Reducing organosulfur fouling in refinery systems

Abstract

A method for removing or preventing organosulfur foulant material on structural parts is provided. The method includes adding a treatment composition to a liquid, gaseous or multiphase stream in contact with the organosulfur foulant material. The treatment composition includes one or more of (i) a hydroxylamine compound, (ii) an amine-formaldehyde reaction product, (iii) a bisulfite salt, (iv) a thiosulfate salt, (v) a salt of a hydroxyl amine compound, and (vi) an aldehyde. A composition for removing or preventing organosulfur foulant material on structural parts is also provided.

Description

REDUCING ORGANOSULFUR FOULING IN REFINERY SYSTEMS CROSS-REFERENCE TO RELATED APPLICATIONSThis application claims priority to United States Provisional Patent Application No.63 / 728,593, filed on December 5, 2024, which is incorporated by reference herein.BACKGROUND OF THE INVENTION

[0001] The present disclosure relates to reducing fouling in refineries, and in particular to reducing organosulfur fouling in distillation tower overhead systems.

[0002] Hydrogen sulfide and organic sulfides are coproduced with, exist in and / or are generated from hydrocarbon and water during the oil and gas production, transportation and processing. These sulfur-containing compounds are toxic and require sweetening, to ensure safe handling. One of the issues from sulfur-containing compounds is deposition. Sulfur- containing compounds are active compounds that tend to react with many organic species. For example, hydrogen sulfide can react with various organic compounds that may be present in hydrocarbon processing systems or refineries, such as amine-based H2S scavengers, triazine H2S scavengers, aldehyde H2S scavengers, unsaturated hydrocarbons, and formaldehyde. These hydrogen sulfide reaction products often form depositions, which can harm overhead systems in crude and vacuum units by causing loss of heat transfer, loss of through-put or even plugging of the pipes and filters. Plus, the deposits also cause quality concerns of various fuel cuts, corrosion and a hazard to important water streams.

[0003] One of the H2S-reaction products that readily form solid materials and cause depositions is dithiazine. Dithiazine in polymeric or amorphous form results from the reaction of a triazine hydrogen scavenger compound and H2S. Dithiazine deposits can form in scavenger contact towers, sour water operations, crude unit overheads, distillation tower overhead systems and natural gas plants.

[0004] One proposed solution for reducing dithiazine fouling is to control the stoichiometry of triazine and H2S or to use alternative scavengers that cause reduced solids. However, this is difficult to achieve when the source of the stream containing the scavenger is unknown or cannot be controlled by the plant. Another common method is the use of oxidizers, such as peroxide, for dissolution of dithiazine during turnaround and shutdown. However, shutdown 1ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)of the plant is required for this approach.

[0005] Recent efforts to mitigate dithiazine fouling were the use of mercaptans / amines (Conoco Phillips, WO 2022 / 076460 Al) and nitriles (Ascend, WO 2022 / 066969 Al). However, these chemistries are toxic and / or expensive to use.

[0006] Therefore, what is needed are improved cost-effective treatments for reducing or removing organosulfur fouling for hydrocarbon refineries.SUMMARY OF THE INVENTION

[0007] The present technology provides for effective treatments to mitigate organosulfur fouling and deposits to benefit hydrocarbon refinery processes. Sulfur-containing organic deposit is a high risk for refineries. As these deposits are frequent in the overhead portion of fractionation towers, expensive shut-downs are needed to remove the deposits.

[0008] In one aspect of the disclosed technology, a method for reducing organosulfur foulant material on structural parts in a refinery is provided. The method provides for adding a treatment composition to a liquid, gaseous or multiphase stream in contact with the organosulfur foulant material where the treatment composition comprises one or more of: (i) a hydroxylamine compound, (ii) an amine-formaldehyde reaction product, (iii) a bisulfite salt, (iv) a thiosulfate salt, (v) a salt of a hydroxylamine, and (vi) an aldehyde.

[0009] In another aspect of the disclosed technology, a treatment composition for removing or preventing organosulfur foulant material on structural parts contacted by liquid, gaseous or multiphase streams is provided. The treatment provides for one or more of (i) a hydroxylamine compound, (ii) an amine-formaldehyde reaction product, (iii) a bisulfite salt, (iv) a thiosulfate salt (v) a salt of a hydroxylamine compound and (vi) an aldehyde.

