US20110031165A1 - Processes for removing hydrogen sulfide from refined hydrocarbon streams - Google Patents

Processes for removing hydrogen sulfide from refined hydrocarbon streams Download PDF

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Publication number
US20110031165A1
US20110031165A1 US12/535,252 US53525209A US2011031165A1 US 20110031165 A1 US20110031165 A1 US 20110031165A1 US 53525209 A US53525209 A US 53525209A US 2011031165 A1 US2011031165 A1 US 2011031165A1
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United States
Prior art keywords
hydrocarbon stream
refined hydrocarbon
corrosion inhibitor
processing equipment
volume
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US12/535,252
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English (en)
Inventor
Larry John KARAS
Sherif Eldin
Malcolm Craig Winslow
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General Electric Co
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General Electric Co
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Priority to US12/535,252 priority Critical patent/US20110031165A1/en
Assigned to GENERAL ELECTRIC COMPANY reassignment GENERAL ELECTRIC COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: ELDIN, SHERIF, KARAS, LARRY JOHN, WINSLOW, MALCOLM CRAIG
Priority to KR1020127005619A priority patent/KR20120055582A/ko
Priority to PCT/US2010/040871 priority patent/WO2011016935A2/en
Priority to AU2010281621A priority patent/AU2010281621A1/en
Priority to EP10734605A priority patent/EP2462207A2/en
Priority to SG2012007647A priority patent/SG178245A1/en
Priority to BR112012002528A priority patent/BR112012002528A2/pt
Priority to CN201080045142XA priority patent/CN102549114A/zh
Priority to CA2770008A priority patent/CA2770008A1/en
Priority to RU2012103702/04A priority patent/RU2012103702A/ru
Priority to JP2012523623A priority patent/JP2013501126A/ja
Priority to MX2012001530A priority patent/MX2012001530A/es
Assigned to GENERAL ELECTRIC COMPANY reassignment GENERAL ELECTRIC COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: KARAS, LARRY JOHN, ELDIN, SHERIF, WINSLOW, MALCOLM CRAIG
Publication of US20110031165A1 publication Critical patent/US20110031165A1/en
Abandoned legal-status Critical Current

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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G75/00—Inhibiting corrosion or fouling in apparatus for treatment or conversion of hydrocarbon oils, in general
    • C10G75/02—Inhibiting corrosion or fouling in apparatus for treatment or conversion of hydrocarbon oils, in general by addition of corrosion inhibitors
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G75/00—Inhibiting corrosion or fouling in apparatus for treatment or conversion of hydrocarbon oils, in general
    • C10G75/04—Inhibiting corrosion or fouling in apparatus for treatment or conversion of hydrocarbon oils, in general by addition of antifouling agents
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G29/00—Refining of hydrocarbon oils, in the absence of hydrogen, with other chemicals
    • C10G29/20—Organic compounds not containing metal atoms
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G29/00—Refining of hydrocarbon oils, in the absence of hydrogen, with other chemicals
    • C10G29/20—Organic compounds not containing metal atoms
    • C10G29/22—Organic compounds not containing metal atoms containing oxygen as the only hetero atom
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/104—Light gasoline having a boiling range of about 20 - 100 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1044—Heavy gasoline or naphtha having a boiling range of about 100 - 180 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1051—Kerosene having a boiling range of about 180 - 230 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1055—Diesel having a boiling range of about 230 - 330 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1037—Hydrocarbon fractions
    • C10G2300/1048—Middle distillates
    • C10G2300/1059—Gasoil having a boiling range of about 330 - 427 °C
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1077—Vacuum residues
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4075—Limiting deterioration of equipment
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/80—Additives

Definitions

  • This invention relates generally to processing hydrocarbon media, and more particularly, to methods for removing hydrogen sulfide from a refined hydrocarbon stream.
  • Hydrocarbon media such as a refined hydrocarbon stream, may contain hydrogen sulfide, which is highly corrosive and poisonous in very small concentrations.
  • the risk of exposure to hydrogen sulfide from handling hydrocarbon media is a health and safety concern during storage, transportation (shipping, truck or pipeline) and processing.
  • Hydrogen sulfide scavengers can be used to remove hydrogen sulfide from hydrocarbon media.
