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Title:
COMPOSITIONS AND PROCESSES FOR REMEDIATING H2S, SULFUR-CONTAINING COMPOSITIONS, AND CONTAMINANTS IN CONTAMINATED FLUIDS
Document Type and Number:
WIPO Patent Application WO/2021/081543
Kind Code:
A1
Abstract:
An aqueous based treatment solution for remediating hydrogen sulfide (H2S) and other contaminants in liquids and substantially without formation of precipitate, including at least one hydroxide compound, at least one organic acid selected from a group consisting of a fulvic acid and a humic acid, a chelating agent, and water. A collective concentration of the at least one hydroxide compound in the treatment solution is in a range of 35 – 55 weight %, a content of water in the treatment solution is at least 30 weight %, a collective concentration of the at least one organic acid in the treatment solution is at least 0.01 weight %, and a weight of the chelating agent in the treatment solution is at least 0.05 weight %.

Inventors:
ROE CLIFFTON (US)
SCHWEITZER LINDA (US)
Application Number:
PCT/US2020/064854
Publication Date:
April 29, 2021
Filing Date:
December 14, 2020
Export Citation:
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Assignee:
GAPS TECH LLC (US)
International Classes:
A61K47/06; A61K8/06; A61Q19/00
Attorney, Agent or Firm:
SHENDE, Fulchand et al. (US)
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Claims:
What is claimed is:

1. An aqueous based treatment solution for remediating hydrogen sulfide ( H2S ) and other contaminants in liquids and substantially without formation of precipitate, the treatment solution comprising: at least one hydroxide compound; at least one organic acid selected from a group consisting of a fulvic acid and a humic acid; a chelating agent; and water, wherein a collective concentration of the at least one hydroxide compound in the treatment solution is in a range of 35 - 55 weight %, a content of water in the treatment solution is at least 30 weight %, a collective concentration of the at least one organic acid in the treatment solution is at least 0.01 weight %, and a weight of the chelating agent in the treatment solution is at least 0.05 weight %.

2. The treatment solution according to claim 1 , wherein the collective concentration of the at least one hydroxide compound in the solution is 45-55 weight %.

3. The treatment solution according to claim 1 , wherein the treatment solution contains at least two different hydroxide compounds.

4. The treatment solution according to claim 1 , wherein the at least one hydroxide compound includes sodium hydroxide (NaOH) and potassium hydroxide (KOH).

5. The treatment solution according to claim 1 , wherein the collective concentration of the at least one organic acid in the solution is 0.01 - 10 weight %.

6. The treatment solution according to claim 1 , wherein the chelating agent includes ethylenediaminetetraacetic acid (EDTA) and the concentration of the chelating agent in the treatment solution is 0.05 - 10 weight %.

7. The treatment composition according to claim 1 , wherein a content of water in the treatment solution is at least 40 weight %.

8. The treatment composition according to claim 1, further comprising 0.001 - 0.2 weight % of surfactant.

9. The treatment composition according to claim 8, wherein the surfactant includes sodium lauryl sulfate.

10. A treatment composition for remediating H2S and other contaminant(s) in contaminated liquids, comprising: 0.1 - 10.0 weight % collectively of at least one hydroxide compound; 0.01 - 3.0 weight % collectively of at least one organic acid selected from a group consisting of fulvic acid and humic acid; 0.01 - 10.0 wt% of a chelating agent; and at least 75 % weight of water.

11. The treatment composition according to claim 10, wherein the chelating agent is ethylenediaminetetraacetic acid (EDTA) and the hydroxide compound(s) include at least one of sodium hydroxide and potassium hydroxide.

12. The treatment composition according to claim 10, further comprising 0.001 - 0.2 weight % of surfactant.

13. The treatment composition according to claim 12, wherein the surfactant comprises sodium lauryl sulphate.

14. The treatment composition according to claim 10, wherein water constitutes at least 90 wt % of the treatment composition.

15. The treatment composition according to claim 10, wherein a pH of the composition is about 14.0

16. A treatment process for remediating H2S in a contaminated liquid, comprising steps of adding 0.05 - 15 ml of the treatment composition according to claim 1 / liter of contaminated liquid, and allowing the treatment composition to react with the H2S and other contaminant(s) in the contaminated liquid for a sufficient time to permit the amounts of the H2S in the contaminated liquid to be reduced to less than 5 ppm, wherein an amount of H2S in the contaminated liquid prior to addition of the treatment composition is at least 500 ppm.

17. The treatment process according to claim 16, wherein in the adding step 0.5 - 6.0 ml of the treatment composition is added Z liter of the contaminated liquid.

18. The treatment process according to claim 16, wherein the chelating agent is ethylenediaminetetraacetic acid (EDTA), and the hydroxide compound(s) include at least one of sodium hydroxide and potassium hydroxide.

19. The treatment process according to claim 16, wherein the treatment composition further comprises 0.001 - 0.2 weight % of surfactant.

20. The treatment process according to claim 10, wherein water constitutes at least 50 wt % of the treatment composition.

Description:
COMPOSITIONS AND PROCESSES FOR REMEDIATING H2S, SULFUR-CONTAINING COMPOSITIONS, AND CONTAMINANTS IN

CONTAMINATED FLUIDS

CROSS-REFERENCE TO RELATED APPLICATIONS

[000.1] This application nonprovisional of and claims priority to US Provisional Application Serial No. 62/925,929, filed October 25, 2019. The entire subject matter of this priority application is incorporated by reference herein.

BACKGROUND OF THE INVENTION

1. FIELD OF THE INVENTION

[0001] The present disclosure relates to improved, novel, cost effective treatment compositions and treatment methods for remediating sulfur-containing contaminants, especially H 2 S, in various fluids, e.g., hydrocarbon based liquids such as crude oil extracted from the ground, other hydrocarbon based liquids, and so-called “produced water” which is contaminated water extracted with crude oil from the ground and gasses such as natural gas. More particularly, the present disclosure relates to such treatment compositions and methods in which the contaminated fluids are chemically reacted with the treatment compositions in the treatment methods in an efficient and economical manner, whereby almost all of the contaminants in the fluids are remediated down to very low levels that have been deemed safe.

2. BACKGROUND

[0002] Sulfur-containing compounds including hydrogen sulfide (H 2 S) have long been recognized as undesirable contaminants in hydrocarbon or petroleum based liquids such as crude oil and liquefied petroleum gas (LPG), as well as in contaminated aqueous solutions such as solutions extracted from the earth along with crude oil, natural gas and the like, which aqueous solutions may also be contain significant concentrations of salts and be considered brine. Herein “hydrocarbon based liquid" is used to indicated any hydrocarbon based liquid, including petroleum based liquids. Examples of hydrocarbon based liquids which may be treated with the treatment solutions and treatment methods of the present invention include those containing molecules of CH 9 to CH 32 . H 2 S is a particularly undesirable contaminant because it is highly toxic, corrosive, etc. and generally petroleum based liquids such as crude oil should contain less than five ppm H 2 S in order to be acceptable for refining or other processing. While the amount of H 2 S in hydrocarbon based liquids can range from a few ppm to more than 100,000 ppm, crude oil from the ground typically contains < 40,000 ppm H 2 S, most often < 2000 ppm H 2 S, and will generally be somewhat acidic with a pH about 5 to 6. The H 2 S may be present in several forms, including H 2 S dissolved in a liquid, H 2 S as mercaptan sulfur and H 2 S content in vapor, but the majority is typically present as H 2 S content in vapor when the contaminated liquid is at ambient pressure or about one atmosphere, particularly at higher concentrations, and the release of H 2 S in vapor or gaseous form from contaminated liquids is significantly toxic and dangerous. The present invention is particularly suited for remediation of liquids containing low to moderate amounts of H 2 S and other sulfur containing contaminants, e.g., H 2 S concentrations of 2000 ppm or less, especially 500 ppm or less, which constitutes a majority of the crude oil and other hydrocarbon based and aqueous based liquids that need to be remediated.

