing method of the present invention, the organic acid (or acids) can be added to the liquid to be treated in an appropriate total amount that results in

- 13 041530 normal concentration, ranging from 0.01 to 10 ppm, preferably from 0.1 to 3.0 ppm, in a liquid, regardless of whether the liquid being treated is a hydrocarbon-based liquid or contaminated aqueous solution. Within this range, the most appropriate dose of the organic acid(s), as well as the most appropriate dose of the newly proposed treatment solution, is predominantly dependent on the same three factors discussed in connection with determining the most appropriate dose of the inventors' newly proposed treatment solution. , that is

1) on the amount of H2S and other sulfur-containing compounds in the treated liquid;

2) on the viscosity of the liquid and

3) the allowable time for the treatment solution to react with the fluid to be treated, although heating and/or stirring the fluid to be treated will reduce the viscosity of the fluid and shorten the time needed to properly reduce the concentration of H ₂ S and other contaminants in the fluid.

The dose of organic acid (or acids) can be essentially linearly scaled in the specified range based on these factors.

The organic acid (or acids) used in the present invention reacts and/or binds with sulfur-containing compounds, including those compounds that are attacked and removed by reaction with NaOH or other hydroxide (or hydroxides) contained in the recently proposed treatment solution, and substantially all remain in the treated fluid rather than being released from it in the form of gases, sediment (or sediments), solid deposits, and the like. It is possible to isolate small amounts of removed sulfide compounds from treated liquids in the form of a gas such as sulfur dioxide or in the form of a precipitate such as sulfate when the organic acid (or acids) are added at the indicated normal concentrations, but this is a small amount. usually doesn't matter. In addition, if it is desired that no precipitate (or precipitates), gas (or gases), solid deposits, etc. be formed in the treated liquid at all. then the amount of organic acid (or acids) added in the treatment process can be increased beyond the specified concentration range, that is, increased by 10-50%. It is very important that the treatment method does not have a significant detrimental effect on the treated fluids, for example, the removed sulfide compounds mostly remain in the treated fluids, but in the form of other sulfur compounds that are not toxic or highly hazardous, unlike H ₂ S until it is removed.

Fulvic acid is essentially a family of organic acids, but can typically be defined as 4,10-dihydro-3,7,8-trihydroxy-3-methyl-10-oxo-1H,3H-pyrano[4,3b][ 1]benzopyran-9-carboxylic acid or 3,7,8-trihydroxy-3-methyl-10-oxo-1,4-dihydropyrano[4,3b]chromene-9-carboxylic acid with the average chemical formula C ₁₃₅ H ₁₈₂ O ₉₅ N ₅ S ₂ and molecular weights typically ranging from 100 to 10,000 g/mol. Similarly, humic acid is a mixture of several molecules, some of which are based on an aromatic core motif with phenolic and carboxyl substituents that are linked to each other, and the illustration below shows the characteristic structure. The molecular weight (size) of humic acid is typically much larger than that of fulvic acid and may range from 50,000 to more than 500,000 g/mol.

The organic acid (or acids) can be added to the treatment solution of the present invention in powder form, for example in the form of a powder containing 70 to 100% by weight of the organic acid (or acids), or in the form of an aqueous solution, for example in the form of an aqueous solution, containing from 1 to 40 wt.% organic acid (or acids).

Another substance that can be used in the treatments of the present invention is monoethanolamine or MEA (C2H7NO). MEA is a liquid organic compound and a weak base. MEA functions as an antiscale agent and is also more effective at removing certain types of sulfur compounds than the hydroxide (or hydroxides) in the recently proposed treatment solution, such that the treatment method according to an illustrative embodiment of the present invention provides more complete removal various types of sulfur-containing compounds. The appropriate amount of MEA to be used in the processing method typically corresponds to a concentration ranging from

- 14 041530

0.5 to 15 ppm, preferably 1.0 to 10 ppm, MEA in the hydrocarbon-based liquid or aqueous solution to be treated. Within this range, the most appropriate dose of MEA again predominantly depends on the same factors discussed in connection with the organic acid (or acids) and the recently proposed treatment solution, and the dose of MEA can be substantially linearly scaled within the specified range based on these factors. MEA can be used in the processing method of the present invention directly at 100% concentration.

