EP3448968A1 - Process for controlling corrosion in petroleum refining units - Google Patents

Process for controlling corrosion in petroleum refining units

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Publication number
EP3448968A1
EP3448968A1 EP17722949.9A EP17722949A EP3448968A1 EP 3448968 A1 EP3448968 A1 EP 3448968A1 EP 17722949 A EP17722949 A EP 17722949A EP 3448968 A1 EP3448968 A1 EP 3448968A1
Authority
EP
European Patent Office
Prior art keywords
alcohol
glycol
amine
mixtures
reacted
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP17722949.9A
Other languages
German (de)
French (fr)
Inventor
Runyu TAN
Lorenzo Spagnuolo
Stephen W. King
Frederick S. Foster
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Dow Global Technologies LLC
Original Assignee
Dow Global Technologies LLC
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Dow Global Technologies LLC filed Critical Dow Global Technologies LLC
Publication of EP3448968A1 publication Critical patent/EP3448968A1/en
Withdrawn legal-status Critical Current

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Classifications

    • 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
    • C10G7/00—Distillation of hydrocarbon oils
    • C10G7/10—Inhibiting corrosion during distillation
    • 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
    • C23—COATING METALLIC MATERIAL; COATING MATERIAL WITH METALLIC MATERIAL; CHEMICAL SURFACE TREATMENT; DIFFUSION TREATMENT OF METALLIC MATERIAL; COATING BY VACUUM EVAPORATION, BY SPUTTERING, BY ION IMPLANTATION OR BY CHEMICAL VAPOUR DEPOSITION, IN GENERAL; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL
    • C23F—NON-MECHANICAL REMOVAL OF METALLIC MATERIAL FROM SURFACE; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL; MULTI-STEP PROCESSES FOR SURFACE TREATMENT OF METALLIC MATERIAL INVOLVING AT LEAST ONE PROCESS PROVIDED FOR IN CLASS C23 AND AT LEAST ONE PROCESS COVERED BY SUBCLASS C21D OR C22F OR CLASS C25
    • C23F11/00—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent
    • C23F11/08—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent in other liquids
    • C23F11/10—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent in other liquids using organic inhibitors
    • C23F11/12—Oxygen-containing compounds
    • C23F11/122—Alcohols; Aldehydes; Ketones
    • C—CHEMISTRY; METALLURGY
    • C23—COATING METALLIC MATERIAL; COATING MATERIAL WITH METALLIC MATERIAL; CHEMICAL SURFACE TREATMENT; DIFFUSION TREATMENT OF METALLIC MATERIAL; COATING BY VACUUM EVAPORATION, BY SPUTTERING, BY ION IMPLANTATION OR BY CHEMICAL VAPOUR DEPOSITION, IN GENERAL; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL
    • C23F—NON-MECHANICAL REMOVAL OF METALLIC MATERIAL FROM SURFACE; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL; MULTI-STEP PROCESSES FOR SURFACE TREATMENT OF METALLIC MATERIAL INVOLVING AT LEAST ONE PROCESS PROVIDED FOR IN CLASS C23 AND AT LEAST ONE PROCESS COVERED BY SUBCLASS C21D OR C22F OR CLASS C25
    • C23F11/00—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent
    • C23F11/08—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent in other liquids
    • C23F11/10—Inhibiting corrosion of metallic material by applying inhibitors to the surface in danger of corrosion or adding them to the corrosive agent in other liquids using organic inhibitors
    • C23F11/14—Nitrogen-containing compounds
    • C23F11/141—Amines; Quaternary ammonium compounds
    • 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
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/44—Solvents
    • 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

  • the present invention pertains to a process for controlling corrosion in petroleum refining units by reducing buildup of hydrochloride salts and minimizing fouling of the apparatus.
  • Hydrocarbon feedstocks such as petroleum crudes, gas oil, etc. are subjected to various processes in order to isolate and separate different fractions of the feedstock.
