METHODS AND SYSTEMS FOR TREATING PETROLEUM FEEDSTOCK CONTAINING ORGANIC ACIDS AND SULFUR

Abstract

Methods and systems of treating petroleum feedstock contaminated with naphthenic acids and sulfur are disclosed. The methods and systems include heating the petroleum feedstock to decompose the naphthenic acids, pressurizing to minimize the portion in the vapor phase, sweeping water vapor and carbon dioxide into a headspace with a non-oxidizing gas, removing water vapor and carbon dioxide from the headspace, reacting the sulfur with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides, and removing the alkali sulfides. Also disclosed is reacting the naphthenic acid with water and an oxide or hydroxide of an alkaline earth element to convert the naphthenic acid into naphthenates, removing water, ketonizing, removing oxides or carbonates, reacting the sulfur with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides, and removing the alkali sulfides.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application Ser. No. 61/909,092 filed Nov. 26, 2013, entitled “Method to Reduce Alkali Metal Needed for Desulfurization of High TAN Petroleum Feedstock.” The disclosure of the application to which the present application claims priority is incorporated by reference.

Without claiming domestic priority, this application is related to U.S. Pat. No. 8,828,220 filed Nov. 1, 2010, titled “Upgrading of petroleum oil feedstocks using alkali metals and hydrocarbons” and U.S. Pat. No. 8,828,221 filed Jul. 16, 2012, titled “Upgrading platform using alkali metals.” These prior patent applications are expressly incorporated herein by reference.

TECHNICAL FIELD

The present disclosure relates to methods and systems for treating petroleum feedstock containing organic acids and sulfur. More specifically, the present disclosure relates to reducing the amount of alkali metal needed for desulfurization of high TAN petroleum feedstock by treating organic acids in high TAN petroleum feedstock prior to desulfurization.

BACKGROUND

There is an ongoing demand for hydrocarbon fuels as an energy source and newer sources of hydrocarbon raw materials are being exploited. These newer sources of hydrocarbon raw materials include shale oil, bitumen, heavy oils, and other similar materials. However, these types of hydrocarbon raw materials often contain high levels of difficult-to-remove sulfur and heavy metals. The high level of nitrogen, sulfur, and heavy metals in these newer sources of hydrocarbon raw materials (which may collectively or individually be referred to as “petroleum feedstock”) makes processing these materials difficult. Typically, these petroleum feedstock materials are refined to remove the sulfur, nitrogen and heavy metals through processes known as “hydro-treating” or “alkali metal desulfurization.”

U.S. Pat. Nos. 8,828,820 and 8,828,821 to Gordon describe methods for desulfurizing and demetallizing petroleum feedstock. Gordon describes methods by which petroleum feedstock is reacted with molten alkali metal in the presence of a radical capping gas. In Gordon's process the molten alkali metal reacts with heavy metals such as nickel and vanadium in the petroleum feedstock. Alkali metal sulfides are also formed from sulfur in the petroleum feedstock. The treated heavy metals and alkali metal sulfides can then be separated from the oil by standard processes such as gravimetric separation, filtration, or centrifugation.

However, these petroleum feedstocks that are high in sulfur and heavy metals can often be high in total acid number (TAN) with values in the range of 1 mg KOH/g. TAN is an important quality measurement of crude oil and is a measurement of total acidity as determined by the amount of potassium hydroxide needed to neutralize the acids in one gram of oil. High TAN values can pose a corrosion problem to machinery, piping, or other metal surfaces that contact the high TAN petroleum. Due to this corrosion problem, petroleum refineries will often restrict the amount of high TAN petroleum feedstock that can be processed. Therefore, there is a need to lower TAN levels in petroleum feedstock prior to refinery processing.

Generally, the acidity in high TAN petroleum feedstock can be attributed to organic acids, such as naphthenic acids. Havre describes naphthenic acids in petroleum feedstock as carboxylic monoacids of the general formula RCOOH where R represents any cycloaliphatic structure. Havre, T. E. (2002). Formation of calcium naphthenate in water/oil systems, naphthenic acid chemistry and emulsion stability. Havre further describes naphthenic acids as C₁₀-C₅₀ compounds with 0-6 fused saturated rings and with the carboxylic acid group attached to a ring via a short side chain.

The method of Gordon can remove organic acids, including naphthenic acids, from petroleum feedstocks despite the varying specific structure of the organic acids. While much of the following discussion will refer specifically to naphthenic acids, it is understood that the disclosed methods and systems may be used to treat other organic acids present in petroleum feedstocks. In Gordon, the molten alkali metal can react with the naphthenic acid and allow for their removal. In the case where molten sodium is the alkali metal added to petroleum feedstock containing naphthenic acids, the reaction of Equation 1a is assumed to occur. A similar reaction where molten lithium is the alkali metal is depicted in Equation 1b:

RCOOH+Na→RCOONa+½H₂  Equation 1a

RCOOH+Li→RCOOLi+½H₂  Equation 1b

In Equations 1a and 1b, the naphthenic acids are converted to sodium naphthenate and lithium naphthenate, respectively. The method of Gordon can lower the TAN caused by naphthenic acids by converting the naphthenic acids to naphthenate salts and thereby lowering the corrosiveness of the treated petroleum feedstock. Unfortunately, there are a number of drawbacks to using the method of Gordon or similar methods to remove naphthenic acids from high TAN petroleum feedstocks. These drawbacks include the consumption of costly alkali metal in the process, the formation of amphiphilic alkali naphthenate salts that can form stable emulsions that can be difficult to remove, and the lack of an easy methodology for recovering alkali metal from alkali naphthenates.

One drawback to the method of Gordon and similar methods is that costly alkali metal is consumed to convert naphthenic acids to alkali naphthenates. Alkali metal that reacts with naphthenic acids is not available to react with and remove sulfur from the petroleum feedstock. Also, alkali naphthenates can be difficult to remove from the petroleum feedstock. The amphiphilic nature of alkali naphthenates causes them to reside at water-oil interfaces and to form stable emulsions that can be difficult to remove from the petroleum feedstock and create problems with downstream processing. Furthermore, it is undesirable for the alkali metal (in the form of the alkali naphthenate) to remain in the petroleum feedstock with amounts over about 100 ppm needing to be removed. Lastly, it is difficult to regenerate the alkali metal from alkali naphthenates. In contrast, alkali sulfide can be easily recovered from the feedstock and the alkali metal from alkali sulfide can be regenerated via electrolysis.

Therefore, there is a need in the industry for new methods and systems to treat naphthenic acids in high TAN petroleum feedstocks prior to treatment with alkali metal to remove sulfur and heavy metals. Such methods and systems are disclosed herein.