[0010] The present technology provides for a treatment for mitigating dithiazine / organosulfur fouling in a refinery or natural gas liquid plant. The technology herein provides inhibitor(s) which react with the sulfur-containing organic deposits, and / or their precursors and form stable compounds. The formation of deposit is therefore mitigated or inhibited. The inhibitor chemicals of the present technology significantly reduce dithiazine / organosulfur solids in the wash water system during plant operation. The reduction in dithiazine solids resulted in2ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)significant savings by reducing filter changes, increasing refinery throughput and allowing the refinery’ to operate at optimal conditions.BRIEF DESCRIPTION OF THE DRAWINGS

[0011] The features and advantages of the invention are apparent from the following description taken in conjunction with the accompanying drawings in which:

[0012] FIG. 1 is a schematic depicting a process flow chart of an atmospheric-vacuum crude unit complex with possible injection points;

[0013] FIGS. 2A and 2B are illustrations of vial samples as described in Examples;

[0014] FIG. 3 is an illustration of vial samples as described in Examples;

[0015] FIG. 4 is a graph of ppmw True Active vs Turbidity Reduction % for Refinery Seal Drum Water;

[0016] FIGS. 5 A and 5B are bar graphs depicting time and absorbance;

[0017] FIGS. 6A-6C are bar graphs depicting absorbance and dose amount; and

[0018] FIGS. 7A and 7B are bar graphs depicting absorbance and dose amount.DETAILED DESCRIPTION OF THE INVENTION

[0019] Dithiazines and other organosulfur compounds can cause significant fouling in refinery systems. The present technology provides for a novel chemical solution for controlling dithiazine / organosulfur fouling and a method to minimize fouling in distillation tower overhead systems and improve overall operability’ and reliability in refinery’ processes,

[0020] In one aspect, a method for reducing organosulfur foulant material on structural parts in a refinery is provided. The method comprises adding a treatment composition to a liquid, gaseous or multiphase stream in contact with the organosulfur foulant material. The treatment composition of the present technology comprises one or more of (i) a hydroxylamine compound, (ii) an amine-formaldehyde reaction product, (iii) a bisulfite salt, (iv) a thiosulfate salt, (v) a salt of a hydroxylamine, and (vi) an aldehyde.3ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)

[0021] In some embodiments, a method for reducing and dissolving sulfur-containing organic deposits in refinery equipment, such as a distillation overhead system is provided.

[0022] The fouling material is an organosulfur foulant. In one embodiment, the foulant can be organosulfur material, dithiazine material or paraformaldehyde compounds. In one embodiment, the foulant material is a dithiazine. In some embodiments, the dithiazine material is polymeric or amorphous, In another embodiment, the dithiazine is a monoethanolamine (MEA) dithiazine. It should be understood that an MEA dithiazine is the reaction product of H2S and MEA triazine, which is the most widely used H2S scavenger. Other aldehyde-based scavengers also result in fouling in the overhead due to decomposition and release of formaldehyde to distillation tower overheads. In some cases, the fouling can be due to polymeric formaldehyde, i.e., paraformaldehyde, and its reaction product with H2S in the overhead forming methylene sulfide oligomers / polymer, which is sometimes also referred to as polythioformaldehyde. High heat in the system, such as from a reboiler, accelerates the formation of polymeric dithiazine, formaldehyde or thioformaldehyde / methylene sulfide solids, as well as their decomposition to push the precursors to the overhead.

[0023] The foulant material deposits on equipment and structural parts of the refinery system. Structural parts may be any type of refinery equipment for processing, storage and transportation. For example, the foulant material may deposit in the distillation tower overhead, a reboiler, pipes, wellbore, desalter, vacuum unit, oil tanks or seal drum where this deposited foulant material is in contact with a liquid stream, gaseous stream or multiphase stream. In one embodiment, the liquid stream may be aqueous or a water stream. In another embodiment, the liquid stream is a hydrocarbon stream. In some embodiments, the hydrocarbon stream is raw crude, desalted crude, heavy naphtha, kerosene, light gas oil (LGO), heavy gas oil (HGO), diesel, light vacuum gas oil (LVGO), heavy vacuum gas oil (HVGO), or a combination thereof. In some embodiments, the liquid stream may include at least two liquid streams. In another embodiment, the liquid stream includes a water stream and a hydrocarbon stream, such as an oil stream. In some embodiments, the gaseous stream is a gaseous hydrocarbon stream or steam. In some embodiments, a multiphase stream is provided. In one embodiment, the multiphase stream includes a liquid stream and a gaseous stream. In one embodiment, the multiphase stream includes a liquid stream and a gaseous stream.

[0024] The foulant material is treated by adding a treatment composition to the liquid or gaseous stream that is in contact with deposited foulant material. Chemical inhibitor(s) are 4ME1\59188041. vlAttorney Docket No. 140015-27820 (PP2024_015-WO)fed to the water / hydrocarbon / gas systems to react with sulfur-containing organic deposits, their precursors and mixtures thereof. In one embodiment, the treatment composition can be added to hydrocarbon production systems, including transportation and processing, in a single location, In another embodiment, the treatment composition may be added at multiple locations. Inhibitors can be added to a hydrocarbon, aqueous, gaseous or mixed phase stream, in equipment that is customary for hydrocarbon processing, transportation or storage, such as but not limited to a wellbore, pipelines, tanks, a desalter, pump-around stream equipment, distillation tower overhead systems, vacuum distillation unit, atmospheric distillation unit, distillation flash zones, fractionation columns and heat exchangers.