  • the feedstock is distilled so as to provide the various valuable fractions, e.g., light hydrocarbons, gasoline, naphtha, kerosene, gas oil, etc.
  • the lower boiling fractions are recovered as an overhead fraction from the distillation and vacuum columns.
  • the intermediate components are recovered as side cuts from the distillation column.
  • the fractions are cooled, condensed, and sent to collecting equipment.
  • the distillation equipment is subjected to the corrosive activity of acids such as 3 ⁇ 4S, HC1, organic acids, and H2CO3.
  • the problem of corrosion caused by these acid gases as water condenses in the overhead condensing systems of distillation and vacuum columns is well known. The consequent presence of acidic water leads to the undesirable corrosion of metallic equipment, often rapidly.
  • the general mechanism of this corrosion is an oxidation of metal atoms by aqueous hydrogen ions.
  • the rate of corrosion is directly related to the concentration of aqueous hydrogen ions.
  • a particularly difficult aspect of the problem is that the corrosion occurs above and in the temperature range of the initial condensation of water.
  • the term "initial condensate" as used herein indicates a phase formed when the temperature of the surrounding environment reaches the dew point of water. At this point a mixture of liquid water, hydrocarbon, and vapor may be present.
  • the initial condensate may occur within the distilling unit itself or in subsequent condensers and other equipment.
  • the top temperature of the fractionating column is normally maintained above the dew point of water.
  • the initial aqueous condensate formed contains a high percentage of HC1.
  • the chlorine comes from salts in the crude, and recently the salt content of crude oil (especially Opportunity Crudes) being used in refineries has increased, generating more chlorides. Due to the high concentration of acids dissolved in the water, the pH of the first condensate can be rather low. Thus, as noted, the condensed water can be highly corrosive. It is important that the first condensate is made less corrosive.
  • ammonia has been added at various points in the system in an attempt to inhibit the corrosiveness of condensed acidic materials.
  • ammonia has not been effective to eliminate corrosion occurring at the initial condensate due to its volatility.
  • ammonia may be ineffective because it does not condense completely enough to neutralize the acidic components of the first condensate.
  • Amines such as morpholine and methoxy propylamine have been used successfully to control or inhibit corrosion that occurs at the point of initial condensation within or after the distillation unit. Adding amines to the petroleum fractionating system raises the pH of the initial condensate rendering the material substantially less corrosive.
  • the amine inhibitor can be added to the system either in pure form or as an aqueous solution. In some cases, sufficient amounts of amine inhibitors are added to raise the pH of the liquid at the point of initial condensation to above 4.5; in some cases to between 5.5 and 6.5.
  • Other highly basic (pKa > 8) amines have been used, including ethylenediamine, monoethanolamine and hexamethylene diamine.
  • the present invention is a process for controlling corrosion in an overhead system of a refining unit comprising water vapor/condensate and petroleum products comprising the step of adding to the system an amine compound and an alcohol, preferably wherein the amount of the amine compound and the alcohol independently range from 1 to 10,000 ppm based on the petroleum products.
  • the amine compound is an alkylamine, an alkanolamine, or mixtures thereof, preferably dimethylethanolamine (DMEA), dimethylisopropanolamine (DMIPA), ethylenediamine (EDA),
  • DMEA dimethylethanolamine
  • DMIPA dimethylisopropanolamine
  • EDA ethylenediamine
  • MOPA methoxypropylamine
  • MEA monoethanolamine
  • DMAPA dimethylaminopropylamine
  • TMA trimethylamine
  • the process disclosed herein above wherein the alcohol is a polyol, polyether diol, polyether triol, or mixtures thereof.
  • the alcohol is a polyol based on ethylene glycol reacted with ethylene oxide, a polyol based on ethylene glycol reacted with propylene oxide, or a polyol based on ethylene glycol reacted with ethylene oxide and propylene oxide, or mixtures thereof.
  • the alcohol is a polyol based on glycerol reacted with ethylene oxide, a polyol based on glycerol reacted propylene oxide, a polyol based on glycerol reacted butylene oxide, a polyol based on glycerol reacted ethylene oxide and/or propylene oxide and/or butylene oxide, or mixtures thereof.