There are several additional considerations regarding MEA in the processing method of the present invention. First, MEA reacts exothermically with hydroxides such as NaOH also used in the process, so it is desirable not to include excess MEA in the process as this may be counterproductive to the hydroxides' intended function of reacting with H2S to its removal. MEA can also react with carbon dioxide (CO2) according to the following reversible reaction:

CO ₂ + 2 HOCH ₂ CH ₂ MH ₂ HOCH ₂ CH ₂ NH ₃ ⁺ + HOCH ₂ CH ₂ NHCO ₂ ... (4)

Because MEA reacts with carbon dioxide in the fluid being treated, this can reduce unwanted reactions involving the hydroxide (or hydroxides) also used in the treatment process, i.e. reactions between MEA and hydroxide (or hydroxides) and reactions between carbon dioxide and hydroxide (or hydroxides) according to equation (3) above. The amount of carbon dioxide in the liquid to be treated can also be an important factor if the amount is significant, and it may be desirable to increase the dose of MEA based on the carbon dioxide content of the liquid to be treated in the case of liquids containing a relatively large amount of carbon dioxide.

Another optional component that can be included in the treatment solution and treatment method of the present invention is a freezing point depressant or anti-gelling agent, which may be desirable if hydrocarbon-based fluids such as crude oil are to be treated. , particularly at low temperatures of 0° C. and below, since other components used in the treatment solution and in the treatment method according to embodiments of the present invention may cause hydrocarbon-based treatment fluids to freeze or gel at such temperatures. For example, the water contained in the treatment solution according to the recent proposal of the authors of the present invention, described in the publication PCT/US 2018/050913, water, which is formed in reactions between hydroxide (or hydroxides) and H ₂ S and other contaminants contained in the treated liquids, and organic acids can cause gelation in processed crude oils. Although the crude oil being processed can be heated to prevent such gelation, it is not always possible or practical to heat the crude oil being processed. In such situations, the addition of an anti-gelling agent may be the most appropriate way to prevent gelation in the crude oil. A suitable group of anti-gelling agents are low molecular weight hydrocarbon fluids, including hexane and cyclohexane, which can be added to hydrocarbon fluids to be treated at doses ranging from 10% to 25% by volume of the combined total volume of all other components. added to hydrocarbon-based fluids processed by the method of the present invention. For example, in the treatment method of the present invention, if a large volume of crude oil is treated using 85 gallons of treatment solution according to the recent proposal of the present inventors, described in the publication PCT/US 2018/050913, together with 10 gallons of organic acid (or acids) and 5 gallons of MEA with a total of 100 gallons of other components, then 10 to 25 gallons of hexane or cyclohexane can also be added to the crude oil as an anti-gelling agent as part of the treatment.

An alternative way to prevent freezing or gelling of hydrocarbon-based fluids in the process of the present invention, as discussed above, is to select the hydroxide (or hydroxides) used in the treatment solution according to the recent proposal of the present inventors, so that the treatment solution has a freezing point below the ambient temperature at which the processing is carried out. For example, in a crude oil treatment process, if a newly proposed treatment solution contains about equal amounts of NaOH and KOH at a total concentration of about 50% by weight in the treatment solution, then the components of the crude oil thus treated will begin to gel at a temperature of , lying in the range from about 0 to -5°C, while if the same crude oil is treated using a treatment solution containing NaOH and KOH in a ratio of 19:1 and a total concentration of about 50 wt.%, in solution for treatment, then the components of the thus processed crude oil will begin to gel at a temperature equal to about 5°C.

In the processing method according to illustrative embodiments of the present invention, the respective amounts of the recently proposed by the present inventors solution for treating contaminated liquids and an additional component (or components) that prevent

- 15 041530 sludge (or sludge), solid deposits, etc., and anti-freeze or anti-gel agents may be separately added to the fluids to be treated, or, alternatively, one or more additional components may be added to a recently proposed treatment solution to form a modified treatment solution, which is then added at an appropriate dose to the fluids to be treated. An alternative approach is more convenient for practical reasons, since the modified treatment solution can be prepared in advance at any convenient location, transported in one container to another location where it will be added to the treatment fluid, and ensure that all components are added to the treatment fluid at the same time. Although some of the various components may react with each other in such a modified treatment solution before it is added to the treatment liquid, the number of such reactions is small and this will not significantly reduce the effectiveness of the treatment method compared to a treatment method in which each of several components individually added to the treated liquid. Accordingly, for example, suitable amounts of an organic acid (or acids), MEA and/or an anti-gelling agent can be added to a certain volume of our recently proposed treatment solution to form a modified treatment solution such that when a certain amount of the modified solution is added for processing to a certain volume of the processed liquid, each of the components was in a certain dose in a certain volume of the processed liquid.

