Renewable transportation fuel process with thermal oxidation system

Abstract

To provide a process for treating effluent streams in a renewable transportation fuel production process, so as to reduce the complexity of the process while providing proper treatment of the effluent streams, especially those related to acid gas and sour water.SOLUTION: One or more of the sour water stream and an acid gas stream are treated directly in thermal oxidation section. The process allows the elimination or size reduction of a sour water stripper unit, a waste water treatment plant and a sulfur recovery unit.SELECTED DRAWING: Figure 1

Description

Technical Field

[0001] (Priority Claim) This application claims the benefit of U.S. Provisional Patent Application No. 63 / 060,031, filed Aug. 1, 2020; U.S. Provisional Patent Application No. 63 / 065,639, filed Aug. 14, 2020; and U.S. Provisional Patent Application No. 63 / 155,465, filed Mar. 2, 2021, the entire contents of each of which are incorporated herein by reference.

Background Art

[0002] As the demand for diesel and jet boiling range fuels increases globally, there is growing interest in sources of feedstocks other than crude oil. One such source is what is referred to as “renewable” and “biological” feedstocks. These renewable biological feedstocks include, but are not limited to, vegetable oils such as corn, jatropha, camelina, rapeseed, canola, and soybean oil, algal oil, and animal fats such as tallow and fish oil. A common feature of these sources is that they are composed of glycerides and free fatty acids (FFAs). Both of these classes of compounds contain straight-chain aliphatic carbon chains having 8 to 24 carbon atoms. The aliphatic carbon chains in glycerides or FFAs can be fully saturated or mono-, di-, or poly-unsaturated. The side chains of glycerides and FFAs in biological oils and fats can be converted to diesel or jet fuel using a number of different processes such as hydrodeoxygenation and hydroisomerization processes.

[0003] Fuel processed from renewable biological sources is desirable for a variety of reasons. First, the use of fuel from renewable biological sources reduces the demand for the extraction and use of fossil fuels. This is particularly applicable to transportation fuels such as diesel and jet fuel. In addition to the environmental protection benefits of using fuel from biological sources, there is a market demand for such fuels. For fuel purchasers, the use of fuel from biological sources can promote publicity activities. Also, certain government policies may require or reward the use of fuel from biological sources.

[0004] Current renewable transportation fuel production processes generate various effluent streams that must be treated and disposed of.

[0005] It is desirable to reduce the complexity of the process while providing appropriate treatment of effluent streams, particularly those associated with acid gases and sour water. It is also desirable to reduce the cost of the chemicals used in treating the effluent streams. It is also desirable to reduce the amount of equipment within the complex.

Brief Description of the Drawings

[0006]

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[0007] A renewable transportation fuel production process generates one or more sour water streams. The sour water streams include a cold separator sour water stream from a cold separator in a cold separation and fractionation section, a de-butanizer receiver sour water stream from a de-butanizer in the cold separation and fractionation section, and a stripper receiver sour water stream from a stripper receiver in the cold separation and fractionation section. The sour water streams are sent to a sour water stripper unit. A portion of the sweet water can be returned to the renewable transportation fuel production process or sent to other units within a refining complex, such as a hydrotreating unit water wash section, a crude oil desalter. The remainder is sent to a wastewater treatment plant. The acid gas from the sour water stripper unit is sent to a sulfur recovery unit. The condensed elemental sulfur in the sulfur recovery unit (SRU) is optionally sent through a belt filter to remove a cake composed of sulfur-containing material. The gaseous material from the SRU is sent to a thermal oxidizer and / or discharged into the atmosphere.

[0008] The process also produces one or more acid gas streams in the acid gas treatment section. The acid gas treatment section includes an acid recycle gas amine contactor, an acid LPG debutanizer receiver LPG effluent amine contactor, an acid lean gas sponge absorber gas overhead amine contactor, and a common amine regenerator. The amine regenerator overhead condenser and reflux drum offgas are sent to a sulfur recovery unit, a belter filter, and a thermal oxidizer.