[0003] Again, much of the H 2 S in a hydrocarbon based liquid, such as crude oil, is in gaseous or vapor form when the contaminated liquid is at ambient pressure. H 2 8 gas has much greater solubility in hydrocarbon based liquids than in water, and at the high pressures at which crude oil exists underground, it is possible for the crude oil to have thousands and tens of thousands of ppm H 2 S therein. However, when the crude oil is brought up to ambient or atmospheric pressure much of the H 2 S gas therein may be released from the crude oil according to Henry’ s Law, and hence the need to remediate the H 2 S and prevent it from being released. The amount of soluble and gaseous H 2 S which can be in aqueous solutions is less than the amount which may be in hydrocarbon based liquids, but it still can be present in hundreds and thousands of ppm, and contaminated aqueous solutions will typically contains < 1000 ppm H 2 S. Generally, H 2 S is an acidic compound, and crude oil as extracted from the ground and containing a typical amount of H 2 S, e.g. < 2000 ppm, which is mostly in the form gas dissolved in the crude oil, has a moderately acidic pH of about 5 - 5.5. Gaseous H 2 S does not exist in solution above a pH of about 7.

[0004] There are many known methods for remediating sulfur-containing compounds, including H 2 S, from crude oil and other liquids. 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 monoethanol amine (ME A), 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 (H 2 S) volumes must be treated.

[0005] H 2 s abatement achieved by a conventional amine treatment process uses an amine such as monoethanolamine (MEA) or triazine for treating H 2 S in crude oil. See, for example, US Patent 8,562,820 which di scloses a formulation of triazine wh ich is specially suited for treatment of hydrocarbon liquids for remediating the H 2 S and other sulfur containing compounds therein. However, the conventional amine treatment process may not be effective for remediating H 2 S in crude oil containing paraffin and other waxes and in oil containing more than 200 ppm H 2 S. Further, the conventional triazine treatment for H 2 S generally requires a significant amount of triazine for treating H 2 S, e.g., the required amount of triazine may be 10 times the amount of H 2 S in the contaminated liquid, and hence results in a relatively high treatment cost. Also, while the H 2 S may be initially remediated or abated down to acceptable levels, the resulting sulfur compounds that remain in the treated oil may undesirably revert back to H 2 S 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.

[0006] The present inventors have proposed other treatment compositions and processes for remediating H 2 S and other contaminants in various contaminated liquids such as crude oil and aqueous solutions such as solutions extracted from the earth along with crude oil and in natural gas. See, for example, International Application Nos. PCT/US2018/050913 and PCT/US2018/064015 , the entire disclosures of which are incorporated herein by reference. These prior proposals are very effective at quickly remediating H 2 S, even at very high concentrations, e.g., 100,000 ppm or more.

[0007] The inventors’ prior proposals as set forth in PCT/US2018/050913 involves an aqueous treatment solution containing primarily a high concentration of one or more hydroxide compounds such as sodium hydroxide (NaOH), potassium hydroxide (KOH), etc., e.g., collectively the hydroxides account for 35-55 weight percent, and preferably at least 45 weight percent of the treatment solution, which efficiently react with H 2 S to convert it to non-toxic substances. Such treatment solution according to the recent proposal is highly alkaline with a pH of 13 - 14. In such treatment process a relatively small dosage of the treatment solution is added to the hydrocarbon based liquids or aqueous solutions being treated, e.g., at a standard dosage rate of 0.25 - 6.0 ml of the treatment solution / liter of the liquid being treated, preferably 1.0-5.0 ml of the treatment solution /liter of the liquid being treated, which corresponds to approximately 125-3000 ppm of hydroxide(s) in the liquid being treated. A particularly appropriate dosage rate for a given contaminated liquid depends on multiple factors, but the hydroxide(s) in the solution efficiently remediate the H 2 S and other sulfur-containing compounds down to acceptable levels within relatively short time periods such as 15 minutes to a few hours, and without otherwise detrimentally affecting the hydrocarbon - petroleum based liquids or contaminated aqueous solutions in any significant manner. The recently 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 solution may include a silicate such as potassium silicate (K 2 SiO 3 ) or barium (Ba) as an antibacterial agent, but the high concentration of hydroxide(s) in the treatment solution is a primary characteristic of the solution because this is important for efficient remediation of H 2 S by the hydroxide(s) in the liquids being treated.

[0008] Another of the inventors’ proposals as set forth in PCT/US2018/064015 involves use of a treatment liquid substantially according to the first proposal together with an appropriate amount of one or more organic acids such as fulvic acid and humic acid, which function to assure that no precipitates, scale or the like are released from the remediated liquids. A dosage rate of the organic acid(s) is one 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. A small amount of monoethanol amine or MEA (C 2 H 7 NO) may also be included in the treatment composition to help prevent scale formation from the remediated liquids, e.g., an amount corresponding to a concentration of 0.5 - 15 ppm, and preferrably 1.0 - 10 ppm, of the MEA in the hydrocarbon based liquid or aqueous solution being treated. The organic acid(s) such as fulvic acid and humic acid are effective to bind to the remediated contaminants and maintain them in the treated liquids without forming any precipitates while the liquids are being treated, transported and/or stored for a period of time such as hours, days or weeks, which is very important sometimes, while MEA also helps prevent scale formation from the remediated liquids.

[0009] Fulvic acid is actually a family of organic acids, but may typically be identified as lH,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 with an average chemical formula of C 135 H 182 O 95 N 5 S 2 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. An example of a humic acid molecule is shown below.

[0010] While the inventors’ previously proposed treatment compositions and processes are very efficiently and effectively for remediating H 2 S and other contaminants in the contaminated fluids, and are much more effective and efficient than other conventionally known treatment solutions and processes known prior to the inventors’ proposals, the present inventors’ previously proposed compositions and processes can always be improved upon. Further the previously proposed treatment solutions and processes may not be the most cost effective for treating some contaminated fluids, e.g., fluid which contain low to moderate amounts of H 2 S and other contaminant(s). For example, a majority of the crude oil and other hydrocarbon based fluids from around the world that need to be remediated some crude oil has H 2 S concentrations of 2000 ppm or less, and even 500 ppm or less. Further, while the inventors’ prior proposals are effective to quickly remediate contaminated fluids containing much higher levels of H 2 S and other contaminant(s) within a relatively short time of a few hours or less, such rapid remediation of high contamination levels may not be required in many instances. On the other hand, the same or substantially the same level of remediation for a given contaminated fluid may be achieved with a smaller dosage of the treatment composition provided that there is a longer reaction time permitted for the treatment composition to react with the contaminants in the fluid, and as a side benefit under such extended reaction time there is likely to be less unreacted treatment composition remaining in the treated fluid. Thus, the present inventors’ previously proposed treatment compositions and treatment processes may not be the most efficient manner of treating liquids with low or moderate levels of contamination, and may not be the most efficient depending on other desired conditions, etc. Further, while the inventors’ previous proposals work very effectively for their intended purposes, there is always room for improvement. Hence, there is a desideratum in the art for a lower cost treatment composition and treatment process which provides many of the advantages of the inventors’ previously proposed treatment compositions and treatment processes, but which have improved efficiency, lower cost and may be used for remediating contaminated liquids which do not require all the advantages that can be achieved using the inventors’ previously proposed treatment compositions and treatment processes.

SUMMARY OF THE INVENTION

[0011] It is an object of the present invention to fulfill the discussed desideratum.

[0012] The inventors have further studied the treatment of contaminated fluids, including fluids which contain low to moderate amounts of H 2 S and other contaminant(s) in light of the foregoing, and the inventors have discovered new treatment compositions and new treatment processes which are more efficient, and more cost effective for remediating contaminated fluids. The extent to which the new treatment compositions and new treatment processes are more efficient and more cost effective may depend on the fluids’ particular characteristics and/or depend on what the desired conditions of remediation are.