BRIEF SUMMARY

Methods and systems for treating petroleum feedstock are disclosed. In some embodiments, the present application discloses methods and systems for treating petroleum feedstock comprising providing a petroleum feedstock comprising organic acids, such as naphthenic acids, and sulfur, heating the petroleum feedstock to decompose the organic acids, pressurizing the petroleum feedstock to minimize a portion of the petroleum feedstock in a vapor phase, sweeping water vapor and carbon dioxide from the petroleum feedstock into a headspace with a non-oxidizing gas, removing water vapor and carbon dioxide from the headspace to promote organic acid decomposition, reacting the sulfur with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides, and removing the alkali sulfides.

In other embodiments, the present application discloses methods and systems for treating petroleum feedstock comprising providing a petroleum feedstock comprising organic acids, such as naphthenic acids, and sulfur, reacting the organic acid with a quantity of water and a stoichiometric excess of an oxide or hydroxide of an alkaline earth element while heating to convert the organic acid into alkaline earth carboxylates, such as naphthenates, to generate an alkaline earth carboxylate (naphthenate) mixture, removing water from the alkaline earth carboxylate (naphthenate) mixture to generate a dewatered mixture, reacting the sulfur in the dewatered mixture with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides, and removing the alkali sulfides

In yet other embodiments, the present application discloses methods and systems for treating petroleum feedstock comprising providing a petroleum feedstock comprising organic acids, such as naphthenic acids, and sulfur, reacting the organic acid with a quantity of water and a stoichiometric excess of an oxide or hydroxide of an alkaline earth element while heating to convert the organic acid into an alkaline earth carboxylate (naphthenate) to generate an alkaline earth carboxylate (naphthenate) mixture, removing water from the alkaline earth carboxylate (naphthenate) mixture to generate a dewatered mixture, heating the dewatered mixture to convert alkaline earth carboxylates (naphthenates) into ketones and alkaline earth oxides or alkaline earth carbonates to generate a ketone mixture, removing alkaline earth oxides or alkaline earth carbonates from the ketone mixture, reacting the sulfur in the ketone mixture with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides, and removing the alkali sulfide.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the above-recited and other advantages and features of the invention can be obtained, a more particular description of the invention briefly described above will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only typical embodiments of the invention and are not therefore to be considered to be limiting of its scope, the invention will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

FIG. 1 illustrates a method and system for treating petroleum feedstock by decomposing naphthenic acid by heat followed by reaction with alkali metal and radical capping gas;

FIG. 2 illustrates a method and system for treating petroleum feedstock by reacting the feedstock with oxides or hydroxides of alkaline earth elements followed by reaction with alkali metal and radical capping gas;

FIG. 3 illustrates a method and system for treating petroleum feedstock by reacting the feedstock with oxides or hydroxides of alkaline earth elements, dewatering, and ketonization, followed by reaction with alkali metal and radical capping gas; and

FIG. 4 illustrates a method and system for treating petroleum feedstock by reacting the feedstock with oxides or hydroxides of alkaline earth elements, dewatering, followed by ketonization and reaction with alkali metal and radical capping gas.

DETAILED DESCRIPTION OF THE INVENTION

The present application discloses methods and systems for treating petroleum feedstock. More specifically, the present disclosure relates to treating organic acids (including naphthenic acids) in high TAN petroleum feedstock followed by treatment with alkali metals to remove sulfur and optionally heavy metals. In some embodiments, the present application discloses methods and systems for thermally treating a liquid high TAN petroleum feedstock at a temperature high enough and at a pressure sufficient to decompose carboxylic acid groups of the organic acids while minimizing any fraction of the feedstock from leaving the liquid phase. In other embodiments, the thermal pretreatment of the petroleum feedstock can lower or eliminate the amount of organic or naphthenic acids in the petroleum feedstock, thereby requiring less alkali metal for further processing and lessening the amount of naphthenate salts that must be removed. In yet other embodiments, a high TAN petroleum feedstock can be pretreated with water and oxides or hydroxides of alkaline earth elements to generate alkaline earth carboxylates or naphthenates before treatment with alkali metal for desulfurization and demetallization. In some embodiments, high TAN petroleum feedstock can be pretreated with water and a stoichiometric excess of oxides or hydroxides of alkaline earth elements to generate alkaline earth carboxylates or naphthenates, dewatered, heated to form ketones, the ketones removed, and treated with alkali metal. In other embodiments, the ketone formation and the alkali metal treatment can be carried out at the same time in a single reactor vessel. In yet other embodiments, the alkali metals and/or the alkaline earth oxides or hydroxides can be regenerated.

In some embodiments the present application discloses methods and systems for treating petroleum feedstock containing contaminants. In some embodiments, contaminants can comprise one or more of organic acids, carboxylic acids, naphthenic acids, sulfur, or heavy metals. In some embodiments, treating the petroleum feedstock can comprise removing one or more contaminants from the petroleum feedstock. In other embodiments, treating the feedstock can comprise lowering the levels of one or more contaminants to levels sufficient for further petroleum processing. In yet other embodiments, treating the petroleum feedstock can comprise lowering the TAN values to sufficient levels to lessen corrosion during further processing of the petroleum feedstock.

In some embodiments, contaminants in petroleum feedstock can comprise sulfur, sulfur compounds and/or sulfur containing molecules and complexes. In other embodiments, sulfur contaminants can comprise organic sulfur compounds, thiols, thiophenes, organic sulfides, and/or organic disulfides. In yet other embodiments, sulfur contaminants can include benzothiophenes and dibenzothiophenes.

In some embodiments, heavy metal contaminants can comprise any metal that interferes with any further processing or use of the petroleum feedstock. In other embodiments, heavy metal contaminants can comprise heavy metals such as nickel and vanadium. In yet other embodiments, heavy metal contaminants can comprise iron, arsenic, and vanadium. In some embodiments, heavy metal contaminants in petroleum feedstock can comprise nickel, vanadium, copper, cadmium, lead, chromium, iron, cobalt, cadmium, zinc, and mercury.

In some embodiments petroleum feedstock can comprise high TAN petroleum feedstock. In other embodiments, petroleum feedstock can comprise shale oil, bitumen, heavy oils, heavy crudes, and other similar materials. In yet other embodiments, petroleum feedstock can comprise shale oils such as those found in the Green River Formation. In some embodiments, petroleum feedstock can comprise bitumens such as those found in Alberta, Canada. In other embodiments, petroleum feedstock can comprise heavy oils such as those found in Venezuela. In yet other embodiments, petroleum feedstock can comprise bitumens such as Athabasca bitumen found in Northern Alberta, Canada.

In some embodiments, TAN values can comprise any substance in a petroleum feedstock that contributes to total acid number. In other embodiments, organic acids in a petroleum feedstock contribute to TAN values. In yet other embodiments, organic acids such as naphthenic acids in petroleum feedstock contribute to TAN values. In other embodiments, TAN value is a measurement of acidity of a petroleum feedstock as determined by the amount of potassium hydroxide in milligrams that is needed to neutralize the acids in one gram of the feedstock. In yet other embodiments, TAN value can be calculated by potentiometric titration, color indicating titration, spectroscopic methods, or combinations thereof. In some embodiments, TAN value can be calculated by ASTM method D-664. In other embodiments, a high TAN value can comprise values over 5. In yet other embodiments, a high TAN value can comprise values over 3. In some embodiments, a high TAN value can comprise values higher than 1.