[0009] In the acid gas treatment section, the lean amine stream contacts (e.g., countercurrently) the acid recycle gas stream from the low-temperature separator in the recycle gas amine contactor and the low-temperature separator in the low-temperature separation and fractionation section. The lean amine stream contacts the acid LPG stream from the debutanizer receiver vessel in the low-temperature separation and fractionation section in the debutanizer receiver amine contactor. The lean amine stream contacts the lean acid gas stream from the sponge absorber in the low-temperature separation and fractionation section in the sponge absorber lean gas overhead amine contactor. The acid gas stream contains CO2 and H2S, which are transferred to the lean amine stream and converted to a rich amine stream. The absorbed CO2 and H2S are removed from the rich amine stream by steam stripping in the common amine regenerator to form a lean amine stream and a regenerator overhead stream. The regenerator overhead stream is sent to the amine regenerator overhead condenser and reflux drum and separated into a liquid reflux and an amine acid gas stream. The liquid reflux is returned to the common amine regenerator. The acid gas containing CO2 and H2S is sent to a sulfur recovery unit.

[0010] One aspect of the present invention is a process for treating an acid gas and a sour water effluent stream in a process for producing a renewable transportation fuel. In one embodiment, the process thermally oxidizes at least one of a sour water stream from the low-temperature separation and fractionation section of the renewable transportation fuel process and an amine acid gas stream from the acid gas treatment section of the renewable transportation fuel process in a thermal oxidation system.That is, the sour water stream is not treated in the sour water stripper unit before being thermally oxidized in the thermal oxidation system, the amine acid gas stream is not treated in the sulfur recovery unit before being thermally oxidized in the thermal oxidation system, and thermally oxidizing at least one of the sour water stream and the amine acid gas stream in the thermal oxidation section to form a flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, SOx, NOx, HCl, Cl2, dioxin, and furan; and optionally recovering waste heat from the flue gas stream in the waste heat recovery section; and removing at least one of SOx, HCl, and Cl2 from the flue gas stream in the SOx removal section to form a desulfurized outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxin, and furan, wherein removing at least one of SOx, HCl, and Cl2 from the flue gas stream comprises quenching the flue gas stream in the quench section to form a quenched flue gas stream, and contacting the quenched flue gas stream with a caustic solution or an NH3-based solution in the scrubbing section to form a desulfurized outlet flue gas stream and a liquid stream containing at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl, or reacting the flue gas stream with a reactant containing at least one of NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2, and Mg(OH)2 in the SOx reaction section to form a reaction section flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, Mg(NO3)2, Cl2, NOx, dioxin, and furan, and in the filtration section,Filtering the reaction section flue gas stream to remove NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, and Mg(NO3)2 to form a desulfurized flue gas stream, including forming a desulfurized flue gas stream, and optionally, in the NOx removal section, removing NOx from the desulfurized flue gas stream to form a denitrified flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, dioxins, and furans; and optionally, in the dioxin-furan removal section, removing dioxins, furans, or both from the desulfurized flue gas stream or the denitrified flue gas stream to form a treated flue gas stream consisting essentially of at least one of H2O, CO2, N2, and O2, including thermal oxidation. Thermal oxidation of a particular stream means that the hydrocarbon components in the stream that are thermally oxidizable are thermally oxidized. For example, with a sour water stream, the hydrocarbon components, sulfur, and nitrogen components in the sour water stream are thermally oxidized, and water is evaporated.,

[0011] In some embodiments, the sour water stream includes at least one of a cold separator sour water stream from a cold separator in a cold separation and fractionation section, a debutanizer receiver sour water stream from a debutanizer in the cold separation and fractionation section, and a stripper receiver sour water stream from a stripper receiver in the cold separation and fractionation section.

[0012] In some embodiments, the amine acid gas stream includes a regenerator amine acid gas stream from a common amine regenerator overhead condenser and reflux drum.