For example, the new treatment compositions and treatment processes may provide some degree of improvement in efficiency and cost in relation to remediation of fluids having high concentrations of H 2 S and other contaminant(s) in comparison to the inventors’ previously proposed treatment compositions and treatment processes. On the other hand, the new treatment compositions and treatment processes may achieve much greater improvements in efficiency and cost for remediating fluids having low to moderate levels of H 2 S and other contaminant(s) such as crude oil and the contaminated water extracted from the earth with crude oil which have H 2 S concentrations of 500-2000 ppm or less or less. Desirably, these new' treatment compositions and treatment processes fire still very effective for irreversibly remediating the H 2 S and other contaminant(s) down to acceptable levels in reasonably short time periods.

[0013] The new treatment compositions may be aqueous based like the composition disclosed in PCT/US2018/064015 and may include at least two of two primary components of the treatment composition as disclosed in PCT/US2018/064015, i.e., one or more hydroxide compounds and one or more organic acids such as fulvic acid and humic acid. The new treatment compositions may also include a chelating agent such as ethylenediaminetriaceticacid (EDTA), a surfactant such as sodium lauryl sulfate, a buffering agent such as potassium carbonate (K 2 CO 3 ), etc. For example, a treatment composition according to an embodiment of the present invention may comprise an aqueous hydroxide solution containing at least one hydroxide compound, wherein the aqueous hydroxide solution constitutes at least 70 weight % and preferably at least 80 weight % of the treatment composition, and wherein the collective concentration of the at least one hydroxide compound in the aqueous hydroxide solution is in a range of 35-55 wt%, one or more organic acid(s) such as fulvic acid and humic acid in a collective amount of 0.01 - 4.0 wt % of the treatment composition, a chelating agent such as ethylenediaminetetraaceticacid (EDTA) in an amount of 0.01 - 10.0 wt% of the treatment composition, a surfactant such as sodium lauryl sulfate in an amount of 0.001 - 0.2 wt% of the treatment composition, a buffering agent such as potassium carbonate in an amount of 0.001 - 0.2 wt% of the treatment composition, etc. Further, for some applications where lesser amounts of the active components of the treatment composition are required for remediating a contaminated fluid, e.g., where the contaminated fluids contain 500-2000 ppm or less of H 2 S, the treatment composition may have a smaller and even much smaller content of the active ingredients per unit volume as compared to the treatment composition in PCT/U S2018/064015. This may be achieved by diluting a treatment composition such as discussed above containing a high concentration of hydroxide compound(s) with potable water, e.g., at a ratio of 1:1 to 1:25, by diluting the different components of the treatment composition with water before the components are combined together, etc. Also, the different components of the composition may be diluted at different ratios, e.g., the hydroxide compounds may be diluted at a higher ration than the organic acids and the chelating agent.

[0014] The new treatment compositions may, for example, be prepared by combining amounts of the hydroxide compounds (s) and the organic acid(s) similar to the amounts of these compounds in the treatment composition in PCT/US2018/064015, together with desired amounts of a chelating agent such as EDTA, a surfactant, a buffering agent, etc., so that the new treatment compositions may also be relatively concentrated, particularly in terms of the hydroxide compound(s) contained therein. Further, if the new treatment composition is to be used in a treatment process for treating fluids having lower concentrations of H 2 S and/or if longer reaction times are permitted, a smaller dosage volume of the new composition may be used per unit volume of contaminated fluid being treated or, alternatively, the treatment composition may be diluted with a volume of water sufficient so that a dosage volume of the treatment composition per unit of the contaminated liquid may be about the same as the dosage volumes discussed in PCT/US2018/064015. For example, the new composition may diluted such that they contain the hydroxide compound(s) and organic acid(s) at about 1: 1 to 1:25 of the concentration of the hydroxide chemical reactant(s) in the treatment solution as disclosed in PCT/US2018/064015. The inventors have discovered that crude oil and other contaminated liquids with low to moderate amounts of H 2 S, e.g., 500- 2000 ppm or less, together with other contaminant(s) may be effectively and efficiently treated / remediated in a relatively short time period, e.g., 0.5-48 hours, by a treatment process according to the present invention in which a dosage amount of the new treatment composition has 1/2 to 1/25 of the amount of hydroxide compound( s) and organic acid(s) compared to the standard dosage amounts discussed in PCT/US2018/064015. Similarly, the dosage amounts of these active ingredients per unit of the contaminated fluid may be substantially reduced in comparison to dosage amounts used of the prior treatment compositions if longer treatment times ar e permitted. In the treatment processes according to the present invention, the lower dosage amounts may be effected by adding proportionally less of a concentrated treatment composition to the contaminated fluid compared to the dosage amounts of the concentrated treatment composition discussed in PCT/US2018/064015, by diluting the new treatment composition with an appropriate amount of water and then adding the same dosage volume of diluted treatment composition per unit of of the contaminated fluid as discussed in PCT/US2018/064015, etc.

[0015] Conveniently, because the new treatment compositions according to the present invention may be relatively dilute, it is possible to initially prepare a more concentrated version of tire treatment composition, then transport the treatment solution in concentrated form to a desired location, such as a given oil well, and then dilute the composition with potable water to its desired concentration at the location before adding appropriate amounts of dilute treatment composition to the contaminated liquid being treated. Further, while it is appropriate to combine all of the components of the treatment composition together before the treatment solution is added to a contaminated liquid, it is also possible to separately add one or more of the components to the contaminated liquid, and either way the treatment process will be effective for efficiently and effectively remediating the H 2 S and other contaminants in the contaminated liquids within a reasonably short time period.

[0016] While the new treatment composition may be prepared in a diluted form as discussed above, an alternative treatment composition and treatment processes according to the present invention may involve preparing a concentrated version of the treatment composition which is not diluted with water similar to the concentrated treatment composition in PCT/US2018/064015, and then a proportionally much smaller volume of the concentrated treatment composition is added per unit of the contaminated fluid, e.g., a dosage of 0.005 1.5 ml, preferably 0.05 - 0.5 ml of the new concentrated treatment composition may be added / liter of contaminated fluid. The effective dosage amounts of the chemical reactants used in this treatment process would be the same as the effective dosage amounts of these chemical reactants used in the treatment process using the diluted treatment composition, but significantly less water would be used - added to the fluid being treated.

[0017] Treatment processes according to the present invention involving the new treatment compositions will vary depending on a few factors, including the type of fluid being treated-remediated, the particular contaminants and levels of the contaminants in the fluid, any restrictions imposed on the processes including reaction time permitted, degree of remediation, concern for avoiding precipitates from being released from the treated fluids, etc. For example, if the contaminated fluid is a liquid such as crude oil or produced water extracted with the crude oil the treatment process may simply involve adding an appropriate dosage of the treatment composition to the liquid and permitting the treatment composition to react with the contaminants for a sufficient period of time. On the other hand, if the contaminated fluid is a mixture of contaminated liquid and contaminated gas flowing through a pipeline the treatment process may involve continuously or periodically adding amounts of the treatment composition to the mixed fluids flowing through the pipeline so that the treatment composition can react with the contaminants in the mixed fluids as they flow through the pipeline toward a destination. Still further, if the contaminated fluid is a gas such as natural gas from a well, the treatment process may involve initially treating the gas to remove some impurities such as salts which are likely to precipitate out of the treated gas and cause problems of clogging, etc., water which may undesirably dilute the treatment composition, etc., and then flowing - bubbling the natural gas through a reactor containing a volume of the treatment composition.

Intent of Disclosure

[0018] 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

[0019] FIG. 1 is a schematic diagram of a treatment system which may be used in an exemplary embodiment of the present invention.