In some embodiments, petroleum feedstock comprises organic acids. In other embodiments, the organic acids in petroleum feedstock can comprise naphthenic acids. In other embodiments, naphthenic acids can comprise a naphtha moiety with a carboxylic acid group. In yet other embodiments, naphthenic acids can comprise an unspecific mixture of carboxylic acids with five or six membered carbon rings. In some embodiments, naphthenic acids can have a molecular weight between about 120 to over 700 a.m.u. In other embodiments, naphthenic acids can have a carbon backbone of between about 9 to about 20 carbons. In yet other embodiments, naphthenic acids in petroleum feedstock can cause corrosion known as naphthenic acid corrosion.

In some embodiments, naphthenic acids in petroleum feedstock can be decomposed. In other embodiments, naphthenic acids can be decomposed by heating to generate a naphtha moiety, water and carbon dioxide. In yet other embodiments, naphthenic acids can be decomposed by heating under pressure to generate a naphtha moiety, water and carbon dioxide. In some embodiments, during heating, the pressure can be maintained to minimize the portion of the petroleum feedstock that enters a vapor phase. In other embodiments, during heating under pressure, a nonoxidizing gas can sweep the petroleum feedstock to draw away generated water and/or water vapor. In yet other embodiments, during heating under pressure, a nonoxidizing gas can sweep the petroleum feedstock to draw away generated carbon dioxide. In some embodiments, the generated water and/or water vapor and/or carbon dioxide can be drawn into a headspace. In other embodiments, the generated water and/or water vapor and/or carbon dioxide can be bled from the headspace to promote decomposition of the naphthenic acid. In yet other embodiments, the generated water and/or water vapor and/or carbon dioxide can be bled from the headspace to prevent inhibition of decomposition from a buildup of decomposition products.

In some embodiments, the nonoxidizing gas can comprise any inert gas that does not react with the petroleum feedstock. In other embodiments, the nonoxidizing gas can comprise hydrogen, light hydrocarbon gas, pyrolysis gas, fuel gas, nitrogen, or combinations thereof. In yet other embodiments, light hydrocarbon gas can comprise methane, ethane, propane, butane, pentane, hexane, or combinations thereof. In some embodiments, light hydrocarbon gas can comprise any hydrocarbon gas comprising between one and six carbons.

In some embodiments, naphthenic acids can be decomposed by heating the petroleum feedstock in the range of a lower decomposition temperature of about 200° C. and an upper decomposition temperature of about 425° C. In other embodiments, the range can comprise a lower decomposition temperature of about 300° C. and an upper decomposition temperature of about 400° C. In yet other embodiments, the range can comprise a lower decomposition temperature of about 232° C. and an upper decomposition temperature of about 400° C. In some embodiments, the range comprises a lower decomposition temperature of about 260° C. and an upper decomposition temperature of about 385° C. In other embodiments, the lower decomposition temperature can be 200° C., 210° C., 220° C., 230° C., 240° C., 250° C., 260° C., 270° C., 280° C., or 290° C. In yet other embodiments, the upper decomposition temperature can be 350° C., 360° C., 370° C., 380° C., 390° C., 400° C., 410° C., 420° C., 430° C., 440° C., 450° C., 460° C., 470° C., 480° C., 490° C., or 500° C.

In some embodiments, naphthenic acids can be decomposed by heating the petroleum feedstock under pressure in a pressure range of a lower pressure limit of about one atmosphere and an upper pressure limit of about 1000 psig. In other embodiments, the pressure range can comprise a lower pressure limit of about 15 psig and an upper pressure limit of about 500 psig. In yet other embodiments, the pressure range can comprise a lower pressure limit of about 30 psig and an upper pressure limit of about 300 psig. In some embodiments, the lower pressure limit can be zero psig, 5 psig, 10 psig, 15 psig, 20 psig, 25 psig, or 30 psig. In some embodiments, the upper pressure limit can be 300 psig, 400 psig, 500 psig, 600 psig, 700 psig, 800 psig, 900 psig, or 1000 psig.

In some embodiments, naphthenic acids can react with alkaline earth oxides or hydroxides to generate alkaline earth naphthenates. In other embodiments, naphthenic acids can react with water and a stoichiometric excess of alkaline earth oxides or hydroxides under heating to generate alkaline earth naphthenates. Equations 2a-2b may describe this process where R is a naphtha group, R′ is another naphtha group, and Ae is an alkaline earth element, and AeO is an alkaline earth oxide.

RCOOH+R′COOH+AeO→RCOOAeOOCR′.H₂O  Equation 2a

RCOOAeOOCR′.H₂O→RCOOAeOOCR′+H₂O  Equation 2b

In some embodiments, Equation 2a may describe the formation of a monohydrate salt of an alkaline earth naphthenate from naphthenic acids and an alkaline earth oxide. In other embodiments, an alkaline earth hydroxide can take the place of the alkaline earth oxide. In yet other embodiments, the alkaline earth naphthenate can comprise a coordination complex of naphthenate groups complexed to the alkaline earth element. Equation 2b may describe the formation of an anhydrous salt of an alkaline earth naphthenate from the monohydrate salt.

In some embodiments, naphthenic acids can react with water and a stoichiometric excess of alkaline earth oxides or hydroxides to generate alkaline earth naphthenates by heating in the range of a lower reaction temperature of about 80° C. and an upper reaction temperature of about 95° C. In other embodiments, the range can comprise a lower decomposition temperature of about 50° C. and an upper decomposition temperature of about 150° C. In yet other embodiments, the range can comprise a lower reaction temperature of about 50° C. and an upper reaction temperature of about 400° C. In some embodiments, the lower reaction temperature can be 50° C., 55° C., 60° C., 65° C., 70° C., 75° C., or 80° C. In other embodiments, the upper reaction temperature can be 90° C., 95° C., 100° C., 105° C., 110° C., 115° C., 120° C., 125° C., 130° C., 135° C., 140° C., 145° C., 150° C., 155° C., 160° C., or 165° C.

In some embodiments, alkaline earth naphthenates can be heated to generate ketones. Equations 2c-2d may describe this process where R is a naphtha group, R′ is another naphtha group, and Ae is an alkaline earth element, AeO is an alkaline earth oxide, and AeCO₃ is an alkaline earth carbonate:

RCOOAeOOCR′→RCOR′+AeCO₃  Equation 2c

RCOOAeOOCR′→RCOR′+AeO+CO₂  Equation 2d

Equation 2c may describe the formation of a ketone from the anhydrous salt of an alkaline earth naphthenate with an alkaline earth carbonate also produced. In some embodiments, the ketone may be a ketone comprising two naphtha moieties. Equation 2d may describe the formation of a ketone from the anhydrous salt of an alkaline earth naphthenate with an alkaline earth oxide and carbon dioxide also produced. In other embodiments, removal of the alkaline earth carbonate, alkaline earth oxide, and/or carbon dioxide can promote the ketonization reaction.