  • the alcohol is ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, glycerol, polyethylene glycol, polypropylene glycol, polytetramethylene glycol, or mixtures thereof.
  • the amine compound and the alcohol are added to the system separately.
  • the amine compound and the alcohol are added to the system together.
  • the process disclosed herein above further comprises the step of adding the amine compound and the alcohol to the system at a rate sufficient to maintain the H of water condensate in the system at a pH of equal to or greater than 4, more preferably equal to or greater than 5.
  • FIG. 1 is a plot of the solubility of monoethanolamine hydrochloride and ethylenediamine hydrochloride in diethylene glycol at different temperatures.
  • FIG. 2 is a plot of the viscosities of room temperature saturated solutions of monoethanolamine hydrochloride and ethylenediamine hydrochloride in diethylene glycol at different temperatures.
  • FIG. 3 is a plot of the viscosity of room temperature saturated solutions of monoethanolamine hydrochloride and ethylenediamine hydrochloride in glycerine at different temperatures.
  • the neutralizer composition comprises an amine compound and an alcohol.
  • the water vapor/condensate coming out of the overhead of the crude distillation unit (CDU) in the refinery is very acidic primarily due to the presence of acidic components, such as hydrochloric acid (HC1), which is formed when the crude oil passes through a heating furnace (composed of metal chlorides such as MgCh, CaC , etc.) prior to entering the CDU.
  • acidic components such as hydrochloric acid (HC1)
  • HC1 hydrochloric acid
  • MgCh, CaC , etc. metal chlorides
  • Water vapor and HC1 rise to the top of the distillation tower along with the light components of the crude oil such as liquefied petroleum gas and naphtha.
  • This stream passes through an overhead line and then enters a condenser, after which the water stream will be separated from naphtha and off-gas and sent to a water treatment unit.
  • the acidic HC1 stream (often having a pH less than 2) is highly corrosive and needs to be neutralized (preferably to a pH of 4 or greater, more preferably 5 or greater).
  • the neutralizing composition is added to the overhead system, traditionally, neutralizers are injected into the overhead system between the CDU and the condenser.
  • the neutralizing composition may be added to the overhead system upstream of the aqueous dew point.
  • This addition point is usually the overhead line off of the distillation column or the vapor line off of a dry first condensing stage accumulator.
  • controlling corrosion is defined to include any cessation, prevention, abatement, reduction, suppression, lowering, controlling or decreasing of corrosion, rusting, oxidative decay, etc.
  • neutralize refers to such corrosion inhibition by reducing the acidity of the chemicals or components in the system such as by raising pH, but does not require adjusting pH to be 7, but rather raising of pH and moving from acidity to basicity to some measurable extent.
  • the nature of the metal surfaces protected in the methods of this invention is not critical.
  • the metals in which the system operates may include, but are not necessarily limited to iron alloys, copper alloys, nickel alloys, titanium alloys, and these metals in unalloyed form as well, etc.
  • the first component of the neutralizing composition is an amine compound, preferably one or more alkylamine or alkanolamine, preferably dimethylethanolamine (DMEA), dimethylisopropanolamine (DMIPA), ethylenediamine (EDA),
  • DMEA dimethylethanolamine
  • DMIPA dimethylisopropanolamine
  • EDA ethylenediamine
  • MOPA methoxypropylamine
  • MEA monoethanolamine
  • DMAPA dimethylaminopropylamine
  • TMA trimethylamine
  • the one or more alkylamine or alkanolamine is added in an amount of from 1 ppm to 10,000 ppm based on the petroleum products.
  • the amine compound is added in an amount of equal to or greater than 1 ppm, preferably equal to or greater than 1 ppm, more preferably equal to or greater than 10 ppm, and more preferably equal to or greater than 100 ppm based on the petroleum products.