  • One type of hydrogen sulfide scavenger is glyoxal.
  • acidic byproducts are often formed. These byproducts can lead to increased corrosion rates during hydrocarbon processing.
  • the acidic byproducts which are not soluble in the refined hydrocarbon stream, can settle out from the refined hydrocarbon stream into a separate aqueous phase.
  • the aqueous phase may run along the bottom of the processing or refinery equipment as small tributaries in pipelines or stagnate at the bottom of holding tanks. This acidic aqueous phase is highly corrosive and can cause troughing in the processing or refinery equipment.
  • a method for reducing the amount of hydrogen sulfide present in a refined hydrocarbon stream and reducing the amount of corrosion in processing equipment contacting the refined hydrocarbon stream includes adding a corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment to protect the processing equipment and adding glyoxal to the refined hydrocarbon stream in contact with the protected processing equipment, wherein said corrosion inhibitor includes an organic soluble compound having a nitrogen-containing ring.
  • the various embodiments provide an improved hydrogen scavenging process for refined hydrocarbon streams that reduces hydrogen sulfide while minimizing corrosion to processing equipment.
  • a method for reducing the amount of hydrogen sulfide present in a refined hydrocarbon stream and reducing the amount of corrosion in processing equipment contacting the refined hydrocarbon stream includes adding a corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment to protect the processing equipment and adding glyoxal to the refined hydrocarbon stream in contact with the protected processing equipment, wherein said corrosion inhibitor includes an organic soluble compound having a nitrogen-containing ring.
  • the refined hydrocarbon stream may be any type of refined hydrocarbon stream containing hydrogen sulfide.
  • the refined hydrocarbon stream includes, but is not limited to, gas oil, naphtha, FCC slurry, diesel fuel, fuel oil, jet fuel, gasoline, kerosene or vacuum residua.
  • the refined hydrocarbon stream may be at an elevated temperature.
  • the refined hydrocarbon stream may be at a temperature of from about ambient to about 150° C.
  • the refined hydrocarbon stream may be at a temperature of from about 40° C. to about 100° C.
  • the processing equipment in contact with the refined hydrocarbon stream may be any type of equipment that can be used for processing the refined hydrocarbon stream, such as pipelines and holding tanks.
  • Processing equipment subject to corrosion is generally processing equipment made of carbon steel, but any type of processing equipment may be protected.
  • the corrosion inhibitor includes an organic soluble compound having a nitrogen-containing ring. In one embodiment, the corrosion inhibitor is miscible in the refined hydrocarbon stream.
  • the nitrogen-containing ring may be a five-membered ring or a six-membered ring.
  • the nitrogen-containing ring may be an imidazoline derivative.
  • the corrosion inhibitor may be a fatty acid imidazoline.
  • the fatty acid imidazoline has the following structure:
  • R and R′ are each, separately, a C 6 to C 36 alkyl, alkylene or aromatic group.
  • R and R′ are each, separately, a C 8 to C 22 alkyl, alkylene or aromatic group.
  • R and R′ are each, separately, a C 16 to C 18 alkyl, alkylene or aromatic group.
  • R and R′ are each, separately, a C 6 to C 36 alkyl, alkylene or aromatic group having branched alkyl groups.
  • R may be stearyl, napthyl, palmyl, olyl, linolyl or linolenyl.
  • R′ may be stearyl, napthyl, palmyl, olyl, linolyl or linolenyl.
  • the fatty acid imidazoline compound includes, but is not limited to, stearic acid imidazoline, naphthenic acid imidazoline, palmitic acid imidazoline, oleic acid imidazoline, linoleic acid imidazoline or linolenic acid imidazoline.
  • the fatty acid imidazoline may contain a mixture of two or more fatty acid imidazoline compounds.
  • fatty acid imidazolines may be prepared by the condensation reaction of at least one fatty acid and diethylenetriamine.
  • the fatty acids may have a C 6 to C 36 chain length.
  • the fatty acids may have a C 8 to C 22 chain length.
  • the fatty acids may have a C 16 to C 18 chain length.
  • the fatty acids may include natural acids derived from tall oils, oleic acid, stearic acid, palmitic acid, linoleic acid, linolenic acid or naphthenic acid or may include synthetically prepared fatty acids.