[0025] FIG, 1 depicts a schematic of an atmospheric -vacuum crude unit complex 10 for refining a liquid hydrocarbon stream, such as raw crude or crude oil. FIG. 1 provides examples of locations for adding the treatment composition. Raw crude 20 enters a desalting system 30, such as a desalter, where brine water is separated from the raw crude. The desalted crude is heated in a furnace to a temperature sufficient (for example, about 700°F to about 750°F) to vaporize a distillate fraction and at least a portion of a liquid bottom fraction of the raw crude. The heated crude is fed to the bottom portion of an atmospheric distillation unit (ADU) tower or ADU fractionation column 50 where the mixture is refluxed and separated into vapor and liquid phases or fractions. The vapor phase rises through the ADU column. The liquid fraction or phase falls to the bottom of the ADU column and is contacted with steam S to evaporate low-boiling distillate components that are dissolved in the heavier liquid phase.

[0026] The vapor phase rises through the ADU column 50 contacting fractionation trays or contact stages (not shown) in the column. Distillate fractions with different boiling points condense at different boiling points while lighter fractions continue up through the ADU column 50. Tire different fractions cool and condense at different levels and can be separated or removed from the ADU column 50. The raw crude or crude oil 20 is separated into distillate fractions of Heavy Gas Oil (HGO), Light Gas Oil (LGO), Kerosene, Heavy Naphtha (HN) and Naphtha or Light Naphtha, The HGO, LGO, Kerosene and Heavy Naphtha distillate products are drawn from the side of the ADU column 50, Steam stripper columns 60 on the side of the ADU column provide reflux to the ADU column 50 and further process the distillate products. A naphtha vapor fraction 70 is removed from the top of the AD U column5ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)50 and further processed in a distillation tower overhead system 80 to produce a liquid naphtha,

[0027] The bottom product, atmospheric distillation residue, 90 is removed from the bottom of the ADU column 50, heated in a furnace 45 and fed to a bottom portion of a vacuum distillation unit or VDU column 100 for further processing. In one embodiment, the distillation residue is heated to about 730°F or in another embodiment, from about 730°F to about 850°F. Vacuum distillation is necessary to fractionate the heavy distillates from the atmospheric distillation residue. Different packing materials (not shown) are used instead of fractionation trays to provide contact stages between liquid and vapor streams to separate the atmospheric distillation residue into different fractionation layers. Steam S is introduced into the bottom of the VDU column 100 to create a vacuum for evaporation of a heavy vacuum gas oil (HVGO), a light vacuum gas oil (LVGO), and diesel, as well as the vacuum bottoms or vacuum residue 110. The HVGO, LVGO and diesel fractions may be further processed in downstream separation and conversion units (not shown). Some of the separated fractions may be returned to the VDU column for refluxing and aiding in fractionation. A vapor stream 120 exits the top of the VDU column 100 and is mixed with steam in an ejector system 130. The ejector system 130 works with the seal drum 140 to pull a vacuum within the VDU column 100, enabling efficient separation of the lighter hydrocarbon fractions at lower boiling points. The seal drum 140 is an enclosed vessel containing a liquid, such as a hydrocarbon condensate, that acts as a barrier, preventing backflow of atmospheric air into the vacuum system while allowing a vapor stream 120 to be drawn off.

[0028] The atmospheric-vacuum crude unit complex may include heat exchangers and pump around loops (not shown) to pre-heat the desalted crude before it is fed into the furnace and to provide additional reflux to the ADU or VDU columns.

[0029] FIG. 1 provides examples of suitable location points, marked with an A, for adding a treatment composition as previously described to a refinery process for treating foulant materials and deposited foulant material. Suitable locations for adding a treatment composition are provided in FIG. 1, but are not limited to the locations shown in FIG. 1. In one embodiment, the treatment composition as previously described is added to a liquid hydrocarbon stream for processing in a refinery’. In some embodiments, the treatment composition is added to a liquid hydrocarbon stream before processing. In another embodiment, treatment composition is added to a liquid hydrocarbon stream during6ME1\59188041. vlAttorney Docket No. 140015-27820 (PP2024_015-WO)processing. In some embodiments, the treatment composition is added to a liquid hydrocarbon stream prior to being heated, such as in a heat exchanger or furnace. In another embodiment, a treatment composition is added to a liquid hydrocarbon stream before entering a distillation column or fractionation column. In another embodiment, the treatment composition is added to a gaseous stream, such as a steam stream for processing hydrocarbon material. In another embodiment, the treatment composition is added to a hydrocarbon vapor stream, such as a naphtha vapor stream, before processing in a distillation tower overhead system. In another embodiment, the treatment composition is added to a mixed phase stream, such as liquid and gaseous hydrocarbon, in a distillation tower overhead system. In another embodiment, the treatment composition is added to a mixed phase stream, such as a liquid hydrocarbon, gaseous hydrocarbon and vapor aqueous stream.

[0030] The treatment composition as previously described is added to a liquid, gaseous or mixed phase stream in any customary manner. In one embodiment, tire treatment composition is injected into the liquid, gaseous or mixed phase stream to be treated.