In some embodiments, alkaline earth naphthenates can be heated to generate ketones in a range of a lower heating temperature of about 100° C. to an upper heating temperature of about 400° C. In other embodiments, the range can comprise a lower heating temperature of about 166° C. to an upper heating temperature of about 312° C. In some embodiments, the lower reaction temperature can be 100° C., 110° C., 120° C., 130° C., 140° C., 150° C., 160° C., 170° C., 180° C., 190° C., or 200° C. In other embodiments, the upper reaction temperature can be 290° C., 300° C., 305° C., 310° C., 320° C., 330° C., 340° C., 350° C., 360° C., 370° C., 380° C., 390° C., or 400° C.

In some embodiments, sulfur in the petroleum feedstock can be reacted with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides. In other embodiments, sulfur in the petroleum feedstock can be reacted with an alkali metal and a radical capping gas with heating to convert the sulfur into alkali metal sulfides. In yet other embodiments, sulfur in the petroleum feedstock can be reacted with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides according to the methods disclosed in U.S. Pat. Nos. 8,828,820 and 8,828,821 to Gordon. Equation 3 may describe this process where S is a sulfur group, X is an first organic group, X′ is a second organic group, XSX′ is an organic sulfur contaminant, H is a radical capping gas, and A is an alkali element.

XSX′+2A+H₂→A₂S+HX+HX′  Equation 3

In other embodiments, other reactions can describe reacting sulfur in petroleum feedstock with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides. In yet other embodiments, the alkali metal can be added in stoichiometric excess. In some embodiments, the radical capping gas can be added in stoichiometric excess. In other embodiments, reacting sulfur in petroleum feedstock with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides can further comprise a catalyst to help promote the reaction. The catalysts may include by way of non-limiting example, molybdenum, nickel, cobalt or alloys of molybdenum, alloys of nickel, alloys of cobalt, alloys of molybdenum containing nickel and/or cobalt, alloys of nickel containing cobalt and/or molybdenum, molybdenum oxide, nickel oxide or cobalt oxides and combinations thereof.

In some embodiments, reacting sulfur in petroleum feedstock with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides can be done with heating in the range of a lower conversion temperature of about 150° C. and an upper conversion temperature of about 450° C. In other embodiments, the range can comprise a lower conversion temperature of about 200° C. and an upper conversion temperature of about 400° C. In yet other embodiments, the lower conversion temperature can be 150° C., 160° C., 170° C., 180° C., 190° C., or 200° C. In some embodiments, the upper conversion temperature can be 400° C., 410° C., 420° C., 430° C., 440° C., 450° C., 460° C., 470° C., 480° C., 490° C., or 500° C. In other embodiments, reacting sulfur in petroleum feedstock with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides can be carried out at a pressure greater than 250 psi. In yet other embodiments, reacting sulfur in petroleum feedstock with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides can be carried out at a pressure below 2500 psi. In some embodiments, reacting sulfur in petroleum feedstock with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides can be carried out at a pressure between about 500 psi and about 3000 psi.

In some embodiments, the alkali metal can comprise lithium, sodium, or potassium, or combinations thereof. In other embodiments, the alkali metal can comprise alloys of lithium, sodium, or potassium. In yet other embodiments, the alkali metal may be molten to facilitate mixing with the petroleum feedstock. In some embodiments, a powdered or other solid quantity of the alkali metal can be introduced to the petroleum feedstock. Sodium is preferred alkali metal because of its low cost, ready availability, and ease of recovery and regeneration.

In some embodiments the radical capping gas can comprise a hydrocarbon gas. In other embodiments, the radical capping gas can comprise hydrogen gas. In yet other embodiments, radical capping gas can comprise methane, ethane, propane, butane, pentane, hexane, heptane, octane, ethene, propene, butene, pentene, hexene, heptane, octene, and their isomers. In some embodiments, the radical capping gas can comprise other hydrocarbons (such as octane, or other carbon containing compounds containing one or more carbon atoms). In other embodiments, the radical capping gas may comprise a mixture of hydrocarbon gases. In yet other embodiments, the radical capping gas may comprise natural gas or shale gas—the gas produced by retorting oil shale. In some embodiments, the radical capping gas may comprise one or more of the following: methane, ethane, propane, butane, pentane, hexane, heptane, octane, ethene, propene, butene, pentene, hexene, heptene, octene, and isomers of the foregoing, natural gas, shale gas, liquid petroleum gas, ammonia, primary, secondary, and tertiary ammines, thiols, mercaptans, and hydrogen sulfide.

In some embodiments, alkali sulfide generated from the petroleum feedstock can be processed to recover the elemental alkali metal and sulfur. In other embodiments, recovery of elemental alkali metal can comprise an electrolytic reaction (electrolysis) of an alkali metal sulfide and/or polysulfide using an alkali ion conductive ceramic membrane (such as, for example, a NaSICON or LiSICON membrane that is commercially available from Ceramatec, Inc. of Salt Lake City, Utah). In some embodiments, processes for recovering elemental alkali metal can be found in U.S. Pat. No. 3,787,315; U.S. Pat. No. 8,088,270; and U.S. Pat. No. 7,897,028 (which documents are incorporated herein by reference). In yet other embodiments, the recovered elemental alkali metal can be used to react with sulfur in the petroleum feedstock.

FIG. 1 illustrates a method 100 for treating petroleum feedstock containing contaminants. In some embodiments, a petroleum feedstock containing contaminants 102 can be transferred to a decomposition reactor 110. A non-oxidizing gas 112 can sweep the decomposition reactor 110. The decomposition reactor 110 can be maintained at pressure to minimize an amount of the feedstock 102 that is in the vapor phase. The decomposition reactor 110 can be maintained at a temperature between about 200° C. and 425° C. to decompose carboxylic acids. In some embodiments, the carboxylic acids can comprise naphthenic acids. In other embodiments, the decomposition reactor can be maintained at a temperature between about 300° C. and 400° C. A gas induction impeller can draw the non-oxidizing gas 112 through the feedstock 102 to bubble through the feedstock to sweep water vapor and carbon dioxide into the headspace. The headspace can be continuously bled 114 to maintain water and carbon dioxide at levels that are favorable to carboxylic acid decomposition. The treated feedstock 116 can be transferred to an alkali metal reactor 120. In some embodiments, the temperature of the decomposition reactor 110, the amount of non-oxidizing gas 112, the amount of pressure maintained, and the speed and/or capacity of the gas induction impeller can be varied to generate effective decomposition of carboxylic acids. In other embodiments, the temperature of the decomposition reactor 110, the amount of non-oxidizing gas 112, the amount of pressure maintained, and the speed and/or capacity of the gas induction impeller can be varied to generate effective decomposition of carboxylic acids based on the viscosity of the petroleum feedstock, the TAN values, and/or the levels of contaminants.