  • the synthetically prepared fatty acids may include acids with an even number of carbon atoms or an odd number of carbon atoms.
  • the condensation reaction may be at a reaction temperature of up to about 400° F. In another embodiment, the reaction temperature may be from about 200° F. to about 400° F.
  • the nitrogen-containing ring may be a pyrimidine derivative.
  • the corrosion inhibitor may be a fatty acid pyrimidine.
  • the fatty acid pyrimidine has the following structure:
  • R a and R b are each, separately, a C 6 to C 36 alkyl, alkylene or aromatic group.
  • R a and R b are each, separately, a C 8 to C 22 alkyl, alkylene or aromatic group.
  • R a and R b are each, separately, a C 16 to C 18 alkyl, alkylene or aromatic group.
  • R a and R b are each, separately, a C 6 to C 36 alkyl, alkylene or aromatic group having branched alkyl groups.
  • R a may be stearyl, napthyl, palmyl, olyl, linolyl or linolenyl.
  • R b may be stearyl, napthyl, palmyl, olyl, linolyl or linolenyl.
  • the fatty acid pyrimidine compound includes, but is not limited to, stearic acid pyrimidine, naphthenic acid pyrimidine, palmitic acid pyrimidine, oleic acid pyrimidine, linoleic acid pyrimidine or linolenic acid pyrimidine.
  • the fatty acid pyrimidine may contain a mixture of two or more fatty acid pyrimidine compounds.
  • fatty acid pyrimidines may be prepared by the condensation reaction of at least one fatty acid with a fatty acid-derived 1,3-propane diamine and paraformaldehyde.
  • the fatty acids may have a C 6 to C 36 chain length.
  • the fatty acids may have a C 8 to C 22 chain length.
  • the fatty acids may have a C 16 to C 18 chain length.
  • the fatty acids may include natural acids derived from tall oils, oleic acid, stearic acid, palmitic acid, linoleic acid, linolenic acid or naphthenic acid or may include synthetically prepared fatty acids.
  • the synthetically prepared fatty acids may include acids with an even number of carbon atoms or an odd number of carbon atoms.
  • the condensation reaction may be at a reaction temperature of up to about 400° F. In another embodiment, the reaction temperature may be from about 200° F. to about 400° F.
  • the corrosion inhibitor may be added to the refined hydrocarbon stream in contact with the processing equipment to protect the processing equipment. In one embodiment, the corrosion inhibitor is added to the refined hydrocarbon stream, which then contacts the processing equipment. In another embodiment, the corrosion inhibitor is added to the refined hydrocarbon stream while it is in contact with the processing equipment.
  • the corrosion inhibitor is added to the refined hydrocarbon stream in any conventional manner.
  • the corrosion inhibitor may be injected into the refined hydrocarbon stream.
  • the corrosion inhibitor may be injected into the refined hydrocarbon stream by a conventional in-line injection system and may be injected at any point in-line suitable to allow the corrosion inhibitor to mix with the refined hydrocarbon stream.
  • the corrosion inhibitor may be added to the refined hydrocarbon stream in a continuous manner or can be added in one or more batch modes and repeated additions may be made.
  • the corrosion inhibitor is injected into the refined hydrocarbon stream as the refined hydrocarbon stream is flowing through a pipeline. In one embodiment, the corrosion inhibitor is injected into the refined hydrocarbon stream as it enters a pipeline. In another embodiment, the corrosion inhibitor is injected into refined hydrocarbon stream in a holding tank. In another embodiment, the corrosion inhibitor is injected into the refined hydrocarbon stream as it enters a holding tank.
  • the corrosion inhibitor disperses into the refined hydrocarbon stream and eventually contacts the processing equipment and deposit onto the processing equipment, forming a protective coating or film.
  • the corrosion inhibitor may be added in any amount suitable for forming a protective coating or film on the processing equipment.
  • the corrosion inhibitor may be added to the refined hydrocarbon stream in an amount of from about 2 ppm by volume to about 200 ppm by volume, based on the volume of the refined hydrocarbon stream.
  • the corrosion inhibitor may be added to the refined hydrocarbon stream in an amount of from about 5 ppm by volume to about 100 ppm by volume, based on the volume of the refined hydrocarbon stream.
