WO2022099192A1

WO2022099192A1 - Chemical compositions and treatment systems and treatment methods using same for remediating h2s and other contaminants in mixtures of contaminated fluids

Info

Publication number: WO2022099192A1
Application number: PCT/US2021/058610
Authority: WO
Inventors: Cliffton Roe; Linda SCHWEITZER
Original assignee: Gaps Technology, Llc
Priority date: 2020-11-09
Filing date: 2021-11-09
Publication date: 2022-05-12

Abstract

A treatment composition for remediating H2S and other contaminant(s) in a fluid mixture of contaminated liquids and gasses comprising: an aqueous hydroxide solution containing at least one hydroxide compound at a collective concentration of 35-55 weight percent of the aqueous hydroxide solution; and at least one organic acid selected from the group consisting of fulvic acid and humic acid, wherein the aqueous hydroxide solution constitutes at least 80 wt% of the treatment composition, the at least one organic acid constitutes 0.1 - 5 wt% of the treatment composition, and a pH of the treatment composition is at least 12.0.

Description

CHEMICAL COMPOSITIONS AND TREATMENT SYSTEMS AND TREATMENT METHODS USING SAME FOR REMEDIATING H₂S AND OTHER CONTAMINANTS IN MIXTURES OF CONTAMINATED FLUIDS

CROSS-REFERENCE TO RELATED APPLICATIONS

[000.1] The present application claims the benefit of priority to US Provisional Patent Application No. 63/111 ,400, filed November 9, 2020. The entire subject matter of each of this priority application, including specification claims and drawings thereof, is incorporated by reference herein.

BACKGROUND OF THE INVENTION

1. FIELD OF THE INVENTION

[0001] The present disclosure relates to novel treatment compositions and treatment methods for remediating sulfur-containing compounds, including H₂S, and other contaminants in various fluids, including hydrocarbon based liquids including crude oil, aqueous solutions including so-called “produced water” that is extracted from the earth with crude oil and gasses natural gas, as well as mixtures of such liquids and gasses. More particularly, the present disclosure relates to such treatment systems, methods and compositions in which mixtures of contaminated fluids are chemically reacted with the treatment compositions in the treatment systems and treatment methods according to the present invention whereby the contaminants in the mixed fluids are rapidly remediated down to significantly reduced levels in a practical, efficient and economical manner.

2. BACKGROUND

[0002] Sulfur-containing compounds including hydrogen sulfide (H₂S) have long been recognized as undesirable contaminants in hydrocarbon liquids such as crude oil and liquefied petroleum gas (LPG), as well as in hydrocarbon gasses such as natural gas, and aqueous solutions such as produced water extracted from the earth along with crude oil and in natural gas. H₂S is a particularly undesirable contaminant because it is highly toxic to humans and other animals, corrosive to metals, etc. and generally hydrocarbon liquids and gasses should contain less than four ppm H₂S. Remediation of H₂S in hydrocarbon liquids and gasses has long been and remains a very important focus of petroleum industries around the world.

[ 0003] Further, many of the hydrocarbon based liquids and gasses which are extracted from the ground may contain significant amounts of many other contaminants, including carbon dioxide, sodium chloride, nitrogen, etc., which should also be remediated down to low, acceptable levels to improve the quality and value of the hydrocarbon liquids and gasses.

[0004] The presence of these other contaminants will typically complicate the treatment required for remediating H₂S, and has conventionally required additional, special treatment compositions and methods beyond those used for remediating H₂S in the contaminated liquids and gasses. A particular complicating factor in treating naturally occurring hydrocarbon based liquids and gasses such as crude oil and natural gas, is the fact that such liquids and gasses typically have widely varying characteristics that must be considered. For example, even in relation to one given well which outputs crude oil, natural gas and produced water, the fluids extracted from the well have characteristics which can vary greatly, e.g., crude oil or natural gas extracted from a given well at a given time on a given day, can contain amounts of H₂S, as well as various types and amounts of other contaminants, which are significantly different from those contained in crude oil or natural gas extracted from the same well on the same day, but at a different time.

[0005] There are many known methods for remediating sulfur-containing compounds, including H₂S, from crude oil, natural gas 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, discuss that: the known methods include amine processes involving monoethanolamine (MEA), triazine, etc., treatment involving use of caustic material, iron oxide process, zinc oxide, molecular sieve, potassium hydroxide, and a hydrodesulphurization process; the amine treatment is usually the most cost effective choice for gas sweetening when significant amounts of acid gases exist; scrubbing of hydrogen sulfide using sodium hydroxide solution is a well established technology in refinery applications; caustic wash process is commonly used as a preliminary step in sweetening liquid hydrocarbons; and since the used solvent in this process cannot be easily regenerated, caustic scrubbers are most often applied where low acid gas (H₂S) volumes must be treated.

[0006] H₂S remediation achieved by a conventional amine treatment process uses an amine such as monoethanolamine (MEA) or triazine for treating H₂S in crude oil. However, with the conventional amine treatment process, while the H₂S may be initially remediated or abated down to acceptable levels, the sulfur contained in the treated oil may undesirably revert back to H₂S over time, especially if the treated oil is heated. Somewhat similarly, it is also known that there are bacteria which ingest sulfur compounds, and hence may reduce the amounts of sulfur contaminants in hydrocarbon based liquids or contaminated aqueous solutions. However, when the bacteria die and decompose this undesirably releases the sulfur back into the hydrocarbon based liquids or contaminated aqueous solutions.

[0007] A conventional caustic treatment used to remediate H₂S in crude oil involves use of a caustic aqueous solution consisting of up to 20% NaOH by weight. The water and caustic material are used to extract H₂S from the crude oil into solution, dissociating H₂S to HS- ion at higher pH, which shifts the equilibrium of H₂S gas from oil to water. Then, the HS- can react with sodium to form NaHS (sodium bisulfide), or with S₂- to form Na₂S (sodium sulfide), for example, plus water as a byproduct according to the following equations.

Generally, the conventional caustic treatment methods are limited to using caustic solutions of only up to 20 weight percent NaOH because the conventional methods are designed and intended to be partly a liquidliquid extraction, and partly a chemical reaction to convert the H₂S gas to a solid sulfurous species. It is conventionally understood that a certain amount of water is needed to permit the chemical reactants to contact with the crude oil or other petroleum based liquid. The larger amounts of water contained in the conventional caustic treatment solutions permit a greater amount of liquid-liquid extraction. Also, it is known that use of excessive amounts of NaOH may damage the crude oil, as well as metal components used handling the crude oil such as pipes and tanks.

[0008] Some of the H₂S may be converted into sulfur dioxide (SO₂) gas, e.g., upon stirring which allows air containing oxygen to get into the oil, which may be released from the treated petroleum based liquid, depending on the pressure under which the treated liquid is kept. Generally, hydroxides including NaOH are reducing agents and would not produce sulfur dioxide or elemental sulfur if the treated hydrocarbon based liquid is not exposed to air. However, if the oil is exposed to air, the sulfide/bisulfide can be oxidized to SO₂ or to elemental sulfur. All sulfide species are the same oxidation state (-2) and NaOH is not changing the oxidation state. Similar reactions would occur for other hydroxides included in the treatment solution. Relative to any such sulfur dioxide (SO₂) gas, as well as any other gases that may be released from the treated crude oil and treated natural gas, it would be necessary as a safety measure to surely contain such gasses in whatever devices the crude oil and natural gas are contained, transported, etc. For example, some head space may be provided in a closed tank, a pipeline or other closed vessel transporting the treated liquid to assure that these gasses are not released into the environment.