[0031] Treatment compositions are added to the liquid or gaseous streams in contact with the organosulfur foulant material for treating the organosulfur deposition material. In some embodiments, the treatment composition comprises one or more inhibitors. In some embodiments, the inhibitor includes hydroxylamine derivatives or hydroxylamine compounds. In one embodiment, the hydroxylamine compound has formula:Rl / R2where Rl and R2 are independently selected from hydrogen or a C1-C20 hydrocarbyl group. In one embodiment, the C1-C20 hydrocarbyl group is a C1-C20 alkyl group. In another embodiment, the C1-C20 alkyl group includes, but is not limited to, methyl, ethyl, propyl, butyl, hexyl, or pentyl. In another embodiment, Rl and R2 are the same C1-C20 hydrocarbyl group. In one embodiment, Rl and R2 are ethyl. In another embodiment, the hydroxylamine compound is diethylhydroxylamine.7MEl\59188041.vlAttorney Docket No. 140015-27820 (PP2024_015-WO)

[0032] In one embodiment, the inhibitor is an amine-formaldehyde reaction product. In one embodiment, the reaction product results from the reaction of an amine with a formaldehyde. In one embodiment, the amine has the following structure:where a is from 1 to 10, b is from 0 to 10 and c is from 0 to 10. In one embodiment, b is 0. In another embodiment, b is from 1 to 10. In one embodiment, c is 0. In another embodiment, c is from 1 to 10. In one embodiment, the amine includes a structure where a is from 1 to 10; and b and c are 0. In another embodiment, a is from 1 to 10, b is 0 and c is from 1 to 10. In another embodiment, a is from 1 to 10, b is from 1 to 10 and c is 0. In another embodiment, a, b and c are each in a range of from 1 to 10.

[0033] In one embodiment, the inhibitor is an amine-formaldehyde reaction product. In one embodiment, the reaction product results from the reaction of an amine with a formaldehyde. In one embodiment, the amine has the following Markush structure:where Rl, R2 and R3 are independently selected from hydrogen or a C1-C20 hydrocarbyl group and n is from 1 to 20.

[0034] in one embodiment, the C1-C20 hydrocarbyl group is a C1-C20 alkyl group. In another embodiment, the C1-C20 alkyl group includes, but is not limited to, methyl, ethyl, propyl, butyl, hexyl, or pentyl. In one embodiment, Rl is hydrogen and R2 and R3 are the same C1-C20 hydrocarbyl group. In another embodiment, Rl is hydrogen and R2 and R3 are both propyl8MEl\59188041.vlAttorney Docket No. 140015-27820 (PP2024_015-WO)groups. In one embodiment, the amine-formaldehyde reaction product is a dipropylamineformaldehyde reaction product.

[0035] In some embodiments, the inhibitor includes a bisulfite salt. In one embodiment, the bisulfite salt is selected from alkali metal bisulfite salts, ammonium -based bisulfite salts, amine-based bisulfite salts, alkali metal metabisulfite salts, ammonium-based metabisulfite salts or amine-based metabisulfite salts. In another embodiment, tire bisulfite salt is a sodium bisulfite salt and / or an ammonium bisulfite salt,

[0036] In some embodiments, the inhibitor includes a thiosulfate salt. In one embodiment, the thiosulfate salt is selected from alkali metal thiosulfate salts, ammonium-based thiosulfate salts and amine-based thiosulfate salts. In another embodiment, the thiosulfate salt is a sodium thiosulfate salt or an ammonium thiosulfate salt.

[0037] In some embodiments, the inhibitor includes a salt of a hydroxylamine compound. In one embodiment, the compound comprises a counter-anion and a hydroxylamine compound. In one embodiment, the counter-anion is an organic, inorganic or mixed counter-anion. In another embodiment, the counter-anion is selected from the group consisting of chloride, sulfate, nitrate, formate, acetate, propionate, butyrate, and alkanesulfonate. In some embodiments, the alkane sulfonate is a C1-C20 alkanesulfonate.

[0038] In one embodiment, the hydroxylamine compound of the hydroxylamine salt compound has formula: / rawhere R1 and R2 are independently hydrogen or a C1-C20 hydrocarbyl group, and the hydroxylamine is as previously described. In one embodiment, the salt of the hydroxylannne compound is a hydroxylamine sulfate.

[0039] In some embodiments, the treatment composition includes a blend of inhibitors. In one embodiment, the treatment composition includes diethylhydroxylamine and hydroxylamine sulfate.9MEl\59188041.vlAttorney Docket No, 140015-27820 (PP2024_015-WO)

[0040] In one embodiment, the treatment composition includes an aldehyde. In one embodiment, the aldehyde may be an alkylaldehyde, such as a C1-C20 alkylaldehyde. In another embodiment, the aldehyde is selected from formaldehyde, arylaldehyde, methoxyaldehyde, hydroxyaldehyde, cinnaminaldehyde, glyceraldehyde, vanillin, veratraldehyde, alloxan, noneal, 1 -formyl piperdine, salicylaldehyde, citronella, paraformaldehyde, methyl formal, acetaldehyde, paraldehyde, glycoladehyde, hydroxymethyl glyceraldehyde, butyl formal, trioxane, tetroxane, glyoxal, and methyl formcel. In one embodiment, the aldehyde is glyoxal.