  • the corrosion inhibitor is added to the refined hydrocarbon stream in an amount of from about 10 ppm by volume to about 100 ppm by volume, based on the volume of the refined hydrocarbon stream. In another embodiment, the corrosion inhibitor is added to the refined hydrocarbon stream in an amount of from about 20 ppm by volume to about 100 ppm by volume, based on the volume of the refined hydrocarbon stream.
  • the corrosion inhibitor may be added in a single batch or may be added in continuing dosages to the refined hydrocarbon stream.
  • the corrosion inhibitor will begin to deposit evenly on the processing equipment as it contacts the equipment.
  • a protective coating will form on the processing equipment as the refined hydrocarbon stream containing the corrosion inhibitor continues to contact the processing equipment.
  • the amount of time suitable for forming a protective coating will depend on many factors, such as the amount of corrosion inhibitor in the refined hydrocarbon stream, the temperature of the refined hydrocarbon stream, the amount of time that the refined hydrocarbon stream is in contact with the processing equipment and the speed at which the refined hydrocarbon stream may be traveling as it contacts the processing equipment.
  • the corrosion inhibitor will provide a protective coating or film onto the processing equipment after at least about 5 minutes of adding the corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment.
  • the corrosion inhibitor provides a protective coating onto the processing equipment from about 5 minutes to about 100 hours of adding the corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment.
  • a protective film or coating is formed onto the processing equipment from about 15 minutes to about 75 hours of adding the corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment.
  • a protective film or coating is formed onto the processing equipment from about 30 minutes to about 60 hours of adding the corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment.
  • a protective film or coating is formed onto the processing equipment from about 1 hour to about 50 hours of adding the corrosion inhibitor to the heavy oil in contact with the processing equipment.
  • a protective film or coating is formed onto the processing equipment from about 10 hours to about 40 hours of adding the corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment.
  • the corrosion inhibitor provides a protective coating to the processing equipment from about 12 hours to about 36 hours of adding the corrosion inhibitor to the refined hydrocarbon stream in contact with the processing equipment.
  • Glyoxal is added to the refined hydrocarbon stream in contact with the protected processing equipment to reduce the hydrogen sulfide.
  • Glyoxal is a water-soluble aldehyde and may include oligomers of glyoxal.
  • Glyoxal is commercially available as a 40 weight percent aqueous solution.
  • the glyoxal may be added to the refined hydrocarbon stream in any conventional manner.
  • the glyoxal may be injected into the refined hydrocarbon stream by a conventional in-line injection system and may be injected at any point in-line suitable to allow the glyoxal to mix with the refined hydrocarbon stream.
  • the glyoxal may be added to the refined hydrocarbon stream in a continuous manner or can be added in one or more batch modes and repeated additions may be made.
  • the glyoxal is added to the refined hydrocarbon stream in any amount sufficient to reduce the levels of hydrogen sulfide in the refined hydrocarbon stream.
  • glyoxal may be added in an amount of from about 1 ppm to about 3000 ppm by volume, based on the volume of the refined hydrocarbon stream.
  • glyoxal may be added in an amount of from about 10 ppm by volume to about 2000 ppm by volume, based on the volume of the refined hydrocarbon stream.
  • glyoxal may be added in an amount of from about 50 ppm by volume to about 1500 ppm by volume, based on the weight of the refined hydrocarbon stream.
  • glyoxal may be added in an amount of from about 100 ppm by volume to about 1200 ppm by volume, based on the volume of the refined hydrocarbon stream.
  • any amount of hydrogen sulfide in the refined hydrocarbon stream may be reduced and the actual amount of residual hydrogen sulfide will vary depending on the starting amount.
  • the hydrogen sulfide levels are reduced to 150 ppm by volume or less, as measured in the vapor phase, based on the volume of the refined hydrocarbon stream.
  • the hydrogen sulfide levels are reduced to 100 ppm by volume or less, as measured in the vapor phase, based on the volume of the refined hydrocarbon stream.
  • the hydrogen sulfide levels are reduced to 50 ppm by volume or less, as measured in the vapor phase, based on the volume of the refined hydrocarbon stream.