  • the amine compound is added in an amount of equal to or less than 5,000 ppm, preferably equal to or less than 1,000 ppm, and more preferably equal to or less than 500 ppm based on the petroleum products.
  • the second component of the neutralizing composition is an alcohol.
  • Any suitable alcohol may be used.
  • the alcohol is a polyol, polyether diol, polyether triol, or mixtures thereof.
  • the alcohol s a polyol based on ethylene glycol reacted with ethylene oxide, a polyol based on ethylene glycol reacted with propylene oxide, a polyol based on ethylene glycol reacted with butylene oxide or a polyol based on ethylene glycol reacted with ethylene oxide and/or propylene oxide and/or butylene oxide, or mixtures thereof.
  • the alcohol is s a polyol based on glycerol reacted with ethylene oxide, a polyol based on glycerol reacted propylene oxide, a polyol based on glycerol reacted ethylene oxide and propylene oxide, or mixtures thereof.
  • the alcohol is ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, glycerol, polyethylene glycol, polypropylene glycol, polytetramethylene glycol, or mixtures thereof.
  • the one or more alcohol is added in an amount of from 1 ppm to 10,000 ppm based on the petroleum products.
  • Alcohol is added in an amount of equal to or greater than 1 ppm, preferably equal to or greater than 1 ppm, more preferably equal to or greater than 10, and more preferably equal to or greater than 100 ppm based on the petroleum products.
  • the alcohol is added in an amount of equal to or less than 5,000 ppm, preferably equal to or less than 1,000 ppm, and more preferably equal to or less than 500 ppm based on the petroleum products.
  • the dosage rate will depend upon a variety of complex, interrelated factors including, but not necessarily limited to, the exact nature of the stream being fractionated, the temperature and pressure of the distillation conditions, the particular amine blends used, etc.
  • the dosage rate will be determined on a case-by-case basis depending upon the acid content of the system. It may be desirable to use computer modeling to determine the optimum rate.
  • the amount of the amine compound and alcohol may independently range from 1 to 10,000 ppm, based on the petroleum products. In another non- limiting embodiment, the amount of the amine compound and alcohol may independently range from 1 to 500 ppm.
  • the desired pH range for all points in the system is from 4 to 8.5, and in another non-limiting embodiment may be from 5 to 7.
  • the neutralizing composition may be added to the system at a rate sufficient to maintain the pH of water condensate in the system at a pH of equal to or greater than 4.0.
  • the neutralizing composition may be added to the system at a rate sufficient to maintain the pH of equal to or greater than 5.0.
  • the solubility of the monoethanolamine hydrochloride (MEA HQ) and or ethylenediamine hydrochloride (EDA 2HC1) in diethylene glycol or glycerol is determined as follows: to 10 g of diethylene glycol or glycerol is added an excess amount of the salt and the reaction mixture is stirred rigorously for at least lh at the desired temperature. The stirring is then stopped and the reaction mixture is allowed to settle.
  • the solubility of the salt in ethylene glycol or glycerol is calculated from the chloride concentration measured by Ion Chromatography. The viscosity of the saturated solution is measured on a Stabinger Viscometer.
  • FIG. 1 The solubility of MEA HC1 and EDA 2HC1 in diethylene glycol at different temperatures is shown in FIG. 1 and the viscosity of the room temperature saturated solution of MEA HQ and EDA 2HC1 at different temperatures is shown FIG. 2.
  • the solubility of MEA HC1 and EDA 2HC1 in glycerol is determined to be 44.5 wt% and 12.8 wt%, respectively.
  • the viscosity of the room temperature saturated solution of MEA HQ in glycerine and EDA 2HC1 in glycerine at different temperatures is shown in FIG. 3.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Organic Chemistry (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Materials Engineering (AREA)
  • Mechanical Engineering (AREA)
  • Metallurgy (AREA)
  • Preventing Corrosion Or Incrustation Of Metals (AREA)

Abstract

A process for controlling corrosion and fouling in petroleum refining units. The corrosion controlling agent comprises an amine and an alcohol. The process comprises the step of adding the amine and the alcohol to the overhead system of the petroleum refining unit, either separately or in combination.