[0013] In some embodiments, the process is carried out in a recycle gas amine contactor, the li Contacting a first portion of the lean amine stream with an acidic recycle gas stream from a cold separator in a cold separation and fractionation section to form a first portion of the rich amine stream, and in a debutanizer receiver amine contactor, contacting a first portion of the lean amine stream with an acidic liquefied petroleum gas (LPG) stream from a debutanizer receiver vessel in the cold separation and fractionation section to form a second portion of the rich amine stream, and at least one of contacting a third portion of the lean amine stream with a lean acidic gas stream from a sponge absorber in the cold separation and fractionation section in a sponge absorber lean gas overhead amine contactor to form a third portion of the rich amine stream; regenerating at least one of the first, second, and third portions of the rich amine stream in a common amine regenerator to form a lean amine stream and an overhead regenerator amine acid gas stream; separating the overhead amine acid gas stream into a regenerator amine acid gas stream and a reflux liquid stream in an amine regenerator overhead condenser; and refluxing the reflux liquid stream to the common amine regenerator. And performing at least one of: forming a second portion of the rich amine stream; and forming a third portion of the rich amine stream by contacting a third portion of the lean amine stream with a lean acidic gas stream from a sponge absorber in the cold separation and fractionation section in a sponge absorber lean gas overhead amine contactor; regenerating at least one of the first, second, and third portions of the rich amine stream in a common amine regenerator to form a lean amine stream and an overhead regenerator amine acid gas stream; separating the overhead amine acid gas stream into a regenerator amine acid gas stream and a reflux liquid stream in an amine regenerator overhead condenser; and refluxing the reflux liquid stream to the common amine regenerator.

[0014] In some embodiments, the process separates, in a pressure swing adsorption unit, a purge stream from an acid recycle gas stream from a cryogenic separator in a cryogenic separation and fractionation section into a recycle hydrogen stream and a PSA tail gas stream, combines the recycle hydrogen stream with the acid recycle gas stream, and introduces the PSA tail gas stream as fuel into a thermal oxidation system, and in the cryogenic separation and fractionation section in a debutanizer receiver amine contactor, contacts a second portion of the lean amine stream with an acid liquefied petroleum gas (LPG) stream to form a second portion of the rich amine stream, and in the cryogenic separation and fractionation section in a sponge absorber lean gas overhead amine contactor, contacts a third portion of the lean amine stream with a lean acid gas stream from the sponge absorber to form a third portion of the rich amine stream, and in a common amine regenerator, regenerates at least one of the second and third portions of the rich amine stream to form a lean amine stream and an overhead regenerator amine acid gas stream, and in an amine regenerator overhead condenser, separates the overhead amine acid gas stream into a regenerator amine acid gas stream and a reflux liquid stream, and refluxes the reflux liquid stream to the common amine regenerator.

[0015] In some embodiments, the process further includes preheating the sour water stream using steam from a process for producing renewable transportation fuel or heat recovered from a waste heat recovery section prior to thermally oxidizing the sour water stream.

[0016] In some embodiments, the process further includes introducing a renewable feedstock to a guard bed to remove contaminants including one or more of an alkali metal, an oxygen compound, a sulfur compound, and a nitrogen compound from the renewable feedstock; treating the renewable feedstock to remove additional oxygen compounds from the renewable feedstock; contacting the renewable feedstock with a hydroisomerization catalyst, a hydrocracking catalyst, or both in the presence of hydrogen under hydroisomerization and hydrocracking conditions in a hydroisomerization and hydrocracking section to form a reaction effluent; and separating and fractionating the reaction effluent in a cryogenic separation and fractionation section to form at least one renewable transportation fuel.

[0017] In some embodiments, separating and fractionating the reaction effluent includes separating the reactor effluent into a liquid hydrocarbon stream, a cryogenic separator recycle acid gas stream, and a cryogenic separator sour water stream in a cryogenic separator; stripping the liquid hydrocarbon stream into a stripper overhead stream and a stripper bottoms stream; separating the stripper overhead stream into a stripper receiver liquid stream, a stripper receiver offgas stream, and a stripper receiver sour water stream in a stripper receiver; contacting the stripper receiver offgas stream with a sponge absorber to form a sponge absorber liquid stream and a lean acid gas stream; separating the stripper receiver liquid stream and optionally the sponge absorber liquid stream into a debutanizer overhead stream and a debutanizer bottoms stream in a debutanizer column; separating the debutanizer overhead stream into an acidic liquefied petroleum gas (LPG) stream, a debutanizer receiver sour water stream, and reflux in a debutanizer receiver; and fractionating the stripper bottoms stream into at least one of a renewable jet fuel stream, a renewable diesel fuel stream, and a naphtha stream.