  • the hydrogen sulfide levels are reduced to 20 ppm by volume or less, as measured in the vapor phase, based on the volume of the refined hydrocarbon stream.
  • glyoxal During the production of glyoxal, acidic byproducts are formed and the glyoxal can have a pH in the range of about 2 to about 3. These byproducts can be highly corrosive. Glyoxal is water-based and after an initial dispersion throughout the refined hydrocarbon stream, will eventually settle out of the heavy oil in an aqueous phase. This aqueous phase will be very acidic and can corrode processing equipment. The coating or film formed by the corrosion inhibitor on the processing equipment protects the processing equipment and reduces or eliminates the corrosion from the acidic aqueous phase.
  • the corrosion inhibitor may continue to be added as the glyoxal is added to the refined hydrocarbon stream in contact with the protected processing equipment.
  • the corrosion inhibitor will continue to deposit on the processing equipment and maintain the protection on the processing equipment.
  • the additional corrosion inhibitor may be added in amounts of from about 1 ppm by volume to about 20 ppm by volume, based on the volume of the refined hydrocarbon stream. In another embodiment, the corrosion inhibitor may be added in an amount of from about 5 ppm by volume to about 10 ppm by volume, based on the volume of the refined hydrocarbon stream.
  • a catalyst may be added to enhance the removal of the hydrogen sulfide.
  • the catalyst is a quaternary ammonium salt.
  • the catalyst may be any suitable quaternary ammonium salt.
  • the catalyst has formula I:
  • R 1 , R 2 , R 3 and R 4 are each independently an alkyl group having from 1 to 30 carbon atoms, an aryl group having from 6 to 30 carbon atoms or an arylalkyl group having from 7 to 30 carbon atoms; and X is a halide, sulfate, nitrate or carboxylate.
  • the alkyl groups and the aryl groups may be substituted or unsubstituted.
  • R 1 is an alkyl group having from 1 to 24 carbon atoms.
  • R 2 is an alkyl having from 1 to 24 carbon atoms, an aryl group having from 6 to 24 carbon atoms or an arylalkyl group having from 7 to 24 carbon atoms.
  • R 3 and R 4 are each, independently, an alkyl group having from 1 to 24 carbon atoms. In another embodiment, R 3 and R 4 are each, independently, an alkyl group having from 1 to 4 carbon atoms.
  • the alkyl group includes, but is not limited to, methyl, ethyl, propyl, isopropyl, butyl, isobutyl, pentyl, hexyl, decyl or dodecyl.
  • the aryl group may be phenyl.
  • the arylalkyl group include may be benzyl.
  • the halide may be chloride, bromide or iodide.
  • the sulfate may be a methyl sulfate.
  • the nitrate may be a bisulfate nitrate.
  • the carboxylate may be acetate.
  • the quaternary ammonium salt is alkyl benzyl ammonium chloride or benzyl cocoalkyl (C 12 -C 18 ) dimethylammonium chloride.
  • the quaternary ammonium salt includes, but is not limited to dicocoalkyl (C 12 -C 18 ) dimethylammonium chloride, ditallowdimethylammonium chloride, di(hydrogenated tallow alkyl) dimethyl quaternary ammonium methyl chloride, methyl bis (2-hydroxyethyl cocoalkyl (C 12 -C 18 ) quaternary ammonium chloride, dimethyl(2-ethyl)tallow ammonium methyl sulfate, n-dodecylbenzyldimethylammonium chloride, n-octadecylbenzyldimethyl ammonium chloride, n-dodecyltrimethylammonium sulfate, soya
  • the catalyst is present from about 0.01 to about 15 percent by weight based on the weight of glyoxal. In another embodiment, the catalyst is present from about 1 to about 10 percent by weight based on the weight of glyoxal.
  • the catalyst may be added to the refined hydrocarbon stream simultaneously with the glyoxal or may be added separately from the glyoxal. In one embodiment, the catalyst is preblended with the glyoxal before being added to the refined hydrocarbon stream.
  • Glyoxal is an aqueous-based compound having a pH from about 2 to about 3. When dispersed in refined hydrocarbon streams, it will eventually settle out of the refined hydrocarbon streams into an acidic aqueous phase and settle to the bottom of processing equipment causing corrosion. To test the efficiacy of the corrosion inhibitor for reducing corrosion, the corrosion test was simulated in water.