An exemplary modified treatment solution of the present invention can be prepared by combining 1 to 15 ml of an aqueous solution containing 5 wt% organic acid (or acids) in water and 0.05 to 0.5 ml of MEA per liter of the newly proposed solution for treatment containing a total hydroxide concentration ranging from 35 to 55 wt.%, preferably equal to at least 45 wt.% in water. The modified treatment solution can then be added to the fluids to be treated at appropriate doses, which may substantially correspond to the standard dose range indicated in connection with the present inventors' newly proposed treatment method, i.e., in the range of 0.25 to 6.0 ml per liter, preferably in the range of 1.0 ml to 5.0 ml/l of the liquid to be treated, bearing in mind that the amounts of organic acid (or acids) and MEA combined with the newly proposed treatment solution to obtain a modified solution for treatment are approximately 1% of the modified treatment solution. The relatively small amount of organic acid (or acids) included in the modified treatment solution does not cause significant changes in the basic characteristics imparted by a significantly larger amount of hydroxide (or hydroxides), and the modified treatment solution will have a pH value substantially corresponding to the pH value of the solution for a treatment that does not contain an organic acid (or acids), for example in the range of 13 to 14, and the modified treatment solution will raise the pH of the fluids to be treated by substantially the same amount as the recently proposed treatment solution that does not contain an organic acid (or acids).

Again, the main important advantages provided by the treatment method of the present invention are the effective reduction of the concentration of H ₂ S and other contaminants in the treated fluids to safe, acceptable levels and the prevention of the formation and release of sludge (or sediments), solid deposits from the treated fluids. and so on. when processing, transporting and storing liquids for periods of time equal to hours, days and weeks, without adversely affecting the processed liquids. To prevent the formation of sediment (or sediments), solid deposits, etc. the amount of the newly proposed treatment solution used in the treatment method should be kept within the standard range indicated above, since the addition of an excess amount of the newly proposed treatment solution usually promotes the formation of sludge (or precipitates), hard deposits, and the like. If the treatment method of the present invention includes the use of the modified treatment solution described above, then in case the amount of the modified treatment solution added per liter of liquid to be treated is increased beyond the standard dosage range, the amounts of organic acid (or acids) and MEA also increase proportionally with the amount of hydroxide (or hydroxides) in the modified treatment solution, and it will still provide substantially no formation of sludge (or sludge), solid deposits, and the like. in treated fluids during their processing, transport and/or storage for a certain period of time, although an increased dose of hydroxide (or hydroxides) added during processing can usually contribute to the formation of sediment (or sediments), solid deposits and etc. in processed liquids, if they do not contain organic acid (or acids) and MEA.

Of course, it is also possible to independently increase the amount of organic acid (or acids) and/or MEA added to the modified treatment solution of the present invention without increasing the amount of hydroxide (or hydroxides) and other components. For example, if the liquid being treated, such as crude oil, has a very high concentration of H2S, or if the treated oil needs to be transported or stored for an extended period of time, such as 1 to 3 months, then an additional amount of organic acid (or acids) and/or MEA outside the normal dosage range indicated above to more reliably ensure that no precipitate (or precipitates), solid deposits, etc. are released. from the treated liquid over a long period of time. This usually does not create any problems with the treated fluid, but may add some cost to the treatment process.

Description of exemplary embodiments of the invention

The following are some examples of treatment methods using the treatment solution of the present invention. The first group of ten (10) examples is shown in the table below, in which various amounts of the modified treatment solution of the present invention were added to 100 ml of crude oil having an API gravity of 34° and containing 40,000 phr. million H2S, and the crude oil was stirred at a speed equal to 300 rpm, at a temperature equal to 21°C. The modified treatment solution used in these examples combined a large amount of our recently proposed treatment solution and smaller amounts of fulvic acid and MEA, such that the modified solution contained in one liter a total of about 50% by weight of NaOH and KOH, of which NaOH was about 49.5 wt% and KOH was about 0.5 wt%; 0.1 wt. % potassium silicate K ₂ SiO ₃ ; 1.0 wt.% fulvic acid having the molecular formula C ₁₄ H ₁₂ O ₈ and a molecular weight of 308.2 g/mol and 0.3 wt.% MEA. Mixing had a negligible effect on the amount of precipitate (or precipitates) produced. Several components of the treatment solution were combined prior to addition to the crude oil in each of the examples. ____________________________________________________________

Example No. Dose Reaction time Residual amount of H ₂ S Sediment amount* 1 0.1 ml 45 minutes 0.0 ml 2 0.3 ml 45 minutes 0.0 ml 3 0.5 ml 45 minutes 0.0 ml 4 0.8 ml 45 minutes 5.0 ml 5 1.0 ml 45 minutes 7.5 ml 6 0.1 ml 30 minutes 30 ppm 7 0.3 ml 30 minutes 12 ppm 8 0.5 ml 30 minutes 5 ppm 9 0.8 ml 30 minutes 3 ppm 10 1.0 ml 30 minutes 0 ppm

*The precipitate was a thick yellow liquid that tested positive for elemental sulphur, not a solid.