In some embodiments, the treated feedstock 116 can be transferred to the alkali metal reactor 120 to be further treated. Radical capping gas 122 and alkali metal 124 can be added to the alkali metal reactor 120. In other embodiments, radical capping gas 122 can comprise one or more of the following: methane, ethane, propane, butane, pentane, hexane, heptane, octane, ethene, propene, butene, pentene, hexene, heptene, octene, and isomers of the foregoing, natural gas, shale gas, liquid petroleum gas, ammonia, primary, secondary, and tertiary ammines, thiols, mercaptans, and hydrogen sulfide. In yet other embodiments, radical capping gas 122 can comprise any suitable gas material. In some embodiments, alkali metal 124 can comprise lithium, sodium, potassium, or combinations thereof. In other embodiments, the sulfur contaminants in the treated feedstock 116 can form alkali sulfides in the alkali metal reactor 120. In yet other embodiments, the heavy metal contaminants in the treated feedstock 116 can be changed in oxidation state to a reduced metallic state. The alkali metal treated feedstock 126 can be transferred to a solid-liquid separator 130.

In some embodiments, the alkali metal treated feedstock can comprise one or more of decomposed carboxylic acids (and/or decomposed naphthenic acids), alkali sulfides, and/or heavy metals in a reduced metallic state. In other embodiments, one or more of the decomposed carboxylic acids (and/or decomposed naphthenic acids), alkali sulfides, and/or heavy metals in a reduced metallic state can be in a solid and/or precipitated form. The solid-liquid separator 130 can separate solids 132 from a liquid fraction 134. The liquid fraction 134 can be transferred for further processing 140. In some embodiments, the solid-liquid separator 130 can comprise filtration, centrifugation, and/or hydrocyclonic separation. In other embodiments, the solid-liquid separator 130 can comprise gravimetric separation methods.

In some embodiments, the solids 132 can be transferred to alkali regeneration 136. The alkali regeneration 136 can comprise regenerating the alkali metal 124 from alkali sulfides or other alkali salts. In other embodiments, alkali regeneration 136 can comprise regenerating the alkali metal 124 by an electrolytic process comprising an alkali ion conductive ceramic membrane. In yet other embodiments, alkali regeneration 136 can comprise any method or process suitable for regenerating alkali metal from alkali sulfides or other alkali salts. In some embodiments, regenerated alkali metal 128 can be transferred to the alkali metal 124 source for use in reactor 120.

FIG. 2 illustrates a method 200 for treating petroleum feedstock containing contaminants. In some embodiments, a petroleum feedstock containing contaminants 202 can be transferred to an alkaline earth reactor 210. A quantity of water 212 can be added to the alkaline earth reactor 210. A stoichiometric excess of an oxide or a hydroxide of an alkaline earth element 214 can be added to the alkaline earth reactor 210. The amount of water needed in the process can be determined by Fourier Transform Infra Red analysis looking for when the carbonyl peak is no longer detected. This amount of water may be 1.5-5 times excess over the stoichiometric amount needed. It is understood that the alkaline earth oxide or hydroxide and water can be introduced into the reactor 210 as an aqueous solution or slurry. It is also understood that less than stoichiometric excess of an oxide or a hydroxide of an alkaline earth element 214 can be added to the alkaline earth reactor 210 resulting in partial reduction in napthenic acid. In some embodiments, a mixture of alkaline earth oxides and alkaline earth hydroxides can be used. In other embodiments, alkaline earth oxides can comprise magnesium oxide or calcium oxide. In yet other embodiments, alkaline earth hydroxides can comprise magnesium hydroxide or calcium hydroxide.

The alkaline earth reactor 210 can be maintained at a temperature to facilitate the formation of alkaline earth naphthenates. In one non-limiting embodiment, the temperature of the alkaline earth reactor is maintained between about 50° C. and 150° C. In other embodiments, the alkaline earth reactor 210 can be maintained at a temperature between about 80° C. and 95° C. A mixer, an impellor, a stirrer or other suitable device can be employed to facilitate formation of alkaline earth naphthenates in the alkaline earth reactor 210. In some embodiments, the temperature of the alkaline earth reactor 210, the amount of water 212 added, the amount of alkaline earth oxide, the amount of alkaline earth hydroxide, an amount of pressure maintained, and/or a speed and/or capacity of the mixer can be varied to generate effective formation of alkaline earth naphthenates.

In some embodiments, the treated feedstock 216 can be transferred to a dewatering reactor 220. The dewatering reactor 220 can separate a dewatered treated feedstock 226 from a water fraction 222. The dewatering reactor 220 can comprise any suitable process for separating a dewatered treated feedstock 226 from a water fraction 222. In some embodiments, the dewatering reactor 220 can comprise an evaporator or an electrostatic type dewatering process. In some embodiments, the water fraction 222 can be recycled and returned to the alkaline earth reactor 210.

In some embodiments, the dewatered treated feedstock 226 can be transferred to an alkali metal reactor 230 to be further treated. Radical capping gas 232 and alkali metal 234 can be added to the alkali metal reactor 230. In other embodiments, radical capping gas 232 can comprise one or more of the following: methane, ethane, propane, butane, pentane, hexane, heptane, octane, ethene, propene, butene, pentene, hexene, heptene, octene, and isomers of the foregoing, natural gas, shale gas, liquid petroleum gas, ammonia, primary, secondary, and tertiary ammines, thiols, mercaptans, and hydrogen sulfide. In yet other embodiments, radical capping gas 232 can comprise any suitable gas material. In some embodiments, alkali metal 234 can comprise lithium, sodium, potassium, or combinations thereof. In other embodiments, the sulfur contaminants in the dewatered treated feedstock 226 can form alkali sulfides in the alkali metal reactor 230. In yet other embodiments, the heavy metal contaminants in the dewatered treated feedstock 226 can be changed in oxidation state to a reduced metallic state. In other embodiments, alkaline earth naphthenates in the dewatered feedstock 226 can form ketones upon heating. In some embodiments, reacting sulfur in petroleum feedstock with an alkali metal and a radical capping gas to convert the sulfur into alkali metal sulfides can be done with heating in the range of about 150° C. to about 450° C. In other embodiments, the temperature can range from about 200° C. to about 400° C. The alkali metal treated feedstock 236 can be transferred to a solid-liquid separator 240.

In some embodiments, the alkali metal treated feedstock can comprise one or more of alkaline earth naphthenates (and/or naphthenate salts), alkaline earth carbonates, alkali sulfides, and/or heavy metals in a reduced metallic state. In other embodiments, one or more of the alkaline earth naphthenates (and/or naphthenate salts), alkali sulfides, and/or heavy metals in a reduced metallic state can be in a solid and/or precipitated form. The solid-liquid separator 240 can separate solids 242 from a liquid fraction 246. The liquid fraction 246 can be transferred for further processing 250. In some embodiments, the solid-liquid separator 240 can comprise filtration, centrifugation, and/or hydrocyclonic separation. In other embodiments, the solid-liquid separator 240 can comprise gravimetric separation methods.