[0009] The present inventors have previously proposed other treatment compositions and processes for remediating H₂S and other contaminants in various fluids, as set forth in International Application Nos. PCT/US2018/050913, PCT/US2018/064015 and US Patent No. 10,913,911, the contents of these Applications are incorporated herein by reference. The previously proposed treatment compositions and processes have proven to be very efficient for remediating sulfur-containing compounds, including H₂S, from hydrocarbon based liquids including crude oil, from contaminated aqueous solutions and from natural gas, much more so than other conventionally known treatment compositions and processes, and with no undesirable effects. [0010] The treatment composition and process disclosed in PCT/US2018/050913 involves an aqueous treatment composition containing primarily a high concentration of one or more hydroxides such as sodium hydroxide (NaOH) and potassium hydroxide (KOH), e.g., collectively the hydroxides account for 35-55 weight percent, and preferably at least 45 weight percent of the treatment composition, which efficiently react with H₂S to convert it to non-toxic substances. Other chemicals that may be included in the treatment composition will generally account for less than 10 wt% of the treatment composition. Such treatment composition according to the recent proposal is highly alkaline with a pH of 13 - 14. In such treatment process the treatment composition is added to the hydrocarbon based liquids or aqueous solutions being treated at appropriate dosage rates depending on multiple factors, and the hydroxide(s) in the solution efficiently remediate the H₂S and other sulfur-containing compounds down to acceptable levels within relatively short time periods, and without otherwise detrimentally affecting the hydrocarbon - petroleum based liquids or contaminated aqueous solutions in any significant manner. This proposed treatment solution may further include one or more other components depending on the specific characteristics of the liquids being treated and other factors relating to the remediation treatment process. For example, the treatment composition may include a silicate such as potassium silicate (K₂SiO₃) or barium (Ba) as an antibacterial agent, but the high concentration of hydroxide(s) in the treatment composition is a primary characteristic of the solution because this is important for efficient remediation of H₂S by the hydroxide(s) in the liquids being treated.

[0011] Such proposed treatment process is based on the inventors’ discovery that the conventional treatment methods using an aqueous solution consisting of up to 20% NaOH by weight is inefficient for remediating H₂S, and that the H₂S in contaminated liquids can be much more efficiently remediated using their proposed treatment composition containing a much higher collective concentration of one or more hydroxides. The inventors’ treatment process is not a wash type process, but involves rapid chemical reactions that greatly reduce the mass transfer of the gas to aqueous phase. What the treatment process does differently in comparison to the conventional treatment processes for remediating H₂S in hydrocarbon based liquids, is to essentially reduce the initial amount of water being added via the treatment solution to the minimum effective amount.

[0012] While it is known that H₂S gas is more soluble in oil than in water and that a rate -limiting step in the remediation of H₂S from crude oil is typically the mass transfer of H₂S from the oil phase into the aqueous phase, the inventors have discovered that: the liquid-liquid extraction aspect of the conventional methods is actually not that important in comparison to the chemical reaction aspect, e.g., because the initial solubility of H₂S into water, as given by Henry’s Law, is low; the larger amounts of water used in aqueous treatment solutions according to the conventional methods also function to dilute the NaOH and transfer the H₂S from the hydrocarbon liquid into the water without abating the H₂S, which is undesirable because this slows the process needed to produce ionized HS- and S₂- ions that allow more of the H₂S contained in the petroleum liquids into solution, and it is much more efficient and effective to remove the H₂S primarily though a chemical reaction process and to a much lesser degree a liquid-liquid extraction. The present inventors have also discovered that since the chemical reactions involved between hydroxides and H₂S, e.g., equations (1), (2) above, produce water, the produced water can readily diffuse through the hydrocarbon based liquid being treated as it is produced because the caustic solution has good migration tendencies in many hydrocarbon based liquids and the diffusion may also be enhanced by agitation and/or heating of the treated liquids. Correspondingly, they determined that it is unnecessary to add any significant amount of water in the treatment process apart from the water in the treatment composition in order for the hydrocarbon based liquid to be effectively treated for remediation of sulfur- containing contaminants, including H₂S, and other contaminants therein. Relative to the inventors’ discovery 1), it should be noted that equation (2) above is reversible, so large amounts of water hydrolyze the sodium sulfide (Na₂S) back to NaOH and NaHS. In other words, equation (2) in the reverse direction is a hydrolysis reaction.

[0013] Such recently proposed treatment process may involve use of a treatment composition including only one hydroxide such as sodium hydroxide (NaOH) or potassium hydroxide (KOH), but may also involve use of a combination of hydroxides for more completely reacting with most or all of the sulfides in the petroleum based liquids, noting that there are more than 300 species of sulfur compounds, although hydrogen sulfide H₂S is by far the main contaminant that must be remediated. Essentially any hydroxide compounds will work in the treatment process, but some hydroxide compounds work better for remediating different contaminants. Also, some hydroxide compounds are more expensive than others, e.g., NaOH and KOH are the most common hydroxide compounds sold in the world because they are the least expensive. For example, some other species of undesirable sulfur compounds include ethyl mercaptan (CH₃CH₂SH), dimethyl sufide (C₂H₆S), isobutyl mercatan (C₄H₁₀S) and methyl thiophene (C₅H₆S).

Sodium hydroxide is very effective for use in the treatment solution because it does not harm the petroleum based liquids when used in appropriate amounts, and is relatively inexpensive. Potassium hydroxide is more effective than sodium hydroxide for reacting with some species of sulfides. Hence, the treatment process involving potassium hydroxide (KOH) together with the sodium hydroxide achieves a more complete reaction with all of the sulfides contained in the hydrocarbon based liquids in comparison to just using a concentrated composition of sodium hydroxide.

[0014] In such proposed treatment process for remediating contaminated liquids, the treatment solution may be added at a standard dosage rate of 0.25 - 6.0 ml of the treatment solution I liter of the liquid being treated, preferably 1.0-5.0 ml of the treatment composition /liter of the liquid being treated, which corresponds to approximately 250-6000 ppm of the treatment composition in the liquid being treated based on the discussed concentration of hydroxide(s) in the composition. The discussed standard dosage rate is generally effective for remediating H₂S concentrations up to down to safe, acceptable levels. 40,000 ppm, 100,000 ppm and higher concentrations of H₂S may be experienced in some hydrocarbon based fluids such as crude oil and natural gas, although contaminated aqueous solutions typically have a much lower H₂S concentration such as 2000 ppm or less. If the amount of the treatment composition added is below 0.25 ml/liter of liquid being treated, sufficient remediation of H₂S may not be archived, and the reactions between the treatment composition and the sulfide compounds in the hydrocarbon based liquid may not proceed quickly and/or efficiently. If the concentration of H₂S is higher than 40,000 ppm it may be necessary to increase standard dosage amount of the recently proposed treatment composition appropriately, which may generally involve linear scalability. Dosage levels above 6.0 ml of the treatment composition / liter of the liquid being treated generally do not further reduce H₂S levels in the treated liquids where reaction times are not a consideration, but can advantageously reduce required reaction times if so desired.

[0015] Within the discussed standard dosage rate range, a most appropriate dosage amount of the treatment composition to be added to a contaminated liquid during the treatment process may be determined based on a few considerations, e.g., the amounts of H₂S and other contaminants in the liquid that need to be remediated, other characteristics of the liquid including its viscosity or API density (the term API as used herein, is an abbreviation for American Petroleum Institute), desired reaction rate/time, specific result desired including whether precipitate(s) are to be formed and released from the liquid, and whether the treated liquid is being mixed and /or heated during the treatment process. For example, mixing at moderate to high speeds to rapidly disperse the treatment composition throughout the treated liquid may reduce required reaction time by 50%, whereas some highly viscous liquids such as bunker fuel may require heating to permit proper dispersion of the treatment composition therein. The appropriate dosage rate is substantially, linearly scalable in relation to most or all of the various characteristics within the standard dosage rate range.