[0018] In some embodiments, the sour water stream includes at least one of a cold separator sour water stream, a stripper receiver sour water stream, and a debutanizer receiver sour water stream.

[0019] In some embodiments, the process includes at least one of: in a recycle gas amine contactor, contacting a first portion of the lean amine stream with a cold separator acid recycle gas stream to form a first portion of the rich amine stream; in a debutanizer receiver amine contactor, contacting a second portion of the lean amine stream with an acid LPG stream from the debutanizer receiver to form a second portion of the rich amine stream; and in a sponge absorber overhead amine contactor, contacting a third portion of the lean amine stream with a lean acid gas stream from the sponge absorber to form a third portion of the rich amine stream; regenerating at least one of the first, second, and third portions of the rich amine stream in a common amine regenerator to form a lean amine stream and an overhead amine acid gas stream; separating the overhead amine acid gas stream into an amine acid gas stream and a reflux liquid stream in an amine regenerator overhead condenser; and refluxing the reflux liquid stream to the common amine regenerator.

[0020] In some embodiments, quenching the flue gas stream includes quenching the flue gas stream with at least one of air, a quenched flue gas stream, a post-SOx exit flue gas stream, a post-NOx exit flue gas stream, a treated exit flue gas stream, and water.

[0021] In some embodiments, the process further includes introducing an uncompressed pressure swing adsorption (PSA) tail gas stream as a fuel source into a thermal oxidation system from a PSA unit connected to a hydrogen production plant. adsorption, PSA) ​

[0022] In some embodiments, the process further includes introducing a slip stream of the lean acid gas stream as a fuel source from the sponge absorber to the thermal oxidation system.

[0023] Another aspect of the present invention is a process for treating an acid gas and a sour water effluent stream in a process for producing a renewable transportation fuel. In one embodiment, the process includes introducing a renewable feedstock to a guard bed to remove contaminants including one or more of an alkali metal, an oxygen compound, a sulfur compound, and a nitrogen compound from the renewable feedstock, treating the renewable feedstock to remove additional oxygen compounds from the renewable feedstock, hydroisomerizing and hydrocracking the renewable feedstock to form a reactor effluent, separating the reactor effluent in a cryogenic separator into a liquid hydrocarbon stream, a cryogenic separator recycle acid gas stream, and a cryogenic separator sour water stream, and the liquid hydrocarbon stream stripping the mu into a stripper top stream and a stripper bottom stream, separating, in a stripper receiver, the stripper top stream into a stripper receiver liquid stream, a stripper receiver offgas stream, and a stripper receiver sour water stream, contacting the stripper receiver offgas stream with a sponge absorber to form a sponge absorber liquid stream and a lean acid gas stream, separating, in a debutanizer column, the stripper receiver liquid stream and optionally the sponge absorber liquid stream into a debutanizer top stream and a debutanizer bottom stream, separating, in a debutanizer receiver, the debutanizer top stream into an acidic liquefied petroleum gas (LPG) stream, a debutanizer receiver sour water stream, and reflux, fractionating the stripper bottom stream into at least one of a renewable jet fuel stream, a renewable diesel fuel stream, and a naphtha stream, performing at least one of contacting a first portion of a lean amine stream with a cryogenic separator acidic recycle gas stream to form a first portion of a rich amine stream, contacting a second portion of the lean amine stream with an acidic LPG stream from the debutanizer receiver in a debutanizer receiver amine contactor to form a second portion of the rich amine stream, and contacting a third portion of the lean amine stream with a lean acid gas stream from the sponge absorber in a sponge absorber top amine contactor to form a third portion of the rich amine stream, regenerating at least one of the first, second, and third portions of the rich amine stream in a common amine regenerator to form a lean amine stream and a top amine acidic gas stream, refluxing a reflux liquid stream to the common amine regenerator, separating, in an amine regenerator top condenser, the top amine acidic gas stream into an amine acidic gas stream and a reflux liquid stream, and in a thermal oxidation system, a sour water stream from a cryogenic separation and fractionation sectionand thermally oxidizing at least one of the sour water stream and the amine acid gas stream, wherein the sour water stream is not treated in a sour water stripper unit before being thermally oxidized in the thermal oxidation system, the amine acid gas stream is not treated in a sulfur recovery unit before being thermally oxidized in the thermal oxidation system, the sour water stream includes at least one of a cold separator sour water stream from a cold separator in a cold separation and fractionation section, a debutanizer receiver sour water stream from a debutanizer in the cold separation and fractionation section, and a stripper receiver sour water stream from a stripper receiver in the cold separation and fractionation section, and thermally oxidizing at least one of the sour water stream and the amine acid gas stream is to thermally oxidize at least one of the sour water stream and the amine acid gas stream in a thermal oxidation section to form a flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, SOx, NOx, HCl, Cl2, dioxin, and furan, and optionally recovering waste heat from the flue gas stream in a waste heat recovery section, and removing at least one of SOx, HCl, and Cl2 from the flue gas stream in a SOx removal section to form a desulfurized outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxin, and furan, wherein removing at least one of SOx, HCl, and Cl2 from the flue gas stream is to quench the flue gas stream in a quench section to form a quenched flue gas stream, and in a scrubbing section, contacting the quenched flue gas stream with a caustic solution or an NH3-based solution to form a desulfurized outlet flue gas stream and a liquid stream containing at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl, or in a SOx reaction section, contacting the flue gas stream with NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2,react with a reactant containing at least one of Mg(OH)2 to produce H2O, CO2, N2, O2, NaCl, Na2CO3, N, forming a reaction section flue gas stream consisting essentially of at least one of a2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, Mg(NO3)2, Cl2, NOx, dioxins, and furans, and in a filtration section, filtering the reaction section flue gas stream to remove NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, and Mg(NO3)2 to form a desulfurized outlet flue gas stream, including forming a desulfurized outlet flue gas stream, and optionally, in a NOx removal section, removing NOx from the desulfurized outlet flue gas stream to form a denitrified outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, dioxins, and furans, and optionally, in a dioxin-furan removal section, removing dioxins, furans, or both from the desulfurized outlet flue gas stream or the denitrified outlet flue gas stream to form a treated outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, and O2, including thermal oxidizing.