As shown in the table, although the amount of H2S in the crude oil was rather high at 40,000 ppm, the effectiveness of reducing the H2S concentration was generally high. At a treatment solution dose of 0.1 ml, the H2S content decreased significantly to 30 ppm, and the H2S content progressively decreased further to 5 ppm at a dose of 0.5 ml and to 0 ppm H2S when adding a dose of treatment solution equal to 10 ml. On the other hand, no precipitate (or precipitates) was formed until the dose was increased to 0.8 ml, which corresponds to 8 ml/l of crude oil and exceeds the upper limit of the standard dose of 6 ml for the recently proposed by the authors of the present invention processing solution. In addition, the reaction time was quite short, even though the liquid was agitated, which would generally shorten the time required for the treatment solution of the present invention to fully react with the H ₂ S in the crude oil, so less treatment solution would be sufficient to lowering the H2S content to 5 ppm or less, for example a dose of 2.5 ml, may be sufficient to reduce the H2S content to 0 ppm if more time is allowed for the reaction.

Example 11.

In this example, the fluid to be treated was a clear, hydrotreated petroleum distillate with an API gravity of 53°, containing 40,000 ppm H ₂ S vapor (determined according to ASTM D5705), 41 ppm mercaptan sulfur (determined according to UOP163) and 33 ppm H2S in liquid (determined according to UOP163), while the composition of the modified treatment solution used was the same as in examples 1-10, and it was added at a dose equal to 10 ml/l of liquid, to be processed (1 vol.%). All tests in this example were performed in a large accredited testing laboratory. Several components of the treatment solution were combined prior to addition to the petroleum distillate and after addition allowed for natural

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Claims (17)