[0041] in another embodiment, the treatment composition includes other additives, such as overhead neutralizers, filmers and / or dispersants.

[0042] The inhibitor composition of the present technology can be added in any amount effective for removing or dissolving the organosulfur foulant material on structural parts of the refinery. In some embodiments, the inhibitor composition is added continuously or intermittently. In one embodiment, the inhibitor composition is added in an amount from about 100 ppm by weight to 10,000 ppm by weight. In another embodiment, the inhibitor is added in an amount from about 300 ppm by weight to about 5000 ppm by weight. In another embodiment, the inhibitor composition is added in an amount from about 1000 ppm by weight to about 2000 ppm by weight.

[0043] In another aspect of the disclosed technology, a treatment composition, as previously described above, is provided. The treatment composition removes or prevents organosulfur foulant material on structural parts contacted by liquid, gaseous or multiphase streams is provided. The treatment composition provides for one or more of (i) a hydroxylamine compound, (ii) an amine-formaldehyde reaction product, (iii) a bisulfite salt, (iv) a thiosulfate salt (v) a salt of a hydroxylamine compound and (vi) an aldehyde.

[0044] EXAMPLES

[0045] Example 1

[0046] Refinery Seal Drum Water — Bottle Tests

[0047] Water samples (A-L) were collected and separated in 50 ml aliquots and sealed in 2-ounce (59 ml) vials, 1000 ppm by weight True Actives (TA) of inhibitors were dosed to treat10ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)the water. The treated and blank samples were place in a 60°C oven for 24 hours. Haziness and deposits formed on the walls were rated and the results are shown in Table 1. Pictures of the samples before treatment and after treatment are shown in FIGS. 2A and 2B, respectively.

[0048] Table 1Sample Treatment Haziness Deposit pH Rating RatingA Untreated not heated 3 0 6.4B Untreated @ 60C 3.5 0 6.5C Diethylenetriamine 2 1 10.8 D Diethylhydroxylamine 1.5 1 7.4E Triethylene glycol 3 0 6.1F Dipropylamine 1 0 11.1formaldehyde reactionproductG Monoethanolamine 1.5 1 10.2TriazineH NaOH 1 4 12.4(peel off)I Acetic Acid 3 1 4.1J Fatty acid 4 0 7.5Diethylhydroxylamine (insoluble)reaction productK Mixture of J and 1,5 (foaming) 1 5.3hydroxyacetic acid11ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)L Hydroxylamine 0.5 4.0sulfate

[0049] The ratings for Haziness and Deposit were on a 0-5 scale where 0 is the best and 5 is the worst. Sample K exhibited foaming, which was not acceptable. Samples C (Diethylenetriamine), D (Diethylhydroxylamine), F (Dipropylamine formaldehyde reaction product), G (Monoethanolaniine triazine) and L (Hydroxylaniine sulfate) exhibit good haziness values at 2 or below and good deposit ratings of 1 or less,

[0050] Example 2

[0051] Hie samples for Diethylhydoxylamine, Dipropylamine formaldehyde reaction product and Hydroxylamine sulfate were tested at different dosage amounts. The samples were prepared as in Example 1. A picture was taken of the treated samples (see FIG. 3). Results are shown in Table 2.

[0052] Table 2Name Chemical Name Dosage Haziness Deposit pH (TA) Rating RatingA Untreated, not heated 3 0 6.4 B, C Untreated @, 60°C 3.5 0 6.5 D Diethylhydroxylamine 1000 ppmw 1.5 1 7.4 E Diethylhydroxylamine 300 ppmw 2 0 7.1 F Diethylhydroxylamine 100 ppmw 2.5 0 7.0G Diethylhydroxylamine 30 ppmw 3 0 6.5 H Dipropylamine formaldehyde 1000 ppmw 0 11.1 reaction product12ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)I Dipropylamine formaldehyde 300 ppmw 1.5 0 11.0 reaction productJ Dipropylamine formaldehyde 100 ppmw 2 0 10.2 reaction productK Dipropylamine formaldehyde 30 ppmw 2.5 0 7.6 reaction productL Hydroxylamine Sulfate 100 ppmw 2.5 2M Hydroxylamine Sulfate 300 ppmw 1 1N Hydroxylamine Sulfate 500 ppmw 0 10 Hydroxylamine Sulfate 600 ppmw 0 1P Hydroxylamine Sulfate 800 ppmw 0 1Q Hydroxylamine Sulfate 1000 ppmw 0 1 (gone in2 wks)

[0053] The ratings for Haziness and Deposit were on a 0-5 scale where 0 is the best and 5 is the worst. Samples D (Diethylhydroxylamine) @, 1000 ppm by weight TA, H (Dipropylamine formaldehyde reaction product) @ 1000 ppm by weight TA, I (Dipropylamine formaldehyde reaction product) @ 300 ppm by weight TA and Hydroxylamine sulfate samples of M, N, O, P, Q @ 300 ppm by weight TA, 500 ppm by weight TA, 600 ppm by weight TA, 800 ppm by weight TA and 1000 ppm by weight TA, respectively, all exhibited very good haziness ratings of 1.5 or less. Samples E (Diethylhydroxylamine) @ 300 ppm by weight TA and J (Dipropylamine formaldehyde reaction product) @ 100 ppm by weight TA exhibited good haziness ratings at 2.