[0020] FIG. 2 is a flow chart of a natural gas remediation process according to an exemplary embodiment of the present invention.

DETAILED DESCRIPTION OF PRESENT EXEMPLARY EMBODIMENTS

[0021] Exemplary embodiments of the present invention will be described below. Primary aspects of the present invention involve use of novel treatment compositions in treatment processes for contaminated fluids containing H 2 S wherein the treatment compositions are combined / mixed with the contaminated fluids and permitted to react over a period of time until the amount of H 2 S remaining in the liquids is less than 5 ppm.

Treatment Compositions

[0022] According to one exemplary embodiment of the present invention, the inventors’ previously proposed treatment compositions as disclosed in PCT/U S2018/064015 are modified to additionally include an amount of a chelating agent such as EDTA, e.g., new treatment composition may further include 0.05 - 10.0 wt% of the chelating agent. The inventors have determined that addition of EDTA to the treatment compositions disclosed in PCT/US2018/064015 desirably enhances the effectiveness of the previously proposed treatment compositions in various ways. For example, EDTA is effective tor controlling the pH of the new treatment composition to remain above 8 in that EDTA is a alkali base with a PH of 14 and slows the decrease of the pH of the treatment composition as it is used over a period of time in remediating a contaminated fluid. This is advantageous because the high pH favors reaction between the hydroxide compound! s) and the H 2 S in the contaminated fluids, including crude oil and natural gas, such that a given amount of the new treatment composition including EDTA can be effectively used for remediating more of the H 2 S in a contaminated fluid compared to an equal amount of the unmodified treatment composition which does not include EDTA. In other words, the EDTA or other chelating agent effectively extends the useful life of the treatment composition. Further, and without being bound to this theory, based on research they have performed the inventors believe that the new treatment composition including EDTA is particularly effective for remediating H 2 S and other sulfur based contaminants in hydrocarbon based fluids, including crude oil and natural gas, because the EDTA helps to break bonds between the sulfur based contaminants and organic molecules in the in hydrocarbon based fluids so that the hydroxide compound! s) in the treatment composition can more fully access and react with these contaminants and thereby more fully remediate these contaminants.

[0023] Generally, hydrocarbon based fluids including crude oil will have a total acid number (TAN) which is based in part on total organics in the fluids which have not decomposed to become a desirable part of the fluids. Further, it is known that sulfur compounds do not exist in sulfide state, including H 2 S, in fluids having a pH above 6.9. Because the EDTA in the new treatment compositions according to the present invention is a alkali base with a PH of 14 one advantage that the EDTA provides in the new composition is that it slows the decrease of the pH of the treatment composition as it is used in remediating the contaminated fluids, e.g., the EDTA is helpful for maintaining the pH of contaminated fluids that are being treated at a pH of 6.9 or greater, e.g., 7.0, 7.2, so that the sulfur based contaminants in fluids are not in sulfide state. Also, at pH of 6.9 and above the treated fluids have a lower TAN and are far less corrosive to structures containing the contaminated fluids than the untreated contaminated fluids would be without being treated. Untreated contaminated fluids such as crude oil and natural gas Otypically have a somewhat acidic pH of less than 6.0. Correspondingly, sulfide compounds including H 2 S, which normally will tend to be in gaseous phase, are more reliably prevented from being released from a contaminated liquid such as crude oil when treated using the new treatment compositions according to the present invention, desirably reducing the volatility and gas pressure of the treated liquid when it is restricted within a confined space. Also, very importantly, by aintaining the pH of a treated fluid at a pH above 6.9 the organic acids such as fulvic acid and humic acid are able to more fully bond to all of the sulfur compounds remaining in the treated fluids, whereby the remediation of the treated fluids is very desirably irreversible, e.g., the sulfur based molecules bound to the fulvic and humic acids in the treated fluids will not revert to H 2 S even if the treated fluids are stored for extended periods of time and/or heated.

[0024] Incidentally, EDTA has been used as a primary reactant in a known method of mitigating H 2 S. However, in the known treatment method the required molar reaction time is long and the molar reaction ratio is 1 mole EDTA to 1 mole H 2 S, such that high concentrations of H 2 S would require large doses ofEDTA for a long treatment period, which is not well suited to treatment of contaminated fluids containing significant amounts of H 2 S. The new treatment processes involving the new treatment compositions containingEDTA according to the present invention are quite different from the previously known treatment method, e.g., hydroxide compounds are the primary reactants for remediating the H 2 S in the treatment processes according to the present invention, not EDTA as in the known method.

[0025] The new treatment composition according to the present invention may also include smaller amounts of other components for enhancing the effectiveness of the other components, for remediating other specific contaminants in the contaminated fluids, etc.

For example the new treatment composition may also include small amounts, e.g., 0.001 - 0.2 wt% , of a a surfactant such as sodium lauryl, a buffering agent such as potassium carbonate, etc.

Treatment Processes

Contaminated Liquids

[0026] Treatment processes utilizing the new treatment compositions according to the present invention include those treatment processes for remediating contaminated liquids including crude oil, other hydrocarbon based liquids and contaminated aqueous such liquids as natural gas extracted from the earth, including many other species of sulfides, disulfides, thiols, mercaptans such as ethyl mercaptan, etc. such as disclosed in PCT/US2018/064015 , but wherein the new treatment compositions including a chelating agent such as EDTA are used instead of the treatment compositions disclosed in PCT/US2018/064015 and at similar dosage rates. In the new treatment processes the dosage amounts of the new treatment compositions for treating such contaminated liquids may be the same or somewhat smaller as the dosage amounts of the treatment compositions as discussed in PCT/U S2018/064015, noting that because the new treatment compositions tend to be more efficient at remediating H 2 S and other contaminants a correspondingly smaller dosage amount may be used to achieve similar results. Thus, for example, in the new treatment treatment process for remediating contaminated liquids, the treatment solution may involve a standard dosage rate of 0.25 - 6.0 ml of the treatment solution / liter of the contaminated liquid being treated, preferably 1.0-5.0 ml of the treatment solution /liter of the contaminated liquid being treated, which is the same as discussed in PCT/US2018/064015 , which corresponds to approximately 250-6000 ppm of the treatment solution in the liquid being treated based on the discussed concentration of hydroxide(s) in the solution. Similar to what is discussed in PCT/US2018/064015 such standard dosage rate is generally effective for remediating H 2 S concentrations of 40,000 ppm and above in contaminated liquids including crude oil down to safe, acceptable levels. Given the improved efficiency of the new treatment compositions including a chelating agent such as EDTA, the dosage amounts for treating the contaminated liquids could be reduced, but remain within the discussed range of 0.25 - 6.0 ml of the treatment solution / liter of the contaminated liquid.

[0027] Other aspects and considerations of the treatment process for treating contaminated liquids according to the present invention may be the same as discussed in PCT/US2018/064015, including selection of which hydroxide compound(s) to use and adjustment of dosage amounts of the treatment composition based on various considerations. For example, relative to the hydroxide compound(s) used in the treatment composition, it is preferable to use only hydroxide compound(s) which do not contain element(s) / component(s) that are also included as a significant contaminant in the fluid being treated. For example, if the fluid contains a significant amount of sodium chloride as a contaminant, then the hydroxide compoundd (s) in the treatment solution should be other than sodium hydroxide (NaOH), e.g., potassium hydroxide (KOH), ammonium hydroxide (NH 4 OH), lithium hydroxide (LiOH), magnesium hydroxide (Mg(OH) 2 ), and manganese hydroxide (Mn(OH) 2 , Mn(OH) 4 ) would be suitable hydroxides for use in this situation.