In some embodiments, the solids 244 can be transferred to regeneration cell 246. The regeneration cell 246 can comprise equipment to regenerate the alkali metal 234 from alkali sulfides or other alkali salts. In other embodiments, regeneration cell 246 can comprise an electrolytic process to regenerate the alkali metal 234 comprising an alkali ion conductive ceramic membrane. In yet other embodiments, regeneration cell 246 can comprise any method or process suitable for regenerating alkali metal 234 from alkali sulfides or other alkali salts. In some embodiments, regenerated alkali metal 248 can be transferred to the alkali metal 234 source for use in reactor 230.

In other embodiments, alkaline earth carbonates can be regenerated to form alkaline earth oxides or alkaline earth hydroxides. In yet other embodiments, alkaline earth carbonates can be regenerated to form alkaline earth oxides by heating the alkaline earth carbonates in regeneration cell 246. In some embodiments, regenerated alkaline earth oxides and/or alkaline earth hydroxides can be returned 249 to the alkaline earth reactor 210. In other embodiments, if the alkali metal 234 comprises sodium then the alkaline earth element comprises an alkaline earth metal that is not reduced by sodium, such as calcium. In such cases, magnesium would not be preferred because it is reduced by sodium.

FIG. 3 illustrates a method and system 300 for treating petroleum feedstock containing contaminants. In some embodiments, a petroleum feedstock containing contaminants 302 can be transferred to an alkaline earth reactor 310. A stoichiometric excess of an oxide or a hydroxide of an alkaline earth element 312 in a water solution or slurry can be added to the alkaline earth reactor 310. In some embodiments, a mixture of alkaline earth oxides and alkaline earth hydroxides can be used. In other embodiments, alkaline earth oxides can comprise magnesium oxide or calcium oxide. In yet other embodiments, alkaline earth hydroxides can comprise magnesium hydroxide or calcium hydroxide. A quantity of water 314 can be added to the alkaline earth reactor 310. It is understood that the alkaline earth oxide or hydroxide and water can be introduced into the reactor 310 as an aqueous solution or slurry. It is also understood that less than stoichiometric excess of an oxide or a hydroxide of an alkaline earth element 312 can be added to the alkaline earth reactor 310 resulting in partial reduction in napthenic acid

The alkaline earth reactor 310 can be maintained at a temperature between about 50° C. and 150° C. to facilitate the formation of alkaline earth naphthenates. In other embodiments, the alkaline earth reactor can be maintained at a temperature between about 80° C. and 95° C. A mixer, stirrer or other suitable device can be employed to facilitate formation of alkaline earth naphthenates in the alkaline earth reactor 310. In some embodiments, the temperature of the alkaline earth reactor 310, the amount of water 314 added, the amount of alkaline earth oxide, the amount of alkaline earth hydroxide, an amount of pressure maintained, and/or a speed and/or capacity of the mixer can be varied to generate effective formation of alkaline earth naphthenates.

In some embodiments, a treated feedstock from the alkaline earth reactor 310 can be transferred to a dewatering reactor 320. The dewatering reactor 320 can separate a dewatered treated feedstock from a water fraction 322. In other embodiments, the dewatering reactor 320 can comprise any suitable process for separating a dewatered treated feedstock from a water fraction 322. In some embodiments, the dewatering reactor 320 can comprise an evaporator or an electrostatic type dewatering process. In yet other embodiments, the water fraction 322 can be recycled and returned to the alkaline earth reactor 310.

In some embodiments, the dewatered treated feedstock can be transferred to a ketonization reactor 330. The ketonization reactor 330 can be maintained at a temperature between about 100° C. and 400° C. to facilitate decomposition of alkaline earth naphthenates to form ketones and alkaline earth oxides and/or alkaline earth carbonates. In other embodiments, the alkaline earth reactor 310 can be maintained at a temperature between about 166° C. and about 312° C. In some embodiments, alkaline earth naphthenates can react in the ketonization reactor 330 to form ketones and/or ketones of naphthenates. A mixer, stirrer or other suitable device can be employed to facilitate formation of ketones in the ketonization reactor 330. In some embodiments, a temperature of the ketonization reactor 330, an amount of pressure maintained, and/or a speed and/or capacity of the mixer can be varied to generate effective formation of ketones.

In some embodiments, the feedstock from the ketonization reactor 330 can be transferred to a first solid-liquid separator 340. In other embodiments, the feedstock from the ketonization reactor 330 can comprise ketones, alkaline earth oxides, and/or alkaline earth carbonates. In yet other embodiments, some or all of the ketones, alkaline earth oxides, and/or alkaline earth carbonates can be in a solid and/or precipitated form. The first solid-liquid separator 340 can separate first solids 342 from a first liquid fraction. In some embodiments, the solid-liquid separator 340 can comprise filtration, centrifugation, and/or hydrocyclonic separation. In other embodiments, the solid-liquid separator 340 can comprise gravimetric separation methods.

In some embodiments, the first solids 342 can comprise alkaline earth carbonates, alkaline earth oxides or alkaline earth hydroxides. In some embodiments, alkaline earth carbonates can undergo thermal decomposition to form alkaline earth oxides and carbon dioxide. In yet other embodiments, alkaline earth carbonates can be regenerated to form alkaline earth oxides by heating the alkaline earth carbonates as part of a regeneration process. In some embodiments, regenerated alkaline earth oxides and/or alkaline earth hydroxides can be returned to the alkaline earth reactor 310.

In some embodiments, the first liquid fraction can be transferred to an alkali metal reactor 350 to be further treated. Radical capping gas 352 and alkali metal 354 can be added to the alkali metal reactor 350. In other embodiments, radical capping gas 352 can comprise one or more of the following: methane, ethane, propane, butane, pentane, hexane, heptane, octane, ethene, propene, butene, pentene, hexene, heptene, octene, and isomers of the foregoing, natural gas, shale gas, liquid petroleum gas, ammonia, primary, secondary, and tertiary ammines, thiols, mercaptans, and hydrogen sulfide. In yet other embodiments, radical capping gas 352 can comprise any suitable gas material. In some embodiments, alkali metal 354 can comprise lithium, sodium, potassium, or combinations thereof. In other embodiments, the sulfur contaminants in the first liquid fraction can form alkali sulfides in the alkali metal reactor 350. In yet other embodiments, the heavy metal contaminants in the first liquid fraction can be changed in oxidation state to a reduced metallic state. After reacting in the alkali metal reactor, the alkali metal treated feedstock can be transferred to a second solid-liquid separator 360.

In some embodiments, the alkali metal treated feedstock can comprise one or more of alkali sulfides and optionally heavy metals in a reduced metallic state. In yet other embodiments, one or more of the alkali sulfides and heavy metals in a reduced metallic state can be in a solid and/or precipitated form. The second solid-liquid separator 360 can separate second solids from a second liquid fraction. The second liquid fraction can be transferred for further processing 370. In some embodiments, the solid-liquid separator 360 can comprise filtration, centrifugation, and/or hydrocyclonic separation. In other embodiments, the solid-liquid separator 360 can comprise gravimetric separation methods.