Description

PROCESS FOR CONTROLLING CORROSION IN PETROLEUM REFINING UNITS
FIELD OF THE INVENTION The present invention pertains to a process for controlling corrosion in petroleum refining units by reducing buildup of hydrochloride salts and minimizing fouling of the apparatus.
BACKGROUND OF THE INVENTION
Hydrocarbon feedstocks such as petroleum crudes, gas oil, etc. are subjected to various processes in order to isolate and separate different fractions of the feedstock. In refinery processes, the feedstock is distilled so as to provide the various valuable fractions, e.g., light hydrocarbons, gasoline, naphtha, kerosene, gas oil, etc. The lower boiling fractions are recovered as an overhead fraction from the distillation and vacuum columns. The intermediate components are recovered as side cuts from the distillation column. The fractions are cooled, condensed, and sent to collecting equipment. No matter what type of petroleum feedstock is used as the charge, the distillation equipment is subjected to the corrosive activity of acids such as ¾S, HC1, organic acids, and H2CO3. The problem of corrosion caused by these acid gases as water condenses in the overhead condensing systems of distillation and vacuum columns is well known. The consequent presence of acidic water leads to the undesirable corrosion of metallic equipment, often rapidly.
The general mechanism of this corrosion is an oxidation of metal atoms by aqueous hydrogen ions. The rate of corrosion is directly related to the concentration of aqueous hydrogen ions. A particularly difficult aspect of the problem is that the corrosion occurs above and in the temperature range of the initial condensation of water. The term "initial condensate" as used herein indicates a phase formed when the temperature of the surrounding environment reaches the dew point of water. At this point a mixture of liquid water, hydrocarbon, and vapor may be present. The initial condensate may occur within the distilling unit itself or in subsequent condensers and other equipment. The top temperature of the fractionating column is normally maintained above the dew point of water. The initial aqueous condensate formed contains a high percentage of HC1. The chlorine comes from salts in the crude, and recently the salt content of crude oil (especially Opportunity Crudes) being used in refineries has increased, generating more chlorides. Due to the high concentration of acids dissolved in the water, the pH of the first condensate can be rather low. Thus, as noted, the condensed water can be highly corrosive. It is important that the first condensate is made less corrosive.
Conventionally, highly basic ammonia has been added at various points in the system in an attempt to inhibit the corrosiveness of condensed acidic materials. However, ammonia has not been effective to eliminate corrosion occurring at the initial condensate due to its volatility. In one non- limiting view, ammonia may be ineffective because it does not condense completely enough to neutralize the acidic components of the first condensate.
Amines such as morpholine and methoxy propylamine have been used successfully to control or inhibit corrosion that occurs at the point of initial condensation within or after the distillation unit. Adding amines to the petroleum fractionating system raises the pH of the initial condensate rendering the material substantially less corrosive. The amine inhibitor can be added to the system either in pure form or as an aqueous solution. In some cases, sufficient amounts of amine inhibitors are added to raise the pH of the liquid at the point of initial condensation to above 4.5; in some cases to between 5.5 and 6.5. Other highly basic (pKa > 8) amines have been used, including ethylenediamine, monoethanolamine and hexamethylene diamine.
However, the use of these highly basic amines for treating the initial condensate has a problem relating to the resultant hydrochloride salts of these amines which tend to form deposits in distillation columns, column pumparounds, overhead lines, overhead heat exchangers and other parts of the system. These deposits occur after the particular amine has been used for a period of time, sometimes in as little as one or two days. These deposits can cause both fouling and corrosion problems and are particularly problematic in units that do not use a water wash.
Thus, it would be desirable if a process could be devised that neutralizes acid environments in distillation overheads of hydrocarbon processing facilities that minimizes or reduces deposits of hydrochloride and amine salts. BRIEF SUMMARY OF THE INVENTION
The present invention is a process for controlling corrosion in an overhead system of a refining unit comprising water vapor/condensate and petroleum products comprising the step of adding to the system an amine compound and an alcohol, preferably wherein the amount of the amine compound and the alcohol independently range from 1 to 10,000 ppm based on the petroleum products.