[0016] Advantageously, the proposed treatment process for treating contaminated liquids such as crude oil and contaminated aqueous solutions is generally efficient and effective as long as the amount of the treatment solution added is within the discussed standard dosage rate range, whether or not the amount of treatment composition added is the most appropriate dosage amount for the given liquid being treated. Further, use of higher amounts of the treatment composition may be desirable in some situations, and generally will not cause any significant problems or complications, although higher dosage amounts generally tend to cause precipitate(s) to be generated and released from the treated liquids. For example, the inventors have further determined that if an intentionally excessive dosage of the recently proposed treatment composition is added to a liquid being treated such as 2-5 times the standard dosage rates discussed above, this will likely cause remediated contaminants and other contaminants in the treated liquid to precipitate out of the treated liquid, which may be desirable in some situations. Also, depending on how much of the treatment composition is used in excess of the standard dosing rate, this may generate different precipitates which separate out of the treated liquid so that the outcome may be controlled in desired manners, e.g., at 2 times the standard dosing rate a hydrate of sodium sulfide such as Na₂S-9H₂O may precipitate out of the treated liquid according to the reaction (2) above, while at a higher dosage rate of 3 to 5 times the standard dosage rate, this may cause elemental sulfur to precipitate out of the treated liquid. Otherwise, the excess dosages of hydroxides in the treatment process will increase the cost of the treatment, but generally do not have any significantly adverse effects on the treated hydrocarbon based liquids and aqueous solutions. However, application of a very excessive amount of the composition, e.g., ten times the normal amount, may render the treated petroleum based liquid caustic which could be damaging to metals such as steel and aluminum used for containing and transporting the treated liquids.

[0017] Reaction times for the inventors’ recently proposed treatment process are typically within a relatively short time period such as 15 minutes - 24 hours after such treatment composition is added to the liquid at the discussed dosage rate, whether the liquid being treated is a hydrocarbon based liquid such as crude oil or a contaminated aqueous solution. Within such time period, the hydroxide(s) in the composition remediates the H₂S and other sulfur based contaminants down to safe, acceptable levels such as 5 ppm or less, and without generating or releasing any particularly harmful substances. For example, when the treatment composition includes sodium hydroxide (NaOH) as the primary hydroxide therein, e.g., at least 90 % of all hydroxides in the solution, much of the H₂S, e.g., at least 60% is converted into sodium bisulfide (NaHS) according to the reaction (1) above, which remains dissolved in the treated petroleum liquid, and does not create any significant problems that would need to be addressed. Additionally, some of the H₂S may be converted into sulfur dioxide (SO₂) gas which may be released from the treated petroleum based liquid, depending on the pressure at which the treated liquid is kept.

[0018] Very desirably, the proposed treatment process is generally not reversible in relation to the H₂S and other sulfur contaminants which have been remediated, e.g., even if the treated liquid is heated up to 180° F for a period of days or weeks, any remediated sulfur compounds remaining in the treated liquids do not revert back to H₂S. Some conventional treatment processes for remediating H₂S are undesirably reversible, including the conventional amine treatment process which uses an amine such as MEA or triazine for treating H₂S in crude oil. For example, with the conventional amine treatment process, while the H₂S may be initially remediated or abated down to acceptable levels, the sulfur contained in the treated oil may undesirably revert back to H₂S over time, especially if the treated oil is heated. Conversely, when crude oil which initially contained about 1000 ppm H₂S was treated according to a treatment process using the treatment composition according to the inventor’s recent proposal at a dosing rate of 3 ml / liter of oil and the H₂S was abated down to about 0 ppm and essentially none of the sulfur precipitated out of the oil, the treated crude oil was heated up to 180 - 300 °F or 82.2 - 148.9 °C for periods of hours, days and weeks, the resulting oil still contained about 0 ppm H₂S. Essentially none of the sulfur compounds(s) in the treated liquid reverted back to H₂S. [0019] According to a second proposal by the present inventors as discussed in PCT/US2018/064015, the first proposed treatment composition and process disclosed in PCT/US2018/050913 are modified or supplemented such that the contaminants in the treated liquids are not only remediated, but remediated in such a manner that essentially no precipitates or scale are generated in the treated liquids. In the first proposed treatment process if only a standard dosing rate of the treatment composition is added to a liquid being treated, there may be little or no precipitate(s), scaling or the like formed from the treated liquids, but even small amounts of precipitate(s), scaling or the like may be undesired or unacceptable in some situations. One particular application in which it is very important to assure that no precipitates, scale and the like will be generated from the treated hydrocarbon based liquids is when crude oil directly from the ground is being transported via tanker truck or other vessel to a major pipeline, which then transports the crude oil to a refinery. Some major pipelines generally will not accept crude oil containing more than 5 ppm H_?S. By treating the crude oil with a standard dosage of the treatment composition according to the proposal in PCT7US2018/050913, this would be effective to reduce the H₂S content down to 5 ppm or less, but it is possible that there would be some precipitates and/or scaling formed or deposited on surfaces of the tanker truck or other vessel transporting the crude oil, which would be undesirable.

[0020] According to the inventors’ proposal in PCT/US2018/064015, a relatively small amount of organic acid(s) such as fulvic acid and humic acid is also added to the treated liquid at a dosage rate that will typically result in a concentration of the organic acid(s) in the liquid being treated being in a normal range of 0.01 - 10 ppm, preferably 0.1- 3 ppm, whether the liquid is a hydrocarbon based liquid or contaminated aqueous solution. Within such range, the most appropriate dosage rate of the organic acid(s), like the most appropriate dosage rate of the first recently proposed treatment solution, largely depends on : 1) the amount of H₂S and other sulfur containing contaminants in the liquid being treated; 2) the viscosity of the liquid; and 3) the amount of time permitted for reacting the treatment solution with the liquid being treated, although heating and/or mixing of the liquid being treated will reduce the viscosity of the liquid and will also reduce the amount of time required for properly remediating the H₂S and other contaminants in the liquid. The dosage amount of organic acid(s) is substantially, linearly scalable within the discussed range based on these factors. Additionally, a small amount of monoethanolamine or MEA (C₂H₇NO) may be added to the treated liquid, along with the organic acid(s), e.g., an amount corresponding to a concentration of 0.5 - 15 ppm, and preferably 1.0 - 10 ppm, of the MEA in the hydrocarbon based liquid or aqueous solution being treated. The small amount of MEA acts as an anti-scaling agent in the second proposed treatment process / composition.

[0021] Fulvic acid is actually a family of organic acids, but may typically be identified as 1H,3H- Pyrano[4,3-b] [l]benzopyran-9-carboxylic acid, 4,10-dihydro-3,7,8-trihydroxy-3-methyl-10-oxo-; 3,7,8- trihydroxy-3-methyl-10-oxo-l,4-dihydropyrano[4,3-b]chromene-9-carboxylic acid, with an average chemical formula of C₁₃₅H₁₈₂O₉₅N₅S₂ and molecular weights typically in a range of 100 to 10,000 g/mol. Somewhat similarly, humic acid is a mixture of several molecules, some of which are based on a motif of aromatic nuclei with phenolic and carboxylic substituents, linked together, and the illustration below shows a typical structure. Molecular weight (size) of humic acid is typically much larger than that of fulvic acid, and can vary from 50,000 to more than 500,000 g/mol.

[0022] In the process for treating contaminated liquids according to the proposal disclosed in PCT/US2018/064015 the organic acid(s) which are also added to the liquids being treated assure that substantially no precipitate(s), scaling or the like will be formed from the treated liquids while they are being treated, transported and/or stored for a period of time such as hours, days or weeks. Further, to any extent that there is a increased likelihood that precipitate(s), scaling or the like may be formed in a treated liquid, e.g., the treated liquid contains an especially high content of H₂S and other sulfides requiring a larger dosage of the treatment solution according to the inventor’s recent proposal and/or the liquid being treated contains a high content of rag components such as organic matter, an increased amount of the organic acid(s) may be added to the treated liquid beyond the normal range of 0.01 - 10 ppm to assure that substantially no precipitate(s), scaling or the like will be formed.