[0054] Example 3

[0055] Refiner}' Seal Drum Water — Turbidity Tests13ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)

[0056] Water samples were treated with varying dosages of inhibitors at room temperature. The samples were prepared as in Example 1. The inhibitors tested were: hydroxylamine sulfate (HAS), a Faty acid Diethylhydroxylamine reaction product (RXN 1), Diethylhydroxylamine (DEHA), Diethylenetriamine (DETA), Acetic Acid, NaOH, Monoethanolamine triazine (MEA-Tri, Dipropylamine formaldehyde reaction product (RXN 2), Triethylene Glycol (Tri-Gly) and a Mixture of Faty acid Diethylhydroxlamine reaction product (RXN 1) and Hydroxyacetic acid (HAA). The treated and blank samples were placed in a 60°C oven for 24 hours. Haziness and deposits formed on the walls were rated. The ratings for Haziness and Deposit were on a 0-5 scale where 0 is the best and 5 is the worst. Turbidity was measured with UV-vis by averaging the absorbance 400-680 nm and converted with the formula: Turbidity = 2.3 * Abs / L, where Abs is Absorbance, normally 400-680 nm and L is the optical length of the sample, which is 1 cm for these measurements. Tire treated turbidity samples were compared to the Blank sample to obtain Turbidity reduction %. Results are shown in Table 3. FIG. 4 shows a graph of turbidity reduction of the refinery seal drum water results (ppm by weight True Active vs. Turbidity Reduction % of 400-680 nm average). FIG. 4 shows chemical treatment samples Hydroxylamine Sulfate, Dipropylamine Formaldehyde Reaction product and Diethylhydroxylamine. All three chemical treatment samples are effective. Hydroxylamine sulfate exlii bited tire best results.

[0057] Table 3Turbidity Turbidity Turbidity Turbidity Turbidity Turbidity ppmw @420 @660 @400’680 Deposit reduction reduction reductionTA -i PH Rating (cm ) (cm ) (cm ) @420 @660 @400-680 Blank @0 1.89 0.96 1.34 0.00% 0.00% 0.00% 6.5 0 60CHAS 100 1.59 0.94 1.24 15.62% 2.32% 7.77% 4.8 2 HAS 300 0.33 0.29 0.30 82.70% 69.30% 77.75% 4.4 1 HAS 500 0.18 0.12 0.14 90.50% 87.27% 89.90% 4.2 1 HAS 600 0.17 0.11 0.12 91.05% 88.72% 90.77% 4.3 1 HAS 800 0.16 0.10 0.11 91.49% 89.66% 91.47% 4.1 11 (gone in HAS 1000 0.25 0.19 0.2 86.77% 80.21% 85.07% 42wks) RXN 1 1000 4.45 1.41 2.54 -135.45% -46.88% -89.55% 7.5 0 DEHA 30 1.96 1.43 1.68 -3.70% -48.96% -25.37% 6.5 0 DEHA 100 1.77 1.33 1.55 6.35% -38.54% -15.67% 7 014ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)DEHA 300 1.49 1.05 1.26 21.16% -9.38% 5.97% 7.1 0 DEHA 1000 0.86 0.44 0.61 54.50% 54.17% 54.48% 7.4 1 DETA 1000 0.66 0.33 0.46 65.08% 65.63% 65.67% 10.8 1 Acetic1000 0.79 0.4 0.56 58.20% 58.33% 58.21% 4.1 1 AcidNaOH 1000 0.6 0.38 0.46 68.25% 60.42% 65.67% 12.4 4 MEA-Tri 1000 0.95 0.51 0.69 49.74% 46.88% 48.51% 10.2 1 RXN 2 30 1.89 1.35 1.61 0.00% -40.63% -20.15% 7.6 0 RXN 2 100 1.63 1.19 1.39 13.76% -23.96% -3.73% 10.2 0 RXN 2 300 1.51 1.03 1.25 20.11% -7.29% 6.72% 11 0 RXN 2 1000 0.68 0.3 0.44 64.02% 68.75% 67.16% 11.1 0 Tri-Gly 1000 2.09 1.09 1.5 -10.58% -13.54% -11.94% 6.1 0 Mix ofRXN I and 1000 1.27 0.53 0.79 32.80% 44.79% 41.04% 5.3 1 (foaming)HAA

[0058] Example 4

[0059] Refinery Overhead Coalescer Deposit

[0060] Treatment samples Hydroxylamine sulfate (TS-1), Diethylhydroxylamine (TS-2), Dipropylamine Formaldehyde Reaction product (TS-3) and Dibutylamine Formaldehyde Reaction product (TS-4) were tested on another sulfur-containing deposit collected from a Refinery overhead coalescer. A Blank was also run. 1000 ppm by weight of the deposit was dispersed in deionized (DI) water by ultrasonication. Samples of the dispersed deposit in DI water were treated with the treatment samples and heated to 60°C for 24 hours. Turbidity was measured for each sample by UV-Vis as described in Example 3. Results are shown in Table 4.