  • Two metal coupons of Carbon C010 steel were weighed and added to two spindles mounted on a stirring shaft in an 800 ml Auto-Clave.
  • the metal coupons were 180° from each other.
  • the stirring shaft was placed into water and stirred at the revolutions per minute as shown in Table 1.
  • the revolutions per minute were used to calculate the approximate flow through a pipeline and are shown in Table 1.
  • a corrosion inhibitor was added to the water at room temperature in the amounts shown in Table 1. 15 minutes later, glyoxal was injected into the water in the amounts shown in Table 1.
  • the Auto-Clave was sealed and the water was heated to about 180° F. to simulate the temperature of a typical refined hydrocarbon stream during processing. After 4 hours, the metal coupons were tested for corrosion by measuring any weight loss of the metal coupons and averaging the metal coupons.
  • the organic soluble corrosion inhibitor shows a marked decrease in corrosion compared with the blank (sample CE-1).
  • a water-soluble corrosion inhibitor was tested (sample CE-2), but it actually increased the corrosion.
  • Ratio 4 500 Oleic acid Imidazoline and 100 14.0 Hydroxyacetic acid (3:1 wt ratio) 5 5 500 Oleic acid Pyrimidine 6 100 10.0 1 Glyoxal used contains 2% by weight quaternary ammonium catalyst and is available commercially as S-1750 from GE Water. 2 Available commercially as Philmplus TM 5K 1642 from GE Water. 3 Available commercially as Sylvadym ® T-18 from Sylvachem Corp. 4 Available commercially as CI-11C from GE Water. 5 Available commercially as 5K2S from GE Water. 6 Available commercially as 5K7 from GE Water.
  • the organic soluble corrosion inhibitors in Samples 1-5 show improved corrosion resistance in comparison with the blank (sample CE-3) and in comparison with an organic soluble dimer/trimer acid (sample CE-4).
  • Corrosion experiments and hydrogen sulfide scavenging were tested in a mixture of oil gas and water in an 800 ml Auto-Clave.
  • the gas oil was initially spiked with an approximate 0.5 wt. % solution of H 2 S in kerosene before being mixed with the water.
  • Two metal coupons of Carbon C1010 steel were weighed and added to two spindles mounted on a stirring shaft. The metal coupons were 180° from each other.
  • the stirring shaft was placed into the gas oil and water mixture and stirred at 300 rpm.
  • the mixture of oil gas and water was 200 ml of gas oil and 400 ml of water.
  • the 2:1 volume ratio of water to gas oil ensured that the coupons were always immersed in water @ 300 rpm to test the corrosion in an aqueous phase.
  • a corrosion inhibitor was added to the gas oil mixture at room temperature in the amounts shown in Table 3. 15 minutes later, glyoxal was injected into the gas oil mixture in the amounts shown in Table 3.
  • the Auto-Clave was sealed and the gas oil and water mixture was heated to about 180° F. to simulate a typical processing temperature. After 4 hours, the metal coupons were tested for corrosion by measuring any weight loss of the metal coupons, averaging the metal coupons and calculating the mils per year (MPY).
  • Hydrogen sulfide testing was performed using the modified ASTM 5705-95 test that measures vapor phase H 2 S two hours after treatment (140° F.) with Drager tubes. Final H 2 S concentration measurements are shown in Table 3.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Preventing Corrosion Or Incrustation Of Metals (AREA)
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US12/535,252 US20110031165A1 (en) 2009-08-04 2009-08-04 Processes for removing hydrogen sulfide from refined hydrocarbon streams
MX2012001530A MX2012001530A (es) 2009-08-04 2010-07-02 Procedimiento para remover sulfuro de hidrogeno de corrientes de hidrocarburo refinado.