[0023] The inventors’ recently proposed treatment processes for liquids may be conveniently carried out essentially wherever the contaminated liquids may be present, e.g., in open bodies of the liquids, in conjunction with a transport tanker or other vessel in which the liquids are being transported, at a wellhead where the liquids are being extracted from the ground, in open or closed tanks, in an enclosed pipeline through which the contaminated fluid(s) being transported, etc. [0024] Relative to treating contaminated gasses such as natural gas, US Patent No. 10,913,911 discusses that treating contaminated gasses is generally much more complicated than treating contaminated liquids such as crude oil and contaminated aqueous solutions, even when the primary contaminant for remediation in natural gas is H₂S just as H₂S is the primary contaminant for remediation in crude oil, due to a few significant complications associated with treating large volumes of contaminated natural gas on a continuous basis. For example: contaminated gasses such as natural gas often contain significant amounts of other contaminants in addition to H₂S, e.g., carbon dioxide (CO₂), nitrogen (N₂), water (H₂O), sodium chloride (NaCl), etc. which can great inefficiencies in gas treatment processes including that some of the contaminants including salt may tend to generate significant amounts of precipitates from the natural gas, which can greatly affect the treatment process; the nature of natural gas is much different from the nature of crude oil and other liquids, including that the value of natural gas on volume basis is much less than crude oil and that natural gas is typically, continuously discharged from a well at significant velocities, pressures and volumes, it is handled and processed much differently than liquids and this creates additional complications for treating contaminated gasses, e.g., a treatment process for remediating a contaminated gas such as natural gas may only permit contact between the treatment composition and the contaminated gas for a few seconds. On the other hand, for treating contaminated liquids the time involved in a treatment process for remediation of contaminants may be an hour or more, but this is typically not a problem as the treatment composition may be simply mixed or provided with the contaminated liquid and then let sit for the time required for the H₂S and other contaminant(s) in the liquid to be remediated.

[0025] As explained in US Patent 10,913,911, one of the present inventors has proposed a new treatment composition and a new treatment process for remediating contaminated natural gas. The treatment composition is similar to that disclosed in PCT/US2018/064015 but may further includes relatively small amounts of a chelating agent such as ethylenediaminetetraacetic acid (EDTA), which among other things increases the efficiency of hydroxide compounds in remediating H₂S, a surfactant such as sodium lauryl sulphate and a buffering agent such as potassium carbonate, etc. However, the treatment process for treating the contaminated natural gas is much more involved than the treatment process for treating a contaminated liquid such as crude oil as disclosed in US Patent 10,913,911, e.g., it may involve additional treatment steps and equipment for removing water, salts, etc., in addition to the a step of remediating H₂S with the treatment composition.

[0026] Generally a typical oil well may discharge 5 to 30,000 barrels of crude oil and 1-20 million ft³ of natural gas / day, as well as 200,000 - 250,000 barrels of contaminated water as a mixed fluid. Further, most oil wells will have a 3-way separator provided in association therewith which separates these three fluids into a gas phase, a hydrocarbon liquid phase and an aqueous liquid phase, whereby the crude oil and the natural gas may separately output from the separator for treatment, e.g., the crude oil may be sent by truck and/or pipeline to a refinery and natural gas may be sent by pipeline to a refinery. Some such pipelines restrict acceptance of the crude oil and natural gas based on the content of H₂S contained therein being at or below a predetermined level such as 5 ppm for multiple reasons, including that H₂S can be very corrosive - damaging to the pipelines. Many oil wells around the world have separators associated therewith which separate the different fluids that are extracted from the wells, e.g., some have three-way separators which separate hydrocarbon based liquids, gasses and aqueous based liquids from each other, some have two-way separators associated therewith which jointly output natural gas and crude oil as one output for further processing and contaminated aqueous based liquids as the other output, which may be disposed of by injecting back downhole into the earth, etc. Some oil wells around the world do not have separators associated therewith, e.g., for some such wells all of the fluids that are extracted from the wells are jointly piped to refineries for further processing. Further, the pipelines that handle a mixture of fluids such as crude oil and natural gas may be formed of specialty steels and other materials which can accept a much higher content of H₂S contained in the mixed fluid, e.g., the content may be as high as 20,000 ppm. For such contaminated, mixed fluids, it still remains a challenge in the art for reducing content of H₂S

SUMMARY OF THE INVENTION

[0027] An object of the present invention is to satisfy the discussed need.

[0027] The present inventors have carefully investigated this, and have discovered a new treatment system and methods for efficiently remediating the H₂S and other contaminants in such fluid mixtures containing both contaminated liquid(s) and contaminated gas(ses) using treatment compositions such as disclosed in PCT/US2018/064015 and USSN 16/857,884, and variations thereof.

[0028] One discovery made by the present inventors is that when the previously proposed treatment compositions and variations thereof are used for treating a continuously flowing, large volume of a mixture of fluids highly contaminated with H₂S and other contaminants, e.g., a continuously flowing mixture of crude oil, produced water and natural gas from a well, such fluid mixture may be efficiently and effectively treated for remediation of the H₂S and other contaminants by adding appropriate dosage(s) of a treatment composition such as those disclosed in PCT/US2018/064015, US Patent No. 10,913,911 and variations thereof to the contaminated fluid mixture as a mixture of the fluids is extracted from a well, and possibly also after the fluids have been separated by the separator. Then as the fluid mixture having the treatment composition combined therewith continues to flow in a pipeline or other transportation means toward to a refinery, e.g., typically tor many miles and over a period of hours, the treatment composition will react with and remediate the H₂S and other contaminants in all of the mixed fluids, both liquid and gaseous, such that the content of these contaminants will be significantly reduced by the time the fluid mixture arrives at the refinery, and very importantly essentially no precipitates will be discharged from the treated fluid mixture. Discharge of any amount of precipitate(s) from the treated fluid mixture is very undesirable as this may partially or completely clog the pipeline, and that would require the pipeline to be shut down for corrective action. The inventors have determined that even if the contaminated fluid mixture contained a relatively high content of H₂S when it is extracted from the well, e.g., 40,000 ppm, 60,000 ppm and higher for the fluid mixture, the content of the H₂S in the liquid portion of the mixture, e.g., crude oil, may be reduced down below 5 ppm and the content of the H₂S in the gaseous portion of the mixture, e.g., natural gas, may be reduced down below 20,000 ppm.