[0061] Table 4Treatment ppmw Turbidity Turbidity Turbidity Turbidity Turbidity Turbidity Deposit Sample TA @420 @660 @400- reduction reduction reduction Rating (cm"1) (cm’1) 680 (cur1) @420 @660 @400- 680Blank 0 2.53 1.66 2.04 0.00% 0.00% 0.00% 0 TS-1 1000 1.53 1.21 1.35 39.60% 27.21% 33.66% 0 TS-2 1000 2.39 1.82 2.08 5.78% -9.68% -1.88% 0 TS-3 1000 1.80 0.94 1.29 28.95% 43.30% 36.78% 215ME1\59188041. vlAttorney Docket No, 140015-27820 (PP2024_015-WO)TS-4 1000 1.79 1.23 1.47 29.37% 26.07% 28.02% 0

[0062] The Deposit ratings were on a 0-5 scale where 0 is the best and 5 is the worst.

[0063] Tire TS-1 treatment (Hydroxylamine sulfate) showed improved turbidity results over the Blank, although not as high as the turbidity results shown in Example 3. It is believed that the age of the treatment sample (TS-1) and the S / C content may have been a factor.

[0064] Example 5

[0065] Samples hydroxylamine sulfate (HAS), diethyl hydroxylamine (DEHA), mixture of HAS and DEHA in 1:1 ppmw TA / ppmw TA ratio, ammonium bisulfite, sodium bisulfite and mixture of ammonium bisulfite to sodium bisulfite in 1: 1 ppmw TA / ppmw TA ratio were tested on organosulfur solids and compared to blank samples. The samples were treated with 500 ppm by weight TA of an inhibitor and heated to 80°C. Data is shown in FIGS. 5A and 5B. HAS, DEHA and the mixture of HAS and DEHA were effective in reducing absorbance / turbidity. Hydroxylamine sulfate (HAS) was the most effective treatment, followed by Diethyl hydroxyl amine (DEHA). Ammonium bisulfite (NH4 Bisulfite), Sodium bisulfite (Na Bisulfite) and Mixture of NH4 Bisulfite and Na Bisulfite were also found to be effective in reducing the absorbance / turbidity due to organosulfur solids compared to the blank / un treated case.

[0066] Example 6

[0067] Samples DEHA and HAS were tested at varying amounts of inhibitor and compared with a Blank sample on organosulfur solids in a refinery' sample. Hie samples were heated to 80°C. Results for DEHA are shown in FIG. 6A. Results for HAS are shown in FIG. 6B. FIG.6C shows results for a mixture of DEHA and HAS in 1: 1 ppmw TA / ppmw TA ratio. HAS was significantly more effective in reducing the absorbance / turbidity compared to DEHA.

[0068] Example 7

[0069] The HAS sample was tested with the addition of an amine Neutralizer (MDEA) and with the addition of DEHA (mixture of DEHA and HAS in 1:1 ppmw TA / ppmw TA ratio) at different dose amounts. The pH of the samples was adjusted to 7.3 with the addition of MDEA and heated to 80°C. Results are shown in FIGS. 7A and 7B. HAS was effective in removing turbidity (reduced absorbance) even with methyl diethanolamine (MDEA).16ME1\59188041. vl

Claims

Attorney Docket No. 140015-27820 (PP2024_015-WO)CLAIMSWhat is claimed is:

1. A treatment composition for removing or preventing organosulfur foulant material on structural parts contacted by liquid, gaseous or multiphase streams, the composition comprising one or more of (i) a hydroxylamine compound, (ii) an amine-formaldehyde reaction product, (iii) a bisulfite salt, (iv) a thiosulfate salt, (v) a salt of a hydroxylamine compound, and (vi) an aldehyde.

2. The treatment composition of claim 1, wherein the hydroxylamine compound has formula:RI / R2wherein R1 and R2 are independently hydrogen or a C1-C20 hydrocarbyl group.

3. The treatment composition of claim 1, wherein the hydroxylamine compound is di eth y Ihy droxy 1 am ine.

4. Tire treatment composition of claim I. wherein the amine -formal dyde reaction product results from the reaction of an amine with a formaldehyde, and wherein tire amine has the following structure:NWwherein a is from 1 to 10, b is from 0 to 10 and c is from 0 to 10.17MEl\59188041.vlAttorney Docket No. 140015-27820 (PP2024_015-WO)5. The treatment composition of claim 1, wherein the amine-formaldehdye reaction product results from the reaction of an amine with a formaldehyde, and wherein the am ine has the following structure:wherein Rl, R2 and R3 are each independently hydrogen or a C1-C20 hydrocarbyl group; and n is 1 to 20.

6. The treatment composition of claim 1, wherein the amine-formaldehyde reaction product is a dipropylamine-formaldehyde reaction product.