In one embodiment of the process disclosed herein the amine compound is an alkylamine, an alkanolamine, or mixtures thereof, preferably dimethylethanolamine (DMEA), dimethylisopropanolamine (DMIPA), ethylenediamine (EDA),
methoxypropylamine (MOPA), monoethanolamine (MEA), dimethylaminopropylamine (DMAPA), morpholine, or trimethylamine (TMA).
In one embodiment, the process disclosed herein above wherein the alcohol is a polyol, polyether diol, polyether triol, or mixtures thereof.
In one embodiment the process disclosed herein above the alcohol is a polyol based on ethylene glycol reacted with ethylene oxide, a polyol based on ethylene glycol reacted with propylene oxide, or a polyol based on ethylene glycol reacted with ethylene oxide and propylene oxide, or mixtures thereof.
In one embodiment of the process disclosed herein above the alcohol is a polyol based on glycerol reacted with ethylene oxide, a polyol based on glycerol reacted propylene oxide, a polyol based on glycerol reacted butylene oxide, a polyol based on glycerol reacted ethylene oxide and/or propylene oxide and/or butylene oxide, or mixtures thereof.
In one embodiment of the process disclosed herein above the alcohol is ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, glycerol, polyethylene glycol, polypropylene glycol, polytetramethylene glycol, or mixtures thereof.
In one embodiment of the process disclosed herein above the amine compound and the alcohol are added to the system separately.
In one embodiment of the process disclosed herein above the amine compound and the alcohol are added to the system together.
In one embodiment the process disclosed herein above further comprises the step of adding the amine compound and the alcohol to the system at a rate sufficient to maintain the H of water condensate in the system at a pH of equal to or greater than 4, more preferably equal to or greater than 5.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a plot of the solubility of monoethanolamine hydrochloride and ethylenediamine hydrochloride in diethylene glycol at different temperatures.
FIG. 2 is a plot of the viscosities of room temperature saturated solutions of monoethanolamine hydrochloride and ethylenediamine hydrochloride in diethylene glycol at different temperatures.
FIG. 3 is a plot of the viscosity of room temperature saturated solutions of monoethanolamine hydrochloride and ethylenediamine hydrochloride in glycerine at different temperatures. DETAILED DESCRIPTION OF THE INVENTION
Methods and compositions are disclosed for neutralizing acid environments and controlling corrosion in distillation overhead systems of petroleum product processing facilities, including, but not limited to distillation columns, vacuum distillation columns, preflash towers, and the like. The neutralizer composition comprises an amine compound and an alcohol.
For decades, refiners have struggled with providing adequate neutralization in overhead systems without forming corrosive salts. Ammonia and several amines have been tried to control corrosion with random successes and failures. The neutralizer compositions of the invention will allow reduction of fouling tendency of the corrosive salts without changing the neutralization power of ammonia and amines.
The water vapor/condensate coming out of the overhead of the crude distillation unit (CDU) in the refinery is very acidic primarily due to the presence of acidic components, such as hydrochloric acid (HC1), which is formed when the crude oil passes through a heating furnace (composed of metal chlorides such as MgCh, CaC , etc.) prior to entering the CDU. Water vapor and HC1 rise to the top of the distillation tower along with the light components of the crude oil such as liquefied petroleum gas and naphtha. This stream passes through an overhead line and then enters a condenser, after which the water stream will be separated from naphtha and off-gas and sent to a water treatment unit. The acidic HC1 stream (often having a pH less than 2) is highly corrosive and needs to be neutralized (preferably to a pH of 4 or greater, more preferably 5 or greater). The neutralizing composition is added to the overhead system, traditionally, neutralizers are injected into the overhead system between the CDU and the condenser.