In some embodiments, the second solids can be transferred to regeneration cell 362. The regeneration cell 362 can comprise equipment to regenerate the alkali metal 354 from alkali sulfides or other alkali salts. In other embodiments, regeneration cell 362 can comprise an electrolytic process to regenerate the alkali metal 354 comprising an alkali ion conductive ceramic membrane. In yet other embodiments, regeneration cell 362 can comprise any method or process suitable for regenerating alkali metal 354 from alkali sulfides or other alkali salts. In some embodiments, regenerated alkali metal 354 can be returned to the alkali metal reactor 350. In other embodiments, if the alkali metal 354 comprises sodium then the alkaline earth element comprises an alkaline earth metal that is not reduced by sodium, such as calcium. In such cases, magnesium would not be preferred because it is reduced by sodium.

FIG. 4 illustrates a method and systems 400 for treating petroleum feedstock containing contaminants. In some embodiments, a petroleum feedstock containing contaminants 402 can be transferred to an alkaline earth reactor 410. A stoichiometric excess of an oxide or a hydroxide of an alkaline earth element 412 can be added to the alkaline earth reactor 410. In some embodiments, a mixture of alkaline earth oxides and alkaline earth hydroxides can be used. In other embodiments, alkaline earth oxides can comprise magnesium oxide or calcium oxide. In yet other embodiments, alkaline earth hydroxides can comprise magnesium hydroxide or calcium hydroxide. A quantity of water 414 can be added to the alkaline earth reactor 410. It is understood that the alkaline earth oxide or hydroxide and water can be introduced into the reactor 410 as an aqueous solution or slurry. It is also understood that less than stoichiometric excess of an oxide or a hydroxide of an alkaline earth element 412 can be added to the alkaline earth reactor 410 resulting in partial reduction in napthenic acid

The alkaline earth reactor 410 can be maintained at a temperature between about 50° C. and 150° C. to facilitate the formation of alkaline earth naphthenates. In other embodiments, the alkaline earth reactor 410 can be maintained at a temperature between about 80° C. and 95° C. A mixer, stirrer or other suitable device can be employed to facilitate formation of alkaline earth naphthenates in the alkaline earth reactor 410. In some embodiments, the temperature of the alkaline earth reactor 410, the amount of water 414 added, the amount of alkaline earth oxide, the amount of alkaline earth hydroxide, an amount of pressure maintained, and/or a speed and/or capacity of the mixer can be varied to generate effective formation of alkaline earth naphthenates.

In some embodiments, a treated feedstock from the alkaline earth reactor 410 can be transferred to a dewatering reactor 420. The dewatering reactor 420 can separate a dewatered treated feedstock from a water fraction 422. In some embodiments, the dewatering reactor 420 can comprise an evaporator or an electrostatic type dewatering process. In other embodiments, the dewatering reactor 420 can comprise any suitable process for separating a dewatered treated feedstock from a water fraction 422. In yet other embodiments, the water fraction 422 can be returned to the alkaline earth reactor 410.

In some embodiments, the dewatered treated feedstock can be transferred to an alkali metal reactor 430 to be further treated. Radical capping gas 432 and alkali metal 434 can be added to the alkali metal reactor 430. In other embodiments, radical capping gas 432 can comprise one or more of the following: methane, ethane, propane, butane, pentane, hexane, heptane, octane, ethene, propene, butene, pentene, hexene, heptene, octene, and isomers of the foregoing, natural gas, shale gas, liquid petroleum gas, ammonia, primary, secondary, and tertiary ammines, thiols, mercaptans, and hydrogen sulfide. In yet other embodiments, radical capping gas 432 can comprise any suitable gas material. In some embodiments, alkali metal 434 can comprise lithium, sodium, potassium, or combinations thereof. In other embodiments, sulfur contaminants in the dewatered treated feedstock can form alkali sulfides in the alkali metal reactor 430. In yet other embodiments, heavy metal contaminants in the dewatered treated feedstock can be changed in oxidation state to a reduced metallic state. In some embodiments, alkaline earth naphthenates can react in the alkali metal reactor 430 to form ketones and/or ketones of naphthenates.

The alkali metal reactor 430 can be maintained at a temperature between about 100° C. and 400° C. to facilitate decomposition of alkaline earth naphthenates to form ketones and alkaline earth oxides and/or alkaline earth carbonates. In other embodiments, the alkali metal reactor 430 can be maintained at a temperature between about 166° C. and about 312° C. In yet other embodiments, the alkali metal reactor can first be heated to a temperature range to promote ketonization of the alkaline earth naphthenates and then subsequently heated to a temperature range to promote formation of alkali sulfides. In some embodiments, a temperature range can be selected to promote ketonization of the alkaline earth naphthenates and formation of alkali sulfides.

After reacting in the alkali metal reactor, the alkali metal treated feedstock can be transferred to a solid-liquid separator 440. In some embodiments, the alkali metal treated feedstock can comprise one or more of ketones, alkaline earth naphthenates (and/or naphthenate salts), alkaline earth oxides, alkaline earth carbonates, alkali sulfides, and/or heavy metals in a reduced metallic state. In other embodiments, the alkali metal treated feedstock can comprise ketones, alkali sulfides and/or heavy metals in a reduced metallic state. In yet other embodiments, one or more of the alkali sulfides and/or heavy metals in a reduced metallic state can be in a solid and/or precipitated form. The solid-liquid separator 440 can separate solids from a liquid fraction. The liquid fraction can be transferred for further processing 450. In some embodiments, the solid-liquid separator 440 can comprise filtration, centrifugation, and/or hydrocyclonic separation. In other embodiments, the solid-liquid separator 440 can comprise gravimetric separation methods.

In some embodiments, the solids can be transferred to regeneration cell 442. The regeneration cell 442 can comprise equipment to regenerate the alkali metal 434 from alkali sulfides or other alkali salts. In other embodiments, regeneration cell 442 can comprise an electrolytic process to regenerate the alkali metal 434 comprising an alkali ion conductive ceramic membrane. In yet other embodiments, regeneration cell 442 can comprise any method or process suitable for regenerating alkali metal from alkali sulfides or other alkali salts. In some embodiments, regenerated alkali metal can be transferred to the alkali metal 434 source for use in the alkali metal reactor 430. In other embodiments, if the alkali metal 434 comprises sodium then the alkaline earth element comprises an alkaline earth metal that is not reduced by sodium, such as calcium. In such cases, magnesium would not be preferred because it is reduced by sodium.