7. Tire treatment composition of claim 1, wherein the bisulfite salt is selected from alkali metal bisulfte salts, ammonium or amine-based bisulfite salts, alkali metal metabisulfite salts, and ammonium or amine-based metabisulfite salts.

8. The treatment composition of claim 1, wherein the bisulfite salt is a sodium bisulfite salt and / or an ammonium bisulfite salt.

9. The treatment composition of claim 1, wherein the thiosulfate salt is selected from an alkali metal thiosulfate salt, an ammonium-based thiosulfate salt and an amine-based thiosulfate salt.

10. Tire treatment composition of claim 1, wherein the salt of a hydroxylamine compound comprises a counter-anion and a hydroxylamine compound, wherein the counter-anion is selected from the group consisting of chloride, sulfate, nitrate, formate, acetate, propionate, butyrate, and alkanesulfonate, and wherein the hydroxylamine compound has formula:Rl- 0 - H / wherein Rl and R2 are independently hydrogen or a C1-C20 hydrocarbyl group.18MEl\59188041.vlAttorney Docket No. 140015-27820 (PP2024_015-WO)11. The treatment composition of claim 1, wherein the salt of a hydroxylamine is a hydroxylamine sulfate,12. The treatment composition of claim 1, wherein the aldehyde is selected from formaldehyde, arylaldehyde, methoxyaldehyde, hydroxyaldehyde, cinnaminaldehyde, glyceraldehyde, vanillin, veratraldehyde, alloxan, noneal, 1 -formyl piperdine, salicylaldehyde, citronella, paraformaldehyde, methyl formal, acetaldehyde, paraldehyde, glycoladehyde, hydroxymethyl glyceraldehyde, butyl formal, trioxane, tetroxane, glyoxal, and methyl formcel.

13. Tire treatment composition of claim 1, wherein the aldehyde is glyoxal.

14. A method for removing or preventing organosulfur foulant material on structural parts, the method comprising adding a treatment composition to a liquid, gaseous or multiphase stream in contact with the organosulfur foulant material wherein the treatment composition comprises one or more of (i) a hydroxylamine compound, (ii) an amine-fonnaldehyde reaction product, (iii) a bisulfite salt, (iv) a thiosulfate salt, (v) a salt of a hydroxylamine compound, and (vi) an aldehyde.

15. The method of claim 14, wherein the hydroxylamine compound has formula: / wherein R1 and R2 are independently hydrogen or a C1-C20 hydrocarbyl group.

16. The method of claim 14, wherein the hydroxylamine compound is diethylhydroxylamine, 17. Tire method of claim 14, wherein the amine-formaldyde reaction product results from the reaction of an amine with a formaldehyde, and wherein the amine has the following structure:19MEl\59188041.vlAttorney Docket No. 140015-27820 (PP2024_015-WO)wherein a is from 1 to 10, b is from 0 to 10 and c is from 0 to 10,18, The method of claim 14, wherein the amine-formaldehdye reaction product results from the reaction of an amine with a formaldehyde, and wherein the amine has the following structure:R2R< R.$wherein Rl, R2 and R3 are each independently hydrogen or a C1-C20 hydrocarbyl group; and n is 1 to 20.

19. The method of claim 14, wherein the amine-formaldehyde reaction product is a dipropylamine-formaldehyde reaction product.

20. The method of claim 14, wherein the bisulfite salt is selected from alkali metal bisulfte salts, ammonium or amine-based bisulfite salts, alkali metal metabisulfite salts, and ammonium or amine-based metabisulfite salts.

21. The method of claim 14, wherein the bisulfite salt is a sodium bisulfite salt and / or an ammonium bisulfite salt.

22. The method of claim 14, wherein the thiosulfate salt is selected from an alkali metal thiosulfate salt, an ammonium-based thiosulfate salt and an amine-based thiosulfate salt.

23. Tire method of claim 14, wherein the salt of a hydroxylamine compound comprises a counter-anion and a hydroxylamine compound, wherein the counter-anion is selected from the group consisting of chloride, sulfate, nitrate, formate, acetate, propionate, butyrate, and alkanesulfonate, and wherein the hydroxylamine compound has formula:20MEl\59188041.vlAttorney Docket No. 140015-27820 (PP2024_015-WO)1R2wherein R1 and R2 are independently hydrogen or a C1-C20 hydrocarbyl group.

24. Tire method of claim 14, wherein the salt of a hydroxylamine is a hydroxylamine sulfate, 25. The method of claim 14, wherein the aldehyde is selected from formaldehyde, arylaldehyde, methoxyaldehyde, hydroxyaldehyde, cinnaminaldehyde, glyceraldehyde, vanillin, veratraldehyde, alloxan, noneal, 1 -formyl piperdine, salicylaldehyde, citronella, paraformaldehyde, methyl formal, acetaldehyde, paraldehyde, glycoladehyde, hydroxymethyl glyceraldehyde, butyl formal, trioxane, tetroxane, glyoxal, and methyl formcel.

26. The method of claim 14, wherein the aldehyde is glyoxal.21MEl\59188041.vl

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