[0028] The organic acids such as fulvic acid and humic acid in the new treatment composition perform essentially the same functions as discussed in PCT/US2018/064015, but these functions are enhanced by the chelating agent such as EDTA included in the new treatment compositions. Fulvic and humic acids are very effective for binding with the sulfur ions, and sulfur based compounds resulting from the remediation of H 2 S and other species of sulfur based contaminants in the contaminated liquid and for preventing the resulting surfur compounds and other contaminants from precipitating out of the treated crude oil or other treated liquid. The fulvic acid and humic acid will pick up sulfide ions (HS or S 2 ) as a scavenger. There is presently no analytical method for identifying all sulfur species in a reaction of H 2 S (including HS or S 2 ) with fulvic or humic acid. Fulvic acid is not one molecule, but a mixture of organic molecules of different structures with various aliphatic and aromatic hydrocarbon with carbonyl and hydroxyl functional groups that can react with HS- and S2-. The same applies to humic acid. In the natural environment, fulvic acid and humic acid are known to pick up sulfur in biogeochemical cycling processes to form organic sulfides, thiols and thiophenes, sulfoxides, polysulfones and sulfonates. Fikewise, when sulfur in a contaminated liquid reacts in a solution containing fulvic acid and/or humic acid, the number and complexity of these compounds makes it difficult to speciate and the results will be different based on other variables such as pH, redox potential, and the presence of other compounds in the solution including impurities in contaminated liquid that can react with and/or bond to fulvic acid or humic acid. These organic acids help in two ways, i.e., they bind sulfur as an irreversible scavenger of sulfur (i.e., once bound, a drop in pH does not return the sulfur to H 2 S), and it also helps to keep solids in solution (i.e. it is a solubility enhancer).

[0029] Reaction times for the new treatment process correspond to those discussed in PCT/US2018/064015 , e.g., typical reaction times are within a relatively short time period such as 15 minutes - 24 hours after such treatment solution 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 solution remediate the H 2 S 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.

Contaminated Liquids Containing Smaller Amounts of H 2 S And Other Contaminants

[0030] While the new treatment compositions according to the present invention may be relatively concentrated similar to the treatment compositions discussed in PCT/U S2018/064015, again, the present inventors have determined that for some for treating contaminated fluids containing smaller amounts of the H 2 S and other contaminants, may be effectively remediated using smaller dosage amounts of the new treatment compositions compared to those discussed in PCT/US2018/064015. This may be achieved by adding a smaller dosage volume of the new, concentrated treatment composition, e.g., a dosage of 0.005 - 1.5 ml, preferably 0.05 - 0.5 ml of the new concentrated treatment composition may be added / liter of contaminated fluid. The effective dosage amounts of the chemical reactants used in this treatment process would be the same as the effective dosage amounts of these chemical reactants used in the treatment process using the diluted treatment composition, but significantly less water would be used - added to the fluid being treated. On the other hand, this may be achieved by diluting the treatment composition with water, e.g., at a ratio of 1:1 to 1:25, and then using dosage volumes of the diluted composition such as discussed in PCT/US2018/064015. The dilution may be achieved by diluting a treatment composition such as discussed above containing a high concentration of hydroxide compound(s) with potable water, e.g., at a ratio of 1:1 to 1:25, by diluting the different components of the treatment composition with water before the components fire combined together, etc. Also, the different components of the composition may be diluted at different ratios, e.g., the hydroxide compounds may be diluted at a higher ration than the organic acids and the chelating agent.

[0031] Thus, for example, according to a exemplary embodiment of the present invention, a novel treatment process for remediating for remediating contaminated liquids containing low to moderate amounts of H 2 S, e.g., 500-2000 ppm or less, may involve a relatively dilute treatment composition containing mostly water, together with much lower concentrations of hydroxide compound(s) and organic acid(s) than in the treatment solution as disclosed in PCT/US2018/064015, an amount of a chelating agent such as EDTA, and optionally a small amount of surfactant. For example, a treatment composition according to an exemplary embodiment of the present invention may contain at least 70 % weight of water, and preferably at least 90 % weight of water, together with: 0.1 - 10.0 weight % collectively of at least one hydroxide compound; 0.01 - 3.0 weight % collectively of at least one organic acid including as fulvic acid, humic acid and the like; 0.05 - 10.0 wt% of a chelating agent such as EDTA; and optionally 0.001 - 0.2 wt% of one or more of a surfactant such as sodium lauryl sulphate and a buffering agent such as potassium bicarbonate. A pH of the treatment composition may be approximately 14.0.

[0032] In the novel treatment composition according to this embodiment of the present invention, the collective concentration of the hydroxide compound(s), the organic acid(s), the chelating agent and/or surfactant may be adjusted within the discussed ranges depending on the amounts of H 2 S and other contaminants in the liquid being treated, as well as on other factors including specific reaction rate desired and other contaminants in the liquid being treated.

[0033] The contaminated fluids which may be treated using the treatment composition , _in a treatment process according to the present invention can be essentially any hydrocarbon based or aqueous based fluids. For example, hydrocarbon based liquids may have a viscosity or API density (the term API as used herein, is an abbreviation for American Petroleum Institute) across a broad range, e.g., from a very dense / viscous substance such as asphaltene to far less viscous / dense substances such as blends of napthas of liquids with an API of about 80. Of course, for some of the very dense / viscous liquids, it may be necessary to heat and/or mix the liquid in order to sufficiently disperse the treatment solution throughout the liquid so that it may sufficiently and efficiently react therewith in a reasonable time.

[0034] For treating contaminated liquids with lower concentrations of H 2 S and other contaminants, a treatment process according to an exemplary embodiment of the present invention may involve adding a standard dosage of the new, dilute treatment composition per unit volume of the contaminated liquid, e.g., a dosage within a range of 0.05 - 15 ml, preferably 0.5 - 5.0 ml of the new, dilute treatment composition / liter of contaminated liquid, and then simply letting the treatment composition react with the H 2 S and other targeted contaminants for period of time such as 30 minutes - 24 hours. The inventors have found that treatment process is very effective for safely and efficiently remediating the low to moderate levels of H 2 S, e.g., about 500-2000 ppm. or less, and other targeted contaminants therein down to appropriate levels of less than 5 ppm within such time period without creating precipitates to be released from the treated liquids and without causing any significant problems for the treated liquids. The most appropriate dosage rate within the discussed range for the treatment composition, as well as for each of the components thereof, will be based on specific characteristics of the contaminated liquid being treated, but not so dependent on whether the liquid is a hydrocarbon based liquid or contaminated aqueous solution. Within such range, the most appropriate dosage rate largely depends on : 1) the amount of H 2 S and other targeted contaminants in the liquid being treated; 2) the viscosity of the liquid; and 3) the amount of time permitted for reacting the treatment composition with the liquid being treated. Heating and/or mixing of the liquid being treated may also he important considerations because heating and/or mixing of the liquid being treated will typically reduce the viscosity of the liquid and will also reduce the amount of time required for dispersing the treatment composition throughout the contaminated liquid for properly remediating the H 2 S and other targeted contaminants in the liquid. The dosage amount of treatment composition and each of its components are substantially, linearly scalable within the discussed range based on these factors.