In one embodiment of the present invention, the neutralizing composition may be added to the overhead system upstream of the aqueous dew point. This addition point is usually the overhead line off of the distillation column or the vapor line off of a dry first condensing stage accumulator.
It will be appreciated that it is not necessary for corrosion in distillation overheads or other equipment to completely cease for the method of this invention to be considered successful. Indeed, the inventive method should be considered operative if corrosion is inhibited to a measurable extent. In the context of this invention, the term "controlling corrosion" is defined to include any cessation, prevention, abatement, reduction, suppression, lowering, controlling or decreasing of corrosion, rusting, oxidative decay, etc. Similarly, the term "neutralize" refers to such corrosion inhibition by reducing the acidity of the chemicals or components in the system such as by raising pH, but does not require adjusting pH to be 7, but rather raising of pH and moving from acidity to basicity to some measurable extent. Furthermore, the nature of the metal surfaces protected in the methods of this invention is not critical. The metals in which the system operates may include, but are not necessarily limited to iron alloys, copper alloys, nickel alloys, titanium alloys, and these metals in unalloyed form as well, etc.
The first component of the neutralizing composition is an amine compound, preferably one or more alkylamine or alkanolamine, preferably dimethylethanolamine (DMEA), dimethylisopropanolamine (DMIPA), ethylenediamine (EDA),
methoxypropylamine (MOPA), monoethanolamine (MEA), dimethylaminopropylamine (DMAPA), morpholine, and trimethylamine (TMA). The one or more alkylamine or alkanolamine is added in an amount of from 1 ppm to 10,000 ppm based on the petroleum products.
Preferably the amine compound is added in an amount of equal to or greater than 1 ppm, preferably equal to or greater than 1 ppm, more preferably equal to or greater than 10 ppm, and more preferably equal to or greater than 100 ppm based on the petroleum products. Preferably the amine compound is added in an amount of equal to or less than 5,000 ppm, preferably equal to or less than 1,000 ppm, and more preferably equal to or less than 500 ppm based on the petroleum products.
The second component of the neutralizing composition is an alcohol. Any suitable alcohol may be used. Preferably, the alcohol is a polyol, polyether diol, polyether triol, or mixtures thereof. In one embodiment, the alcohol s a polyol based on ethylene glycol reacted with ethylene oxide, a polyol based on ethylene glycol reacted with propylene oxide, a polyol based on ethylene glycol reacted with butylene oxide or a polyol based on ethylene glycol reacted with ethylene oxide and/or propylene oxide and/or butylene oxide, or mixtures thereof. In another embodiment, the alcohol is s a polyol based on glycerol reacted with ethylene oxide, a polyol based on glycerol reacted propylene oxide, a polyol based on glycerol reacted ethylene oxide and propylene oxide, or mixtures thereof. In yet another embodiment, the alcohol is ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, glycerol, polyethylene glycol, polypropylene glycol, polytetramethylene glycol, or mixtures thereof. The one or more alcohol is added in an amount of from 1 ppm to 10,000 ppm based on the petroleum products.
Preferably alcohol is added in an amount of equal to or greater than 1 ppm, preferably equal to or greater than 1 ppm, more preferably equal to or greater than 10, and more preferably equal to or greater than 100 ppm based on the petroleum products.
Preferably the alcohol is added in an amount of equal to or less than 5,000 ppm, preferably equal to or less than 1,000 ppm, and more preferably equal to or less than 500 ppm based on the petroleum products.
It will be appreciated that it is difficult to predict what the optimum dosage rate would be in advance for any particular system. The dosage will depend upon a variety of complex, interrelated factors including, but not necessarily limited to, the exact nature of the stream being fractionated, the temperature and pressure of the distillation conditions, the particular amine blends used, etc. In one non-limiting embodiment of the invention, the dosage rate will be determined on a case-by-case basis depending upon the acid content of the system. It may be desirable to use computer modeling to determine the optimum rate. Nevertheless, to provide some understanding of expected or possible dosage rates, the amount of the amine compound and alcohol may independently range from 1 to 10,000 ppm, based on the petroleum products. In another non- limiting embodiment, the amount of the amine compound and alcohol may independently range from 1 to 500 ppm.