migration in petroleum distillate without agitation at a temperature of about 21°C. The treated fluid was tested for H2S 13 minutes after the treatment solution was added to it, and the results showed 0 ppm H2S vapor (determined according to ASTM D5705), less than 0.2 ppm mercaptan sulfur (determined according to UOP163), and less than 1.0 ppm H2S in liquid (determined according to UOP163). Moreover, the same sample was stored for a month heated to an elevated temperature (up to 148°C) and again tested for H2S content, obtaining essentially the same results - 0 ppm H2S vapor and about 0 ppm H2S in liquid, which confirmed that the decrease in H2S concentration with this treatment method is not reversible. An additional test was carried out on petroleum distillate before and after treatment, consisting in the determination of sodium content, hydrocarbon distribution (HDST) and total light ends. This test showed: an increase in sodium content from 2 mg/kg before treatment to 40 mg/kg after treatment, which is in the acceptable range of concentrations; the absence of adverse effects on the original petroleum distillate and its residue and the reproducibility of ASTM D7169 and D2887 methods; and a slight but desirable increase in hexane, pentane and butane in total light ends (as determined by ASTM D7900). The major test lab that performed the test also commented that the test was performed using the most in-depth procedures including complete analysis of the crude product, complete fractional distillation, etc., and they found no negative effects, differences or variations in the product or fractions. fractions were balanced, the boiling points of the fractions met repeatability requirements, the total light ends were slightly increased, and most importantly, the H2S concentration remained reduced over time and after heating to elevated temperatures. Example 12. In this example, the treatment solution used in Examples 1-11 was tested for corrosivity to aluminum and steel specimens by the UNECE test method, section 37.4. The treatment solution was added to crude oil having an API gravity of 33° and containing 4000 ppm H2S vapor at a dose equal to 10 ml/l crude oil (1 vol.%) and allowed to migrate into the crude oil for 30 min. The samples were then immersed or semi-immersed in the treated liquid or exposed to the gas of the treated crude oil, in all cases the test lasted 168 hours. The weight loss of the samples was determined after 168 hours and 0.0% weight loss was found in all tested samples. As such, it was found that crude oil treated with a treatment solution dose of about 1.5 times normal was not corrosive to metals. Tests were also carried out with crude oils treated with higher doses of treatment solution, and only when the dose was increased to ten times the normal dose did the aluminum samples begin to show some weight loss after 168, for example, they became slightly chipped. The above description is for clarity of understanding only and is not intended to be limiting in any way, as modifications within the scope of the invention may be apparent to those skilled in the art and are within the scope of the invention. CLAIM 1. A water-based treatment solution for reducing the concentration of hydrogen sulfide (H2S) and other contaminants in liquids substantially without the formation of sediment, which contains at least one hydroxide compound selected from the group consisting of sodium hydroxide (NaOH), potassium hydroxide ( KOH), magnesium hydroxide (Mg(OH) ₂ ) and manganese hydroxide (Mn(OH) ₂ , Mn(OH) ₄ ); at least one organic acid, which includes at least one of fulvic acid and humic acid; and water, and the total concentration of at least one hydroxide compound in the treatment solution is in the range from 35 to 55 wt.% and the total concentration of at least one organic acid in the treatment solution is 0.01 wt.% or more and less 10 wt%. 2. The treatment solution according to claim 1, wherein the total concentration of at least one hydroxide compound in the solution is 45-55% by weight. 3. Treatment solution according to claim 1, containing at least two different hydroxide compounds. 4. The treatment solution according to claim 1, wherein the at least one hydroxide compound comprises at least one of sodium hydroxide (NaOH) and potassium hydroxide (KOH). 5. The treatment solution according to claim 1, wherein it further comprises monoethanolamine (MEA) and the concentration of MEA in the treatment solution is at least 0.05% by volume. - 18 041530 6. The treatment solution according to claim 1, wherein the concentration of MEA in the treatment solution is 0.052.0% by volume. 7. The treatment solution according to claim 1, wherein it further comprises at least one silicate compound and barium as an antibacterial agent. 8. A treatment method for purifying a contaminated liquid initially containing more than 5 ppm hydrogen sulfide (H ₂ S), essentially without the formation of a precipitate, comprising the steps of preparing an aqueous solution containing at least one hydroxide compound selected from the group , including sodium hydroxide (NaOH), potassium hydroxide (KOH), magnesium hydroxide (Mg(OH) ₂ ) and manganese hydroxide (Mn(OH) ₂ , Mn(OH) ₄ ), where the total concentration of at least one hydroxide compound in aqueous solution lies in the range from 35 to 55 wt.%; adding an aqueous solution to the contaminated liquid at a dose that provides a concentration of at least one hydroxide compound in the range from 125 to 5000 ppm in the contaminated liquid; add at least one organic acid, which includes at least one of fulvic acid and humic acid, to the contaminated liquid in a dose that provides a concentration of at least one organic acid equal to at least 0.01 ppm in the contaminated liquids; and dispersing the aqueous solution and at least one organic acid in the contaminated liquid and allowing the aqueous solution and at least one organic acid to interact with the contaminated liquid for a period of time until the concentration of hydrogen sulfide in the contaminated liquid decreases to <5 ppm. 9. The treatment method of claim 8, wherein the dose of the aqueous solution added to the contaminated fluid provides a concentration of at least one hydroxide compound in the range of 500 to 2500 ppm in the contaminated fluid. 10. The treatment method of claim 8, wherein the at least one organic acid is added at a dose that provides a concentration of at least one organic acid in the range of 0.1 to 10 ppm in the contaminated fluid. 11. The treatment method of claim 8, further comprising adding monoethanolamine (MEA) to the contaminated fluid at a concentration of 0.5 to 15 ppm MEA in the contaminated fluid. 12. The treatment method of claim 8, wherein the aqueous solution contains at least two different hydroxide compounds. 13. The treatment method of claim 8, wherein the contaminated fluid is a hydrocarbon-based fluid. 14. The treatment method of claim 8, further comprising combining the aqueous solution and at least one organic acid before adding the aqueous solution and at least one organic acid to the contaminated liquid. 15. The treatment method of claim 8, wherein the at least one hydroxide compound in the aqueous solution is selected to provide the aqueous solution with a specific freezing point of 0°C or less. 16. The treatment method according to claim 8, where the doses of an aqueous solution and at least one organic acid added to the contaminated fluid are adjusted based on at least one of: the concentration of hydrogen sulfide in the contaminated fluid, the desired reaction time to reduce the concentration of hydrogen sulfide in the contaminated liquids up to <5 ppm and the viscosity of the contaminated liquid. 17. The treatment solution of claim 1, wherein the at least one organic acid comprises fulvic acid. ^jj) Eurasian Patent Organization, EAPO Russia, 109012, Moscow, Maly Cherkassky per., 2