[0035] Other considerations regarding the dosage amount for a given contaminated liquid as discussed in PCT/US2018/064015 regarding the amounts of hydroxide compound(s) and organic acid(s) in the treatment solution also generally apply to the treatment solution according to the exemplary embodiment of the present invention. However, if the dilute treatment composi tion according to the exemplary embodiment of the present invention is used, this will contain a significantly larger proportion of water and less of the reactive compounds than the treatment composition of PCT/US2018/064015 , and it is important that the total water content of treated hydrocarbon based liquids such as crude oil not exceed 0.5 volume % because this could render the treated crude oil not marketable and valuable. Hence, if the contaminated liquid contains relatively higher amounts of I PS. e.g., exceeding 2000 ppm, it may be more appropriate to a less diluted version of the treatment composition according to the exemplary embodiment of the present invention or a treatment composition as disclosed in PCT/US2018/064015 rather than a fully treatment composition according to the present invention for treating the contaminated liquid. Examples

[0036] An example of an aqueous treatment composition according to the exemplary embodiment of the present invention may be prepared as follows. In an appropriate size container combine : 20-50 gallons of a concentrated aqueous solution containing 35- 55 wt % collectively, preferably 45- 55 wt% collectively, of one or more hydroxide compounds such as NaOH and KOH; 2-5 gallons of an aqueous solution containing about 1-10 wt % collectively of one or more organic acids such as fulvic acid and humic acid; 2-5 gallons of an aqueous solution containing 25-50 wt% of EDTA; and optionally 0.1-1 gallon of surfactant such as sodium lauryl sulphate, together with an amount of water to generate 330 gallons of the treatment composition. Again, timing for when some or all the amount of water is added to the other components may be delayed until the other components are brought to a location where the treatment composition is to be added to the contaminated liquid being treated, e.g., at a given oil well.

[0037] A example of treatment process using an aqueous treatment composition according to the exemplary embodiment of the present invention to treat crude oil containing about 2000 ppm of H 2 S involves the steps of : 1) adding 5 ml of the treatment composition as prepared in the example of the preceding paragraph to a volume of contaminated crude oil contained in a closed vessel such as a tanker truck at a dosage rate of 5 ml of the treatment composition / liter of the crude oil ; and 2) allowing the treatment composition to react with the H 2 S for a period of 15 minutes to 24 hours or until the concentration of H 2 S remaining in the crude oil is less than 5 ppm. Thus treated, the crude oil is safe for being transported to a refinery and the remediated H 2 S and other contaminants in the crude oil will remain in the crude oil without precipitating and being released from the treated crude oil.

Contaminated Gasses

[0038] Treatment processes utilizing the new treatment compositions according to the present invention also include treatment processes for remediating contaminated gasses including natural gas, and other hydrocarbon based gasses. Contaminated gas treatment processes according to the present invention may involve bubbling or otherwise flowing the contaminated gasses through a reactor, disposed horizontally or vertically, containing a volume of the new treatment composition according to the present invention so as to remediate the contaminants in the gasses, including H 2 S, other species of sulfides, disulfides, thiols, mercaptans such as ethyl mercaptan, and other contaminants typically found in the natural gas such as

CO 2 .

[0039] However, there are many differences between contaminated liquids such as crude oil and treatment of contaminated gasses such as natural gas and due to these differences treatment processes for contaminated gasses such as natural gas typically will require additional steps and be much more complicated than treatment processes for treating contaminated liquids.

[0040] One of the present inventors has carefully investigated caustic treatment of petroleum based gasses including natural gas, as well as other contaminated gasses for removing H 2 S and other contaminants therefrom, and has discovered some new treatment systems, methods and compositions for efficiently remediating the contaminants in such gasses.

[0041] One such discovery is that when his previously proposed treatment compositions are used for treating a large volume of a highly contaminated gas which is flowing, e.g., natural gas which is being extracted from well and which contains significant amounts of H 2 S and other contaminants, simply flowing / bubbling the contaminated gas through the treatment compositions may not he an efficient or practical method for remediating the contaminants. While the inventor’s previously proposed treatment solutions are effective for remediating the H 2 S and other contaminants in the gasses down below government accepted levels, the treatment solutions and the treatment processes may become much less effective in a relatively short time, such as 4-12 hours of use, due to other contaminants in the natural gas besides H 2 S and to the nature of the treatment process for natural gas. This makes the cost of the treatment process itself very high in terms of the treatment solution having to be replaced every 4-12 hours, as well as shutting down and restarting the process every few hours. Moreover, it is no simple, inexpensive task to stop and re-start the flow of natural gas and other fluids from a well.

[0042] In relation to the discovery, the inventor has discovered that there are multiple complications involved with the problem. A main complication is that some of the contaminants in the natural gas, such as Na and Cl ions from salts, may generate significant amounts of precipitates that released from the natural gas as it is being treated and clog up components of the treatment system and the treatment process. For example, if natural gas contains a significant amount of sodium chloride (NaCl), e.g., any water vapor contained in the natural gas will typically be saturated with Na and Cl ions and these ions combine as sodium chloride NaCl which tends to precipitate out of the natural gas as it is being treated and quickly build up to a significant amount in 1-6 hours. Such precipitates tend to greatly disrupt the treatment process and would have to be removed on a regular basis, again, making the treatment process more complicated and inefficient. Such precipitation of sodium chloride occurs even if the treatment process uses a treatment solution according to the inventor’s proposal in PCT /US2018/064015 , which includes an organic acid such as fulvic acid or humic acid that helps to prevent formation of precipitates in treated liquids/fluids. Another complication is that some of the contaminants interfere with remediation of the H 2 S and other targeted contaminants, inhibiting and slowing down the remediation and requiring additional treatment composition to be used to achieve the desired level of remediation. Still another complication is the nature of the natural gas which is to be treated with a liquid treatment composition, and the velocity, pressure and volume at which natural gas is discharged from a well. For the contaminants that are to be remediated, including H 2 S, there must be sufficient contact between the contaminants and the hydroxides and other reactants in the treatment composition and this is very difficult or impossible to achie ve if the natural gas is flowing at a high velocity, such 10 feet / see. or more.

[ 0043] The inventor has further studied the treatment of contaminated gasses in light of the discovered complications, and the inventor has further discovered novel treatment systems, treatment processes and treatment compositions that address and overcome each of the complications discussed above and provide a very practical, effective and efficient manner of remediating contaminated natural gas and other contaminated gasses.

[0044] According to an aspect of the present invention, the inventor has determined that the first complication pertaining to formation and release of precipitates may be overcome by initially treating the contaminated gas to remove the contaminants most likely to generate precipitates, including Na and Cl ions. This may be done, for example, by passing the contaminated gas through a water wash flow cell of potable water to remove such ions which are very soluble in water. The inventor has performed testing of the effects of a water wash flow cell on contaminated natural gas obtained from a well, after the natural gas is initially separated from the crude oil and contaminated water that is discharged with the natural gas from the well, and has found that the water wash very effective for removing these contaminants from the contaminated gas, e.g., testing showed that the after the water wash the gas contained an undetectable amount of Na and less than 0.03 ppm of Cl. Removal of the contaminants most likely to generate precipitates, including Na and Cl ions, not only prevents formation of precipitates, but the inventor has also discovered that it also synergistically improves the efficiency of the treatment composition that remediates H 2 8 and CO 2 according to an embodiment of the present invention as discussed further herein.

[0045] According to another aspect of the present invention, the inventor has determined that the second complication pertaining to interference to remediation of primary targeted contaminants including H 2 S by other contaminants in the gas may largely be overcome by also removing most of the water (H 2 O) in the natural gas before the treatment for remediation of H 2 S and other targeted contaminants. Generally, contaminated natural gas from a well may contain trace amounts of water up to 5 % volume, and after passing through a water wash flow cell the natural gas will typically contain at least 2 % volume of water. It is possible to remove water from the natural gas using a variety of conventional means, e.g., a glycol tower, a coalescing or dehydrating unit which causes water vapor in the gas to liquefy and drop out, etc. The conventional means may be appropriate for use according to the exemplary embodiments of the present invention, but the inventor has determined that it is important to reduce the water content to a very low level, e.g., less than 1 ppm, and more preferably < 0.5 ppm in the natural gas, because even low levels of water can add up to significant quantities over a period of 24 hours (one day) in the treatment of natural gas flowing from, a well, and the water will, among other things, dilute the treatment composition which remediates H 2 S and other targeted contaminants according to the exemplary embodiments of the present invention, and this undesirably makes the treatment process less efficient by increasing necessary reaction times, etc. For example, with an average size well discharging about 2 million ft 3 of natural gas / day at 125-150 PSI, if the natural gas contains 2 ppm of water, this amounts to more than 7 barrels of water / day in the natural gas, whereas in the exemplary treatment process according to an embodiment of the invention the amount of treatment compositions used may be less than one barrel.