[0029] For effecting such treatment process, the inventors have determined that the treatment composition may be added to the fluid mixture as it is extracted from the well and/or after the fluid mixture has passed through a separator to remove liquid, water based component therefrom. For example, the inventors have determined that a first dosage of the treatment composition may be added to the fluid mixture as it is extracted from a well, so that treatment composition may remediate some of the H₂S and some other contaminants in all the fluids of the fluid mixture, and then such treated fluid mixture may be passed through a separator to remove liquid, water based component(s) therefrom, after which an additional amount of the treatment composition may be added to the remaining fluid mixture of crude oil and natural gas to further remediate any H₂S and some other contaminants remaining in the fluids. The inventors have determined that when the treatment composition is added to the fluid mixture as it is extracted from the well, the dosage amount of the treatment composition added to the mixture should be appropriate for raising pH of the fluid mixture from an initial pH value of 5-6 to a pH value between 9.0 and 10, preferablyy between 9.5 and 10, for achieving optimum results. If the pH is raised to a value above 10 this may likely cause some precipitates, including salts, rag contaminants, etc., to be released from the treated fluid mixture, which would be undesirable because this may clog the pipeline through which the treated fluid mixture is flowing. With such treatment of the fluid mixture as it is extracted from a well, the H₂S in the liquid components of the mixture, e.g., oil and water, are typically reduced to very low values such as 5 ppm or less, although the H₂S in the gaseous components of the mixture, e.g., natural gas, is typically reduced to about 1/3 to Vi of its original value. The treated fluid mixture may then be passed through a separator to remove the liquid, water based component(s) from the oil and gas components. The liquid, water based component(s) will have little or no H₂S remaining therein, although these component(s) will still contain significant amounts of other contaminants, including salts and rag components, and may be disposed of by being injected back into the earth, via a salt water disposal well. After being discharged from the separator, a mixture of the partially oil and gas components may then have additional dosages of the treatment composition added thereto, which will further remediate any H₂S and some other contaminants remaining in the mixture as the oil and natural gas are transported for further processing, e.g., at a refinery. Given that the H₂S in the oil may already be remediated down to 5 ppm or less through the initial dosage of the treatment composition added to the fluid mixture as it is extracted from the well, the additional dosages of the treatment composition primarily function to further remediate the H₂S and some other contaminants in the natural gas, while the oil in the fluid mixture also functions as a vehicle for containing the treatment composition such that the treatment composition will have significant contact with the natural gas as the mixture of the oil, gas and treatment composition flows along the pipeline.

[0030] For purposes of adding additional dosages of the treatment composition to the oil and gas mixture after the liquid water component(s) have been separated therefrom via the separator, one appropriate system that may be used involves use of a reactor, which may be oriented in any direction, in which the oil and natural gas mixture from the separator continuously flows into a lower portion of the reactor, an amount of the treatment composition is added to the fluid mixture before the fluid mixture enters the reactor and/or to the fluid mixture in the reactor so as to achieve a desired concentration of the treatment composition / unit volume of the fluid mixture, some of the fluid mixture as combined with the treatment composition is continuously withdrawn from an upper portion of the reactor, and the withdrawn portion will then flow along a pipeline toward another pipeline that will send the fluid mixture to a refinery or other destination giving time for the treatment composition to react with and remediate the H₂S and other contaminants in the fluid mixture. To any extent that the fluid mixture being treated contains a significant amount of gas, one appropriate manner of flowing the fluid mixture into the reactor is via numerous small openings formed in pipe(s) extending longitudinally along the lower portion of the reactor , whereby the fluid mixture will enter the reactor in the form of small fluid streams containing bubbles of the gas that cause the fluid streams to flow upward through other fluid already in the reactor so as to mix with the same, and the fluid being withdrawn from the upper portion of the reactor will have a substantially homogeneous - uniform content of the treatment composition. For continuously adding the treatment composition to the reactor, the concentration of the treatment composition in the fluid mixture being withdrawn from the reactor may be monitored to determine if the rate of at which the treatment composition is being added needs to be adjusted, while a portion of the mixed fluid in the reactor may be continuously withdrawn from a bottom portion of the reactor, mixed with additional treatment composition and then again flowed into the reactor along with additional mixed fluid from the separator. As an alternative to using a reactor for adding further dosage of the treatment composition to the oil and gas mixture, additional dosage of the treatment composition may be simply, directly added to the oil and gas mixture as it flows through a pipeline or other transportation means.

[0031 ] Although maintaining pH of the treated fluid mixture in a range of 9.0 to 10 as the mixture is extracted from the earth is important for preventing release of precipitates such as salts, rag components, etc., once the liquid, water based components are separated from the oil and natural gas, there is little or no concern regarding release of precipitates such as salts, rag components, etc. because these contaminants mostly remain in the liquid, water based component(s). Hence, pH of the mixture of oil and natural gas may be increased above 10 when additional dosages of the treatment composition are added thereto after the liquid, water based component(s) are separated from without having concern that precipitates will be released from the further treated oil and gas mixture. However, maintaining the pH of the further treated oil and gas mixture in the range of 9.5 to 10 would still be appropriate for further remediating H₂S and some other contaminants in the oil and natural gas fluid mixture. Raising the pH above 10 for the further treated mixture may not achieve any better results than maintaining pH of the further treated mixture in the range of 9.5 to 10, but would require greater dosage amount(s) of the treatment composition and would be cost more for the treatment.

[0032] The inventors have discovered that for such treatment system and process, treatment compositions such as disclosed in PCT/US2018/064015 and USSN 16/857,884, as well as variations thereof, are appropriate for treating the contaminated fluid mixtures, and these compositions perform similar functions when treating the contaminated fluid mixture containing two or more of crude oil, produced water and natural gas. The treatment composition disclosed in PCT/US2018/064015 primarily includes, e.g., as at least 80 wt % and preferably at least 90 wt %, of the treatment composition, a concentrated aqueous hydroxide solution with 35-55 wt % of one or more hydroxide compounds as the main component, together with a small amount, e.g., 0.1-4 wt% of an organic acid such as fulvic acid or humic acid, and possibly small amounts of MEA, e.g., 0.1-3 wt%, and /or an antibacterial compound such as potassium silicate. The concentrated hydroxide compound(s) react with H₂S to remediate same, while the organic acids such as fulvic acid and humic acid function to prevent any precipitates from being generated and released from the treated fluid, and MEA functions as an anti-scaling agent. On the other hand, the treatment composition disclosed in US Patent No. 10,913,911 may also primarily include, e.g., as at least 80 wt % and preferably at least 90 wt %, of the treatment composition, a concentrated aqueous hydroxide solution having a high concentration of one or more hydroxide compound! s), ^c-g-- 35-55 wt % of one or more hydroxide compounds as the main component, together with 0.1-4 wt% of an organic acid such as fulvic acid or humic acid, 0.2 - 5 wt %, of ethylenediaminetetraacetic acid or EDTA (CioIUsNjpg) which is a type of chelating agent that, among other things, helps to improve molar reactivity of the hydroxide compound^) and helps to prevent formation of precipitates, and possibly smaller amounts, e.g., 0.01 - 0.1 % volume, of a surfactant such as sodium lauryl sulphate, a buffering agent such as potassium carbonate, etc.

[0033] Appropriate dosage amounts of such treatment compositions will, of course, be based on amount of the fluid mixture being treated. For a typical oil well with well head piping outlet having a diameter of 2-10 inches and an output of 5,000-10,000 barrels of crude oil and 10 million to 20 million ft’ of natural gas / day (24 hours) and wherein the H₂S content of the mixed fluid is 40,000 ppm to 60,000 ppm or higher, the inventors have found that an appropriate total amount of treatment composition may be in a range of 5 to 20 gallons of treatment composition added per hour or 120 - 480 gallons per day. Of this amount of the treatment composition, part such as 14 to % of the total amount may be added to the fluid mixture which is extracted from the earth, and the balance may be added after the water based components are separated from the oil and natural gas via the separator. The inventors have determined that under these conditions the treated crude oil in the final fluid mixture will be reduced to less than 5 ppm II₂S and often 0 ppm H₂S, while the treated natural gas in the mixed fluid will be reduced by 50 to 70 % and will typically have less than 15,000 ppm H₂S.

Intent of Disclosure

[0034] Although the following disclosure of exemplary embodiments of the invention offered for public dissemination is detailed to ensure adequacy and aid in understanding of the invention, this is not intended to prejudice that purpose of a patent which is to cover each new inventive concept therein no matter how it may later be disguised by variations in form or additions of further improvements. The claims at the end hereof are the chief aid toward this purpose, as it is these that meet the requirement of pointing out the improvements, combinations and methods in which the inventive concepts are found.

BRIEF DESCRIPTION OF DRAWINGS

[0035] FIG. 1 is a schematic diagram of a system for remediating a contaminated fluid mixture according to an exemplary embodiment of the present invention.