The desired pH range for all points in the system is from 4 to 8.5, and in another non-limiting embodiment may be from 5 to 7. Alternatively, to give another idea of expected dosage rates, the neutralizing composition may be added to the system at a rate sufficient to maintain the pH of water condensate in the system at a pH of equal to or greater than 4.0. In another non-limiting embodiment, the neutralizing composition may be added to the system at a rate sufficient to maintain the pH of equal to or greater than 5.0. EXAMPLES
The solubility of the monoethanolamine hydrochloride (MEA HQ) and or ethylenediamine hydrochloride (EDA 2HC1) in diethylene glycol or glycerol is determined as follows: to 10 g of diethylene glycol or glycerol is added an excess amount of the salt and the reaction mixture is stirred rigorously for at least lh at the desired temperature. The stirring is then stopped and the reaction mixture is allowed to settle. The solubility of the salt in ethylene glycol or glycerol is calculated from the chloride concentration measured by Ion Chromatography. The viscosity of the saturated solution is measured on a Stabinger Viscometer.
Example 1.
The solubility of MEA HC1 and EDA 2HC1 in diethylene glycol at different temperatures is shown in FIG. 1 and the viscosity of the room temperature saturated solution of MEA HQ and EDA 2HC1 at different temperatures is shown FIG. 2.
Example 2.
At 25°C, the solubility of MEA HC1 and EDA 2HC1 in glycerol is determined to be 44.5 wt% and 12.8 wt%, respectively. The viscosity of the room temperature saturated solution of MEA HQ in glycerine and EDA 2HC1 in glycerine at different temperatures is shown in FIG. 3.

Claims

What is claimed is:
1. A process for controlling corrosion in an overhead system of a refining unit comprising water condensate and petroleum products comprising the step of adding to the system an amine and an alcohol.
2. The process of Claim 1 wherein the amine is an alkylamine, an alkanolamine, or mixtures thereof.
3. The process of Claim 1 wherein the amine is dimethylethanolamine (DMEA), dimethylisopropanolamine (DMIPA), ethylenediamine (EDA), methoxypropylamine (MOPA), monoethanolamine (MEA), dimethylaminopropylamine (DMAPA), morpholine, trimethylamine (TMA), picoline, pyridine, or mixtures thereof.
4. The process of Claim 1 wherein the alcohol is a polyol, polyether diol, polyether triol, or mixtures thereof.
5. The process of Claim 1 wherein the alcohol is a polyol based on ethylene glycol reacted with ethylene oxide, a polyol based on ethylene glycol reacted with propylene oxide, or a polyol based on ethylene glycol reacted with ethylene oxide and propylene oxide, or mixtures thereof.
6. The process of Claim 1 wherein the alcohol is a polyol based on glycerol reacted with ethylene oxide, a polyol based on glycerol reacted propylene oxide, a polyol based on glycerol reacted butylene oxide, a polyol based on glycerol reacted ethylene oxide and/or propylene oxide and/or butylene oxide, or mixtures thereof.
7. The process of Claim 1 wherein the alcohol is ethylene glycol, diethylene glycol, triethylene glycol, tetraethylene glycol, glycerol, polyethylene glycol, polypropylene glycol, polytetramethylene glycol, or mixtures thereof.
8. The process of Claim 1 wherein the alcohol is diethylene glycol, ethylene glycol, glycerol, or mixtures thereof.
9. The process of Claim 1 wherein the amine and the alcohol are added to the system separately.
10. The process of Claim 1 wherein the amine and the alcohol are added to the system together.
11. The process of Claim 1 wherein the amount of the amine and the alcohol independently range from 1 to 10,000 ppm based on the petroleum products.
12. The process of Claim 1 further comprising the step of adding the amine and the alcohol to the system at a rate sufficient to maintain the pH of water condensate in the system at a pH of equal to or greater than 4.0.
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