[0046] Additionally, because water is one of the byproducts resulting from remediation of H 2 S and other targeted contaminants using the exemplary treatment compositions according to the exemplary embodiments of the present invention, the inventor has further determined that it is also very beneficial to remove water from treatment compositions being used in the reactor throughout the treatment process in order to achieve even better efficiency. The water can be removed periodically, e.g., when the amount of water in the treatment composition reaches a predetermined level, or continuously. For example, some amount of the treatment composition may form a pool in a bottom portion of a reaction chamber of the reactor and from that pool some amount, e.g., 1-20 % volume, may he withdrawn and heated to a temperature at which the water will vaporize but which does not otherwise adversely affect the treatment composition, e.g., 240-400 °F, the evaporated water can be drawn off and then the dehydrated treatment composition returned to the reaction chamber.

[0047] According to another aspect of the present invention, the inventor has determined that the third complication, pertaining to tire nature of the natural gas which is to he treated with a liquid treatment composition and the high rate at which natural gas is extracted from a well, may largely be overcome by: regulating the pressure of the natural gas to an appropriate level which will correspond to a flow rate or velocity of the natural gas being remediated to less than 10 feet/sec, preferably to < 5 feet/sec, as it passes through a volume of the new treatment composition according to the present invention which is contained in one or more reactors sufficiently sized to handle all of the gas being discharged from the well; and disrupting the flow of the natural gas through the reactor(s) so that the gas cannot flow uninterrupted therethrough in a stream or as large hubbies, and will thereby have much more surface area for reacting with the treatment composition. Such disruption may be accomplished by packing the reactor( s) or portions thereof with a fine, non-reactive media, e.g., stainless steel wool, pea gravel, perforated plates, etc., through which the natural gas will pass as it flows through the reactor(s). Additionally, the inventor has determined that for optimum efficiency, it is desirable that the reactor should not be filled to any extent with tire treatment composition, e.g., as a bubble tower, but instead may be operated as a counter-flow type reactor in which the natural gas is continuously introduced near the bottom of the reactor and the treatment composition is continuously introduced at intermediate and/or upper portions of the reactor so as to wet or saturate the non-reactive media and so that the natural gas will contact and react with the treatment composition as it flows upward through the reactor. With such a counter-flow reactor, some of the treatment composition will remain in the treated natural gas along with the remediated contaminants as the natural gas exits the reactor, and some of the treatment composition may descend to a bottom portion of the reactor and accumulate based on gravity. The amount of treatment composition remaining in the natural gas as it exits the reactor may be minimized by providing some type of baffle, e.g., perforated plate(s), before the reactor exit that the natural gas will contact and which will separate any small droplets of treatment composition from the natural gas and permit same to drip back down into the reactor. The amount of treatment composition which descends into and accumulates at the bottom portion of the reactor may be used as the source for withdrawing some of the treatment composition to be dehydrated by removing accumulated water, which dehydrated composition may then be re-circulated back into the reactor as discussed herein.

[0048] Relative to the carbon dioxide (CO 2 ) in the natural gas, this can be remediated with the hydroxide compound(s) in the new treatment composition according to the exemplary embodiment of the invention, and theoretically this would require an additional amount of the treatment composition to be used in the remediation process. For this reason, the present inventor considered tire possibility of removing CO 2 from the natural gas before it is treated with the treatment composition in the counter-flow reactor, e.g., by a scrubbing process, or by addition of carbonate compounds in the treatment composition to reduce reactivity of hydroxides in the treatment composition with CO 2 . However, the inventor further discovered that when the Na and Cl ions are initially removed from the natural gas using the water wash and because the treatment composition is highly basic with a pH of 13-14, such that the pH of the natural gas is increased from an initial value of about 5.8 - 6.2 to a pH of at least 7 when it contacts the treatment composition, this has a synergistic effect whereby some of the H 2 S and CO 2 in the natural gas react together to form, among other things, hydroxide ion OH " , which will then help to efficiently remediate other H 2 S and CO 2 in the natural gas. Hence, while is possible to initially scrub CO 2 from the natural gas before the gas is remediated using the treatment composition of the present invention or to add carbonates to the treatment composition to reduce reactivity with CO 2 , the treatment process according to the present invention can efficiently remediate the CO 2 content in the natural gas down to 1 ppm or less without separately scrubbing the CO 2 using an additional scrubbing process or adding carbonates to the treatment composition.

Exemplary Treatment System and Process For Treating Contaminated Gasses

[0049] Referring to FIGS, land 2, there are shown a system 100 for remediating contaminated natural gas according to an exemplary embodiment of the present invention and a flowchart of a treatment method or process using the system 100 according to an exemplary embodiment of the present invention. The system 100 may include a three phase separator 102 which receives the fluids output from a well 101 and separates same into a gas stream, a aqueous based liquid stream and a hydrocarbon based liquid stream, a water wash flow cell 104, a chiller 106, a coalescing unit 108, a counter-flow reactor 110 with injectors 120 for injecting treatment composition, a dehydrator 112 and possibly other and/or additional components as discussed herein. The different components of the system may be used in manners as discussed above to remove the various contaminants from a contaminated gas, and if the contaminated gas does not include contaminants or sufficient levels of some contaminants requiring remediation, then not all components of the system may be required to be used for treating the gas.

[0050] Generally, a well for extracting crude oil and natural gas from the earth may have an inside diameter (ID) of about 4 inches, while the well may be drilled to an average depth of 30,000 to 50,000 feet, at which depth temperature may be about 1000 °F and pressure may be 100 to 2500 PSI. Some wells have pump jacks and some do not, and for those that do not they will have regulators which reduce the pressure down to about 300 PSI at tire surface well head. A typical well will yield 1 to 2 million ft 3 of natural gas / day at 100 PSI and 120 °F. If a well produces 2 million ft 3 of natural gas / day at such pressure and temperature and the gas is passed through a pipe with a 3 inch ID, the flow rate or velocity of the gas would be about 68 feet/sec. At such velocity it would be impossible to remediate the natural gas in a reactor according to the present exemplary embodiment because the gas would rapidly pass through the treatment composition with little contact. However, the counter-flow reactor 110 may have an ID of any appropriate size, e.g., 1-6 feet ID, and the pressure of the gas may be adjusted or regulated to any desired pressure, including pressures above 100 PSI, at which the gas will have a reduced volume and increased density compared to the volume and density at or below 100 PSI, such that all of the natural gas extracted from a well could be properly handled by one or more of the reactors 110 which are appropriately structured to receive the gas so that it passes through the reactor(s) at a velocity of < 5 feet/sec. For example, 2 million ft 3 of natural gas at 100 PSI and 120 °F being discharged from a well through a pipe with an ID of 3 inches is treated in a reactor having an ID of 2.0 feet, and gas pressure adjusted to 120 PSI with a corresponding reduction in volume, the gas velocity through the reactor would be about 5 feet/sec., and if the pressure is increased to 200 PSI with a corresponding reduction in volume, the gas velocity through the reactor would be about 0.9 fee/sec. Generally, the pressure and density of the natural gas do not significantly affect the effectiveness of the remediation process according to the exemplary embodiment of the present invention. In other words, the remediation process is effective for reducing the contaminant levels down to government acceptable levels or lower regardless of the pressure and density of the gas, as long as the flow rate or velocity of the gas through the reactor 110 is less than

10 feet/ sec., preferably < 5 feet/sec. [0051] Based on all testing thus far, it is expected that in a full scale operation, e.g., including a counter-flow reactor with a 2 ft ID and 21 ft tall, and at least 6 ft of which is packed with non-reactive media, a continuous flow of natural gas from a well at 2 million ft 3 / day, including high concentrations of H 2 S, e.g., 2,000 - 300,000 ppm, and other contaminants may be successfully treated down to less than 1 ppm for each of the contaminants using 1-4 gallons/hour or 24-96 gallons total of the treatment composition provided the pressure of the gas is maintained within a range of 100-200 PSI and velocity of the gas is less than 10 feet/ sec., preferably < 5 feet/sec. according to the exemplary embodiment. The specific formulation and / or amount of treatment composition used may be appropriately adjusted based on specific characteristics of the natural gas and operations of the different components of the treatment system 100 to achieve a desired result. Of course, the counter-flow reactor 110 and other components of the exemplary treatment system 100 in FIGS. 1-2 may be constructed in any suitable size appropriate for treating any given amount of natural gas being output from a well. Similarly, it is also possible to use multiple systems 100 to handle the natural gas from a given well.