DETAILED DESCRIPTION OF PRESENT EXEMPLARY EMBODIMENTS

[0036] Exemplary embodiments of the present invention will be described below. Primary aspects of the present invention involve use of novel treatment compositions in treatment compositions for remediating contaminated fluid mixtures of liquids and/or gasses such as a mixture of crude oil and natural gas from a well. Again, FIG. 1 is a schematic diagram of a treatment system which may be used in an exemplary embodiment of the present invention.

[0037] Referring to FIG. 1 , there is shown a system 100 for remediating contaminated mixed fluids according to an exemplary embodiment of the present invention. The system 100 may generally a well 10 which outputs a fluid mixture of crude oil, produced water and natural gas, an first treatment station 50 at which a first dosage of treatment composition is added to fluid mixture from the well, a separator 104 which receives fluids output from the well 10 after the first dosage of the treatment composition has been added at the station 50 and separates the liquid, water based component(s) of the fluid mixture from the oil and natural gas components of the mixture, a reactor 102 which is depicted as extending horizontally but may extend in any direction and receives an oil and natural gas mixture from the separator 104, a discharge nozzle 106 which discharges the mixed fluid into the reactor, a discharge outlet 108 which discharges the fluid mixture from the reactor after treatment composition has been added thereto, a supply of the treatment composition 110, a re-circulation pump 112 which withdraws a portion of the mixed fluid from the reactor 102 via a discharge outlet 114 at a bottom of the reactor, adds an appropriate dosage of treatment composition from the supply 100 thereto and then adds the fluid mixture and treatment composition to the flow of untreated fluid mixture from the separator 104 which is flowing into the reactor. A controller 116 such as a programmed electronic processing unit (ECU) may be provided for controlling operations of the system 100, and the controller would receive various inputs from sensor(s) (not shown) pertaining to characteristics of the system and the fluid mixture. The fluid mixture from the well 10 having the treatment composition added at station 50 should be permitted to react for at least 30 seconds or more before going into the spearator, and this may be achieved by providing a pipeline between the station 50 and the separator 104 having appropriate length, etc.

[0038] The inventors have determined that when the first dosage of the treatment composition is added to the fluid mixture as it is extracted from the well, the dosage amount of the treatment composition added to the mixture should be appropriate for raising pH of the fluid mixture from an initial pH value of 5-6 to a pH value between 9.0 and 10, preferably between 9.5 and 10, for achieving optimum results. If the pH is raised to a value above 10 this may likely cause some precipitates, including salts, rag contaminants, etc., to be released from the treated fluid mixture, which would be undesirable because this may clog the pipeline through which the treated fluid mixture is flowing. For example, With such treatment of the fluid mixture as it is extracted from a well, the H₂S in the liquid components of the mixture, e.g., oil and water, are typically reduced to very low values such as 5 ppm or less, although the H₂S in the gaseous components of the mixture, e.g., natural gas, is typically reduced to about 1/3 to ½ of its original value. The treated fluid mixture may then be passed through a separator to remove the liquid, water based component(s) from the oil and gas components. The liquid, water based component(s) will typically have little or no H₂S remaining therein, although these component(s) will still contain significant amounts of other contaminants, including salts and rag components, and may be disposed of by being injected back into the earth, via a salt water disposal well.

[0039] After being discharged from the separator, a mixture of the partially oil and gas components may then have additional dosages of the treatment composition added thereto via the system of the present invnetion, which will further remediate any H₂S and some other contaminants remaining in the mixture as the oil and natural gas are transported for further processing, e.g., at a refinery. Given that the H₂S in the oil may already be remediated down to 5 ppm or less through the initial dosage of the treatment composition added to the fluid mixture as it is extracted from the well, the additional dosages of the treatment composition primarily function to further remediate the H₂S and some other contaminants in the natural gas, while the oil in the fluid mixture also functions as a vehicle for containing the treatment composition such that the treatment composition will have significant contact with the natural gas as the mixture of the oil, gas and treatment composition flows along the pipeline.

[0040] For purposes of adding additional dosages of the treatment composition to the oil and gas mixture after the liquid water component(s) have been separated therefrom via the separator 104, one appropriate system that may be used involves use of a reactor such as the reactor 102 in FIG. 1, which may be oriented in any direction. The oil and natural gas mixture from the separator may continuously flow into a lower portion of the reactor 102, an amount of the treatment composition 110 is added to the fluid mixture before the fluid mixture enters the reactor and/or to the fluid mixture in the reactor so as to achieve a desired concentration of the treatment composition I unit volume of the fluid mixture, some of the fluid mixture as combined with the treatment composition is continuously withdrawn from an upper portion of the reactor, and the withdrawn portion will then flow along a pipeline toward another pipeline that will send the fluid mixture to a refinery or other destination giving time for the treatment composition to react with and remediate the II₂S and other contaminants in the fluid mixture. To any extent that the fluid mixture being treated contains a significant amount of gas, one appropriate manner of flowing the fluid mixture into the reactor is via numerous small openings formed in discharge nozzle 106 extending longitudinally along the lower portion of the reactor , whereby the fluid mixture will enter the reactor in the form of small fluid streams containing bubbles of the gas that cause the fluid streams to flow upward through other fluid already in the reactor so as to mix with the same, and the fluid being withdrawn from the upper portion of the reactor will have a substantially homogeneous - uniform content of the treatment composition. For continuously adding the treatment composition to the reactor, the concentration of the treatment composition in the fluid mixture being withdrawn from the reactor may be monitored to determine if the rate of at which the treatment composition is being added needs to be adjusted, while a portion of the mixed fluid in the reactor may be continuously withdrawn from a bottom portion of the reactor, mixed with additional treatment composition and then again flowed into the reactor along with additional mixed fluid from the separator. As an alternative to using a reactor for adding further dosage of the treatment composition to the oil and gas mixture, additional dosage of the treatment composition may be simply, directly added to the oil and gas mixture as it flows through a pipeline or other transportation means. [0041] Although maintaining pH of the treated fluid mixture in a range of 9.0 to 10 as the mixture is extracted from the earth is important for preventing release of precipitates such as salts, rag components, etc., once the liquid, water based components are separated from the oil and natural gas, there is little or no concern regarding release of precipitates such as salts, rag components, etc. because these contaminants mostly remain in the liquid, water based component(s). Hence, pH of the mixture of oil and natural gas may be increased above 10 when additional dosages of the treatment composition are added thereto after the liquid, water based component(s) are separated from without having concern that precipitates will be released from the further treated oil and gas mixture. However, maintaining the pH of the further treated oil and gas mixture in the range of 9.0 to 10 would still be appropriate for further remediating H₂S and some other contaminants in the oil and natural gas fluid mixture. Raising the pH above 10 for the further treated mixture may not achieve any better results than maintaining pH of the further treated mixture in the range of 9.0 to 10, but would require greater dosage amount(s) of the treatment composition and would be cost more for the treatment.

[0042] The reactor 102 may be formed of an appropriate material such as carbon steel which is resistant to reacting with the mixed fluid and the contaminants in the mixed fluid including H₂S, and may have an appropriate size based on the volume of mixed fluid being treated. For example if the volume of mixed fluid being treated is 5,000-10,000 barrels of crude oil and 10 million to 20 million ft³ of natural gas / day (24 hours), an appropriate size for the reactor 102 may be 5-10 feet in diameter and 12-25 feet long.

[0043] The discharge nozzle 106 may include one or more pipe(s) extending longitudinally along the lower portion of the reactor and having numerous small openings formed therein in pipe(s), whereby the fluid mixture will enter the reactor in the form of small fluid streams containing hubbies of the gas in the mixture. The pressure of the mixed fluid stream and the gas bubbles will cause fluid streams from the numerous small openings to flow upward through a large quanti ty of the mixed fluid and treatment composition already in the reactor so as to thoroughly mix with the same. By the time that the mixed fluid and treatment composition reaches the upper portion of the reactor where a portion of the same is discharged through the outlet 108 the mixed fluid and treatment composition are combined in a homogenous mixture.