BR112012002528A BR112012002528A2 (pt) 2009-08-04 2010-07-02 método para a redução da quantidade de sulfeto de hidrogênio
CA2770008A CA2770008A1 (en) 2009-08-04 2010-07-02 Processes for removing hydrogen sulfide from refined hydrocarbon streams
AU2010281621A AU2010281621A1 (en) 2009-08-04 2010-07-02 Processes for removing hydrogen sulfide from refined hydrocarbo streams
EP10734605A EP2462207A2 (en) 2009-08-04 2010-07-02 Corrosion protection process using fatty acid imidazoline or pyrimidine and glyoxal
SG2012007647A SG178245A1 (en) 2009-08-04 2010-07-02 Processes for removing hydrogen sulfide from refined hydrocarbo streams
KR1020127005619A KR20120055582A (ko) 2009-08-04 2010-07-02 정제된 탄화수소 스트림으로부터 황화수소를 제거하는 방법
CN201080045142XA CN102549114A (zh) 2009-08-04 2010-07-02 从精炼的烃流除去硫化氢的方法
PCT/US2010/040871 WO2011016935A2 (en) 2009-08-04 2010-07-02 Processes for removing hydrogen sulfide from refined hydrocarbo streams
RU2012103702/04A RU2012103702A (ru) 2009-08-04 2010-07-02 Способы удаления сероводорода из потоков очищенных углеродов
JP2012523623A JP2013501126A (ja) 2009-08-04 2010-07-02 精製炭化水素流から硫化水素を除去する方法

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KR101293268B1 (ko) 2011-04-14 2013-08-16 한국화학연구원 식물유 유래 이미다졸린 화합물을 포함하는 방청제
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US20170066977A1 (en) * 2015-09-08 2017-03-09 Ecolab Usa Inc. Hydrocarbon soluble/dispersible hemiformals as hydrogen sulfide scavengers
US20170066976A1 (en) * 2015-09-08 2017-03-09 Ecolab Usa Inc. Hydrogen sulfide scavengers
US10196343B2 (en) 2013-01-30 2019-02-05 Ecolab Usa Inc. Hydrogen sulfide scavengers
US10301553B2 (en) 2017-02-28 2019-05-28 Ecolab Usa Inc. Use of sulfonium salts as hydrogen sulfide inhibitors
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US10336950B2 (en) 2016-07-29 2019-07-02 Ecolab Usa Inc. Antifouling and hydrogen sulfide scavenging compositions and methods
US10538710B2 (en) 2017-07-13 2020-01-21 Ecolab Usa Inc. Hydrogen sulfide scavengers
US10900128B2 (en) 2018-08-29 2021-01-26 Championx Usa Inc. Use of sulfonium salts as corrosion inhibitors
US11499108B2 (en) 2019-01-23 2022-11-15 Championx Usa Inc. Complete removal of solids during hydrogen sulfide scavenging operations using a scavenger and a Michael acceptor

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US10196343B2 (en) 2013-01-30 2019-02-05 Ecolab Usa Inc. Hydrogen sulfide scavengers
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WO2016126630A1 (en) * 2015-02-04 2016-08-11 Ecolab Usa Inc. Diphenyliodonium salts as sulfidogenesis inhibitors and antimicrobials
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US10407626B2 (en) * 2015-09-08 2019-09-10 Ecolab Usa Inc. Hydrocarbon soluble/dispersible hemiformals as hydrogen sulfide scavengers
US10584286B2 (en) * 2015-09-08 2020-03-10 Ecolab Usa Inc. Hydrogen sulfide scavengers
US20170066976A1 (en) * 2015-09-08 2017-03-09 Ecolab Usa Inc. Hydrogen sulfide scavengers
US20170066977A1 (en) * 2015-09-08 2017-03-09 Ecolab Usa Inc. Hydrocarbon soluble/dispersible hemiformals as hydrogen sulfide scavengers
US10336950B2 (en) 2016-07-29 2019-07-02 Ecolab Usa Inc. Antifouling and hydrogen sulfide scavenging compositions and methods
US10301553B2 (en) 2017-02-28 2019-05-28 Ecolab Usa Inc. Use of sulfonium salts as hydrogen sulfide inhibitors
US10538710B2 (en) 2017-07-13 2020-01-21 Ecolab Usa Inc. Hydrogen sulfide scavengers
US10900128B2 (en) 2018-08-29 2021-01-26 Championx Usa Inc. Use of sulfonium salts as corrosion inhibitors
US11499108B2 (en) 2019-01-23 2022-11-15 Championx Usa Inc. Complete removal of solids during hydrogen sulfide scavenging operations using a scavenger and a Michael acceptor

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