[0052] Referring to FIG. 2 there is shown a treatment process for remediating H 2 S and other contaminants in natural gas and other gasses according to an exemplary embodiment of the present invention, and it generally corresponds to the exemplary treatment system 100 of FIG. 1. At step SI a flow of a contaminated gas is received, e.g., a flow of contaminated natural gas from the separator 102 after it has been separated from the crude oil and produced water. At step S2 the pressure and volume of the flow of natural gas is adjusted such that the flow rate or velocity of the gas will be less than 10 feet/sec., preferably < 5 feet/sec, as the treatment process continues. At step S3 it is determined whether the contaminated gas contains water and/or chemicals that are likely to precipitate from the treated gas in amounts such that these contaminants should be initially removed, and if YES, the contaminated gas is treated in the water wash flow cell 104 to remove ions of chemicals such as Na, Cl and C0 3 at step S4 and/or in step S5 is treated remove water down to less than 1 ppm, preferably < 0.5 ppm, e.g., in the coalescing unit 108 and optionally the chiller 106. If the answer at S3 is NO or after the chemicals and water are removed in steps S4, S5, at step S6 the flow of contaminated gas is then passed through a reactor such as the counter-flow reactor 110 where H 2 S and other targeted contaminants are remediated using the treatment composition, e.g., the treatment composition is injected via nozzles 120 to saturate a non-reactive media also disposed in the reactor with the treatment composition so that the gas will flow through the saturated media in the form of very small bubbles, e.g. average size ranging from about 1 - 50 milliliters, for at least 1.5 seconds. At step S7 some portion of the treatment composition in the reactor is removed, some of the water and possibly some other contaminants that have combined with the treatment composition are removed, e.g., by processing the treatment composition in the dehydratorl 12, and the dehydrated treatment composition is injected back into the reactor, along with additional new treatment composition. Finally at step SB, the treated natural gas as discharged from the reactor is sold, burned, transported to a refinery for further processing, or otherwise processed for transport and/or storage. Additionally, while not shown in FIG. 2, sensors will be provided in association with different components of the treatment system and various parameters of the treatment process may be monitored to make sure the contaminants are being properly remediated and that the various components of the system are operating properly, and if necessary appropriate adjustments may be made to keep the treatment process operating in an efficient manner.

[0053] The treatment process according to the exemplary embodiment may conducted at various temperatures, including ambient up to 200 °F, and may be conducted at various pressures, but for purposes of efficiency and given the flow rate, pressure and volume of natural gas from a well it may be desirable to conduct the treatment process at pressures significantly above ambient, e.g., 50-300 PSI, as the volume and velocity of the natural gas is reduced as pressure goes up, whereas the treatment system, process and composition according to the exemplary embodiment of the invention remains very effective at remediating the contaminants down to very low levels even as the pressure increases. The treatment process according to the exemplary embodiment may conducted in a continuous, partly continuous manner or batch manner, although for very large volumes of gas such as natural gas coming out of a well, batch manner may not be practical. A continuous or partly continuous treatment processes may involve flowing a continuous stream of the gas through the system. 100 for any given period of time , e.g., hours, days, weeks, etc., and the longer tire treatment process may continuously proceed while sufficiently remediating the contaminants in the gas, the more efficient and cost effective the process will be.

[0054] With the new treatment composi tion according to the exemplary embodiment of the present invention as used in a treatment system and process according to the above discussed aspects of the present invention, including a water wash flow cell to remove Na, Cl ions, a device for initially removing water from the natural gas, and a counter-flow reactor, the present inventor has successfully remediated the H 2 S and other targeted contaminants in natural gas, including mercaptans, thiophene and other disulfides, H 2 O, CO 2 , NaCl and nitrogen (N 2 ) down to less than 1 ppm each in a small scale operation, and without generation of any precipitates from the treated natural gas in the counter-flow reactor. It is expected that in a full scale operation, e.g., including a counter-flow reactor with a 2 ft ID and 21 ft tall, and at least 6 ft of which is packed with non-reactive media, a continuous flow of natural gas from a well at 2 million ft 3 / day, including 2,000 - 100,000 ppm H 2 S and other contaminants may be successfully treated down to less than 1 ppm for each of the contaminants by regulating the pressure of the gas within a range of 50-250 psi to assure that the gas flows at less than 10 feet/second, and preferably < 5 feet/ second, and using 1 -4 gallons/hour or 24-96 gallons total/day of the treatment composition according to the exemplary embodiment. Overall, such a treatment process is practical because it is very effective and cost efficient for remediating even highly contaminated natural gas, unlike ail known, conventional treatment processes existing prior to the present invention. The natural gas as treated using the treatment composition and treatment process according to the exemplary embodiment of the present invention is so clean, that it may be directly sold as sweet natural gas without further processing.

Similarly, it may be directly condensed into liquefied petroleum gas (LPG) in the vicinity of the well from which it is extracted, in such liquefied state the gas may be very economically stored and transported. Intent of Disclosure

[0055] Although the following disclosure 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.

[0056] 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 one exemplary embodiment of the treatment composition is a relatively dilute aqueous solution containing a large proportion of water, an alternative treatment composition and treatment process according to the present invention may involves preparing a concentrated version of the treatment composition which is not diluted with water, and then a much smaller volume of the concentrated treatment solution is added per unit of the contaminated liquid, e.g., a dosage of 0.005 - 1.5 ml, preferably 0.05 - 0.5 ml of the new concentrated treatment composition is added / liter of contaminated liquid. The effective dosage amounts of the chemical reactants used in this treatment process would be the same as the effective dosage amounts of these chemical reactants used in the treatment process using the diluted treatment composition, but significantly less water would be used - added to the liquid being treated.

[0057] Further, while the discussion of the invention herein discusses treatment of different types of fluids separately and in different processes, e.g., treatment of contaminated liquids such as crude oil and produced water by addition of dosages of treatment solution to the contaminated liquids and treatment of contaminated gasses such as natural gas by passing-bubbling the gas through a contained quantity of treatment composition, it is also possible to treat a mixture of contaminated fluids using the treatment compositions according to the present invention. For example, some pipelines that deliver petroleum based substances to a refinery or the like may accept a mixture of contaminated crude oil and contaminated natural gas, and it is within the scope of the present invention to simultaneously remediate the mixture of contaminated crude oil and contaminated natural gas by injecting dosages of a treatment composition according to the present invention into the mixed fluid so that the treatment composition may remediate both the contaminated crude oil and contaminated natural gas as the mixed fluid travels along the pipeline. While the contaminants in the crude oil and the natural gas may be remediated to different extents in such as treatment process, e.g., the contaminants in the liquid may be reduced below 5 ppm while the contaminants in the natural gas may be remediated down to 20-50% of the initial content, this may be acceptable for some pipelines and will favorably increase the value of the mixed fluid.

[0058] As another example, it is possible to include other components in the treatment composition of the exemplary embodiment, such as MEA as an anti-scaling agent, an antibacterial such as a sulfite compound, etc.