[0044] The re -circulation pump 112 may be any appropriate type of pump, but the inventors have found that a pneumatic - diaphragm pump works appropriately for not only for re-circulating and mixing the mixed fluid with treatment composition from the supply 110, but also for maintaining an appropriate, desired concentration of the treatment composition in the reactor and in the mixed fluid discharged from the reactor through outlet 108. A portion of the mixed fluid in the reactor may be continuously withdrawn from a bottom portion of the reactor, mixed with additional treatment composition and then again flowed into the reactor along with additional mixed fluid from the separator. For continuously adding the treatment composition to the reactor, the concentration of the treatment composition in the mixed fluid being withdrawn from the reactor may be monitored to determine by a sensor (not shown). If the rate at which the treatment composition is being added needs to be adjusted based on the sense value, the rate at which the treatment composition is added via the re -circulation pump 112 may be appropriately adjusted by the controller 116.

[0045] The present inventors have discovered that when the previously proposed treatment compositions such as disclosed in PCT/US2018/064015 and US Patent No. 10,913,911, and variations thereof tire used for treating a continuously flowing, large volume of a fluid mixture highly contaminated with H₂S and other using the treatment system treatment process as shown in FIG.l, such fluid mixture may be efficiently and effectively treated for remediation of the H₂S and other contaminants. After being combined with the treatment composition in the reactor 102 and being discharged from the outlet 108 the fluid mixture may continue to flow in a pipeline or other means toward a refinery, e.g., typically the fluid mixture with the treatment composition combined therewith may flow for many miles and over a period of hours toward a refinery or other destination, and while flowing the treatment composition will react with and remediate the H₂S and other contaminants in both the liquid and gaseous components of such fluid mixture such that the content of these contaminants will be significantly reduced by the time the fluid mixture arrives at the pipeline leading to the refinery. Very importantly, essentially no precipitates will be discharged from the treated fluid while it is flowing toward the refinery or other destination due in large part to the presence of the organic acid(s) such as fulvic acid and humic acid in the treatment composition. Discharge of any amount of precipitate(s) from the treated fluid is very undesirable as this may partially or completely clog the pipeline, and would require the pipeline to be shut down for corrective action. The inventors have determined that even if the contaminated fluid mixture contained a relatively high content of H₂S when it was discharged from the separator, e.g., 40,000 ppm, 60,000 ppm or higher, the content of the H₂S in the liquid portion of the mixture, e.g., crude oil, may be reduced down below 5 ppm and the content of the H₂S in the gaseous portion of the mixture, e.g., natural gas, may be reduced down below 15,000 ppm and without formation or release of any appreciable amount of precipitate(s) from the treated fluid mixture. Generally, natural gas having less than 20,000 ppm of H₂S is considered to be saleable even if the natural gas requires further processing for removing most of the H₂S and other contaminants.

[0046] Again, the present inventors have discovered that for such treatment system and process, treatment compositions such as disclosed in PCT/US2018/064015 and US Patent No. 10,913,911, as well as variations thereof, are appropriate for treating the contaminated fluid mixture, such as crude oil, and these components perform similar functions when treating the contaminated fluid mixture containing liquid(s) such as crude oil and gas(ses) such as natural gas. The treatment composition disclosed in PCT/US2018/064015 primarily includes, e.g., as at least 80 wt % and preferably at least 90 wt %, of the treatment composition, a concentrated aqueous hydroxide solution with 35-55 wt % of one or more hydroxide compounds as the main component, together with a small amount, e.g., 0.1-4 wt% of an organic acid such as fulvic acid or humic acid, and possibly small amounts of MEA, e.g., 0.1-3 wt%, and /or an antibacterial compound such as potassium silicate. The concentrated hydroxide compound(s) react with H₂S to remediate same, while the organic acids such as fulvic acid and humic acid function to prevent any precipitates from being generated and released from the treated fluid, and MEA functions as an anti-scaling agent. On the other hand, the treatment composition disclosed in US Patent No. 10,913,911 may also primarily include, e.g., as at least 80 wt % and preferably at least 90 wt %, of the treatment composition, a concentrated aqueous hydroxide solution having a high concentration of one or more hydroxide compound(s), e.g., 35-55 wt % of one or more hydroxide compounds as the main component together with a small amount, e.g., , e.g., 0.2 - 5 wt %, of ethylenediaminetetraacetic acid or EDTA (C₎₀H_!6N₂O_s) which is a type of chelating agent that, among other things, helps to improve molar reactivity of the hydroxide compound(s) and helps to prevent formation of precipitates, and possibly smaller amounts, e.g., 0.01 - 0.1 % volume, of a surfactant such as sodium lauryl sulphate, a buffering agent such as potassium carbonate, etc. The pH of such treatment compositions according to the present invention is approximately 14 based on the high concentration of hydroxide compound(s) in the compositions.

[0047] An appropriate amount of such treatment compositions will, of course, be based on amount of the mixed fluid being treated. For a typical oil well with well head piping having a diameter of 2-10 inches and an output of 5,000-10,000 barrels of crude oil and 10 million to 20 million ft³ of natural gas / day (24 hours) and wherein the H₂S content of the mixed fluid at 40,000 ppm, 60,000 ppm or higher, the inventors have found that an appropriate amount of treatment composition is in a range of 5 to 20 gallons of treatment composition added per hour or 120 - 480 gallons per day. In other words, 5 to 20 gallons of treatment composition added per hour based on a volume of the mixed fluid of 205 - 420 gallons / hour of liquid and 416,667 - 833,333 ft³/ hour of gas. Of this amount of the treatment composition, part such as ^s,4 to % of the total amount may be added to the fluid mixture which is extracted from the earth at station 50, and the balance may be added after the water based components are separated from the oil and natural gas via the separator 104. The inventors have determined that under these conditions the treated crude oil in the mixed fluid will have less than 5 ppm H₂S and often 0 ppm H₂S, while the treated natural gas in the mixed fluid will have less than 20,000 ppm H₂S. Further, it should be noted that the pipelines through which the mixed crude oil and natural gas flow often have bacterial growing therein, e.g., which is attached to the walls of the pipeline, and that such bacterial may be a problem for helping ELS and other sulfurbased contaminants remain in or become regenerated in the mixed fluid. Hence, the amount of treatment composition which is added to mixed crude oil and natural gas according to the present invention may initially be at a higher rater within the discussed range of 5 to 20 gallons of treatment composi tion added per hour so that the treatment composition may kill the bacteria, and after a period of time sufficient to kill the bacteria the dosage rate may be reduced to a lower value within the range.

[0048] In the above exemplary embodiment of a treatment system and treatment process according to the present invention the fluids being discharged from a well are initially separated before the treatment composition is added to the fluid mixture. However, it is not required that the fluids from the well be initially separated from each other before a treatment composition according to the present invention is added to the fluid mixture. For example, the system 100 of FIG. 1 including the reactor 102 may be omitted and an appropriate dosage of the treatment composition may be delivered directly into the pipeline through which the fluid is flowing toward a refinery or other destination. As the fluid mixture containing the treatment composition flows along the pipeline they will be thoroughly mixed together and the treatment composition will significantly remediate contaminants in the fluid mixture to essentially the same extent as when the treatment composition is added to the fluid mixture using the system 100. Such a treatment process not involving the system 100 would be appropriate if the fluid mixture being output from a well is going to be directly delivered to a refinery or if the system 100 is not available.