In yet other embodiments, the solids can comprise alkaline earth oxides or alkaline earth hydroxides. In some embodiments, alkaline earth carbonates can be regenerated to form alkaline earth oxides or alkaline earth hydroxides. In yet other embodiments, alkaline earth carbonates can be regenerated to form alkaline earth oxides by heating the alkaline earth carbonates as part of a regeneration process in regeneration cell 442. In some embodiments, regenerated alkaline earth oxides and/or alkaline earth hydroxides can be returned to the alkaline earth reactor 410.

The terms “a,” “an,” “the” and similar referents used in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Recitation of ranges of values herein is merely intended to serve as a shorthand method of referring individually to each separate value falling within the range. Unless otherwise indicated herein, each individual value is incorporated into the specification as if it were individually recited herein. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g., “such as”) provided herein is intended merely to better illuminate the invention and does not pose a limitation on the scope of the invention otherwise claimed. No language in the specification should be construed as indicating any non-claimed element essential to the practice of the invention.

It is contemplated that numerical values, as well as other values that are recited herein are modified by the term “about”, whether expressly stated or inherently derived by the discussion of the present disclosure. As used herein, the term “about” defines the numerical boundaries of the modified values so as to include, but not be limited to, tolerances and values up to, and including the numerical value so modified. That is, numerical values can include the actual value that is expressly stated, as well as other values that are, or can be, the decimal, fractional, or other multiple of the actual value indicated, and/or described in the disclosure.

Groupings of alternative elements or embodiments of the invention disclosed herein are not to be construed as limitations. Each group member may be referred to and claimed individually or in any combination with other members of the group or other elements found herein. It is anticipated that one or more members of a group may be included in, or deleted from, a group for reasons of convenience and/or patentability. When any such inclusion or deletion occurs, the specification is deemed to contain the group as modified thus fulfilling the written description of all Markush groups used in the appended claims.

Certain embodiments of this invention are described herein, including the best mode known to the inventors for carrying out the invention. Of course, variations on these described embodiments will become apparent to those of ordinary skill in the art upon reading the foregoing description. The inventor expects skilled artisans to employ such variations as appropriate, and the inventors intend for the invention to be practiced otherwise than specifically described herein. Accordingly, this invention includes all modifications and equivalents of the subject matter recited in the claims appended hereto as permitted by applicable law. Moreover, any combination of the above-described elements in all possible variations thereof is encompassed by the invention unless otherwise indicated herein or otherwise clearly contradicted by context.

It is to be understood that the embodiments of the invention disclosed herein are illustrative of the principles of the present invention. Other modifications that may be employed are within the scope of the invention. Thus, by way of example, but not of limitation, alternative configurations of the present invention may be utilized in accordance with the teachings herein. Accordingly, the present invention is not limited to that precisely as shown and described.

Claims

1. A method for treating petroleum feedstock comprising:

providing a petroleum feedstock comprising naphthenic acids and sulfur;

heating the petroleum feedstock to decompose the naphthenic acids;

pressurizing the petroleum feedstock to minimize a portion of the petroleum feedstock in a vapor phase;

sweeping water vapor and carbon dioxide from the petroleum feedstock into a headspace with a non-oxidizing gas;

removing water vapor and carbon dioxide from the headspace to promote naphthenic acid decomposition;

reacting the sulfur with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides; and

removing the alkali sulfide.

2. The method of claim 1, wherein the petroleum feedstock is heated in a range of about 200° C. to about 425° C.

3. The method of claim 1, wherein the petroleum feedstock is heated in a range of about 300° C. to about 400° C.

4. The method of claim 1, wherein the non-oxidizing gas comprises hydrogen, light hydrocarbon gas, pyrolysis gas, or combinations thereof.

5. The method of claim 1, wherein the alkali metal comprises lithium, sodium, potassium, or combinations thereof.

6. The method of claim 1, wherein the radical capping gas comprises one or more of the following: methane, ethane, propane, butane, pentane, hexane, heptane, octane, ethene, propene, butane, pentene, hexene, heptene, octene, and isomers of the foregoing, natural gas, shale gas, liquid petroleum gas, ammonia, primary, secondary, and tertiary ammines, thiols, mercaptans, and hydrogen sulfide.

7. The method of claim 1, further comprising regenerating the alkali metal from the alkali metal sulfide.

8. The method of claim 7, wherein regenerating the alkali metal from the solids comprises an electrolytic process using an alkali metal ion conductive ceramic membrane.

9. A method for treating petroleum feedstock comprising:

providing a petroleum feedstock comprising naphthenic acids and sulfur;

reacting the naphthenic acid an aqueous solution or slurry containing an oxide or hydroxide of an alkaline earth element while heating to convert the naphthenic acid into alkaline earth naphthenates, thereby generating an alkaline earth naphthenate mixture;

removing water from the alkaline earth naphthenate mixture to generate a dewatered mixture;

reacting the sulfur in the dewatered mixture with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides; and

removing the alkali sulfides.

10. The method of claim 9, wherein the alkaline earth mixture is heated in a range of about 80° C. to about 95° C.

11. The method of claim 9, wherein the dewatered mixture is heated in a range of about 300° C. to about 400° C.

12. The method of claim 9, wherein the alkali metal comprises sodium and the alkaline earth element comprises one or more of calcium, strontium, or barium.

13. The method of claim 9, further comprising regenerating the alkali metal from the alkali metal sulfide.

14. The method of claim 7, wherein regenerating the alkali metal from the solids comprises an electrolytic process using an alkali metal ion conductive ceramic membrane.

15. A method for treating petroleum feedstock comprising:

providing a petroleum feedstock comprising naphthenic acids and sulfur;

reacting the naphthenic acid with an aqueous solution or slurry containing an oxide or hydroxide of an alkaline earth element while heating to convert the naphthenic acid into an alkaline earth naphthenate, thereby generating an alkaline earth naphthenate mixture;

removing water from the alkaline earth naphthenate mixture to generate a dewatered mixture;

heating the dewatered mixture to convert alkaline earth naphthenates into ketones and alkaline earth oxides or alkaline earth carbonates, thereby generating a ketone mixture;

removing alkaline earth oxides or alkaline earth carbonates from the ketone mixture;

reacting the sulfur in the ketone mixture with an alkali metal and a radical capping gas to convert the sulfur into alkali sulfides; and

removing the alkali sulfide.

16. The method of claim 15, wherein the dewatered mixture is heated in a range of about 166° C. to about 312° C.

17. The method of claim 15, wherein heating the dewatered mixture to convert alkaline earth naphthenates into ketones and alkaline earth oxides or alkaline earth carbonates and reacting the sulfur with an alkali metal and a radical capping gas to convert the sulfur into an alkali sulfide is carried out at the same time in a single reaction vessel.

18. The method of claim 17, wherein the alkali metal comprises sodium and the alkaline earth element comprises one or more of calcium, strontium, or barium.

19. The method of claim 15, further comprising regenerating the alkaline earth carbonates with heat to form alkaline earth oxides.

20. The method of claim 15, wherein removing the alkaline earth oxides or alkaline earth carbonates and the alkali sulfide comprises filtration, centrifugation, hydrocyclonic separation, or combinations thereof.