Example of Invention Embodiment

[0049] The inventors have conducted a specific an example of the present invention on an actual well, and the specific characteristics and results of the example are as follows.

Treatment Composition

The treatment composition used in the example was aqueous based and primarily included at approximately 94-96 wt %, of the treatment composition a concentrated aqueous hydroxide solution having about 25 wt % of each of NaOH and KOH, or about 50 wt % collectively of these two hydroxide compounds as the main component together with about 1-2 wt % of fulvic acid, a 2-3 wt% of EDTA and about 0.1 % volume of sodium lauryl sulphate. The pH of such treatment compositions according to the present invention is approximately 14. Based on the output of the well a dosage rate of the treatment composition varied between eight (8) and sixteen (16) US gallons / hour, with an average dosage rate of about ten (10) gallons /hour. In this example about Tz of the treatment composition was added in the first dosage at station 50 and the rest of the treatment composition was added to the oil and natural gas fluid mixture in the reactor 104. Characteristics of the Well

The well from which the contaminated fluid mixture of oil, produced water and natural gas was extracted output about 6,000 barrels of crude oil /day, about 42,000 - 50,000 barrels of produced water and about 14.5 million ft³ /day of natural gas, and after the produced water was separated from the crude oil and natural gas a mixture of the oil and gas contained about 40,000 ppm of H₂S.

System which Combines the Fluid Mixture with Treatment Composition and Results A system used for effecting the treatment process was the system as shown in FIG. 1, which included the first station 50 at which about Yz of the treatment composition was added to the fluid mixture from the well 10 so as to achieve a pH of between 9.0 and 10, preferably between 9.5 and 10, the separator 104 which separated the liquid water based component(s) from the mixture and discharged these component(s) to waste, and discharged the remaining oil and natural gas mixture for further processing, a horizontally aligned reactor such as the reactor 102 and formed of carbon steel, and a pneumatic diaphragm, constant re-circulation pump such as recirculation pump 112. The fluid mixture of oil and natural gas, as well as the treatment composition, were introduced into the reactor near its bottom, the fluid mixture having the treatment composition homogeneously mixed therein was withdrawn near the top of the reactor. The reactor had a diameter of six (6) feet and a length of fifteen (15) feet. Further, an amount of fluid mixture with the treatment composition was constantly withdrawn from the reactor, additional treatment composition was added to the withdrawn fluids to maintain the treatment composition at an appropriate concentration in the fluid mixture, and then the withdrawn fluid and added treatment composition were then delivered back into the reactor along with additional amounts of the oil and natural gas mixture from the well.

After the fluid mixture having the treatment composition homogeneously mixed therein was withdrawn near the top of the reactor it then flowed through a pipeline several miles long and for more than two (2) hours. This was sufficient to allow the treatment composition to substantially fully react with the contaminants in the fluid mixture. Very desirably, no appreciable amount of precipitates was released from the treated fluid mixture as it flowed through the pipeline. The fluid mixture was then tested to determine effects of the treatment composition on the contaminants in the fluid mixture. The testing showed that the crude oil in the fluid mixture contained no H₂S, while the H₂S in the natural gas of the treated fluid mixture was reduced 65% to about 14,000 ppm, making the treated natural gas appropriate for sale. [0050] The foregoing description is given for clearness of understanding only, and no unnecessary limitations should be understood therefrom, as modifications within the scope of the invention may be apparent to those having ordinary skill in the art and are encompassed by the claims appended hereto. For example, while the exemplary embodiment of the treatment system 100 includes the re-circulation pump 112 which not only withdraws some portion of the mixed fluid from the reactor 100 but also adds treatment composition from the supply 110 and then flows these into the fluid stream from the separator 104, it is certainly possible to separately add the treatment composition to the reactor 102 without use of the pump 112 and for the fluid output of the pump to be separately flowed into the reactor apart from the mixed fluid stream from the separator 104.

Claims

We claim:

1. A treatment composition for remediating for remediating H2S and other contaminant(s) in a fluid mixture of contaminated liquids and gasses comprising; an aqueous hydroxide solution containing at least one hydroxide compound; at least one organic acid selected from the group consisting of fulvic acid and humic acid; and a chelating agent, wherein the aqueous hydroxide solution constitutes at least 80 wt% of the treatment composition, the at least one organic acid constitutes 0.1 - 4.0 wt% of the treatment composition and a pH of the treatment composition 14.0.

2. The treatment composition according to claim 1, wherein the chelating agent constitutes 0.1 - 5 wt% of the treatment composition.

3. The treatment composition according to claim 2, wherein the chelating agent includes ethylenediaminetetraacetic acid (EDTA).

4. The treatment composition according to claim 1, further comprising at least one of a surfactant and a buffering agent.

5. The treatment composition according to claim 1, wherein the at least one hydroxide compound at a collective concentration of 45-55 weight percent of the aqueous hydroxide solution and the aqueous hydroxide solution constitutes at least 90 wt% of the treatment composition.

6. The treatment composition according to claim 1, wherein the at least one hydroxide compound includes at least one of NaOH and KOH.

7. The treatment composition according to claim 1, wherein the at least one organic acid includes fulvic acid.

8. A treatment process for remediating H2S and other contaminants in a fluid mixture of contaminated liquid and contaminated gas, comprising steps of : adding a dosage of the treatment composition of claim 1 to the fluid mixture to bring a pH of the fluid mixture having the treatment composition added thereto to be in a range of 9.0 and 10, and flowing the fluid mixture having the treatment composition added thereto trough a pipeline to permit the treatment composition to remediate contaminants in the fluid mixture.

9. The treatment process according to claim 8, wherein the fluid mixture contains a liquid water based component, a liquid hydrocarbon based component and a natural gas component jointly extracted from the earth.

10. The treatment process according to claim 9, including further steps of : after permitting the treatment composition to remediate contaminants in the fluid mixture, separating the liquid water based component from the liquid hydrocarbon based component and the natural gas component, discharging the liquid hydrocarbon based component and the natural gas component as a fluid mixture, adding a further dosage of the treatment composition to the fluid mixture of the liquid hydrocarbon based component and the natural gas component, and permitting the treatment composition to further remediate contaminants in the fluid mixture of the liquid hydrocarbon based component and the natural gas component.

11. The treatment process according to claim 10, wherein a dosage amount of the treatment composition added to the fluid mixture which brings the pH of the fluid mixture having the treatment composition added thereto to be in a range of 9.0 and 10 is *4 to % of an amount of the further dosage of the treatment composition added to the fluid mixture of the liquid hydrocarbon based component and the natural gas component.

12. The treatment process according to claim 10, wherein the step of adding a further dosage of the treatment composition to the fluid mixture of the liquid hydrocarbon based component and the natural gas component involves flowing the fluid mixture of the liquid hydrocarbon based component and the natural gas component into a lower portion of a reactor, adding the further dosage of the treatment composition to the fluid mixture in the reactor, and withdrawing a portion of the fluid mixture having the treatment composition added thereto from an upper portion of the reactor, wherein a collective dosage of the treatment composition added to the fluid mixture is 5 to 20 gallons of treatment composition added per hour based on a volume of the mixed fluid of 205 - 420 gallons / hour of liquid and 416,667 - 833,333 fl³/ hour of gas .

13. The tr eatment process according to claim 10, further including a step of withdrawing a portion of the mixed fluid and the treatment composition from a bottom of the reactor and re-circulating the withdrawn portion back into the reactor.

14. The treatment process according to claim 10, wherein reactor is as horizontal reactor and the fluid mixture of the liquid hydrocarbon based component and the natural gas component is flowed into the reactor via a large number of small discharge openings formed in a pipe which extends longitudinally along a the lower portion of the reactor.

15. The treatment process according to claim 9, wherein the fluid mixture as extracted from the earth nitially contains more than 20,000 ppm of H₂S.