[0024] In some embodiments, the process further includes preheating the sour water stream using steam from a process for producing renewable transportation fuels or heat recovered from a waste heat recovery section before thermal oxidizing the sour water stream.

[0025] In some embodiments, quenching the flue gas stream includes quenching the flue gas stream with at least one of air, a quenched flue gas stream, a desulfurized outlet flue gas stream, a denitrified outlet flue gas stream, a treated outlet flue gas stream, and water.

[0026] In some embodiments, the process further includes introducing an uncompressed pressure swing adsorption (PSA) tail gas stream from a PSA unit connected to a hydrogen production plant as a fuel source into a thermal oxidation system.

[0027] In some embodiments, the process further includes introducing a slip stream of a lean acid gas stream from a sponge absorber as a fuel source into a thermal oxidation system.

[0028] Figure 1 illustrates an overview of one embodiment of a conventional process 100 for treating gas and sour water effluent streams in a process for producing renewable transportation fuels. As will be understood by those skilled in the art, other arrangements are possible and not all components of the apparatus are presented in every process. Renewable feedstock 105 and optionally petroleum feedstock 110 are introduced into a single-stage or two-stage renewable transportation fuel production unit 115 for producing renewable transportation fuels.

[0029] Figure 2 provides details of one embodiment of the conventional renewable transportation fuel production unit 115 of Figure 1. As will be understood by those skilled in the art, other arrangements are possible and not all components of the apparatus are presented in every process. As is known in the art, the renewable transportation fuel production process can be a single-stage or two-stage process.

[0030] Renewable feedstocks 105 include, but are not limited to, glycerides, fatty acid alkyl esters (FAAE), and free fatty acids (FFA). Most glycerides are triglycerides, but monoglycerides and diglycerides can be present and can be treated similarly. Examples of renewable feedstocks include canola oil, corn oil, soybean oil, rapeseed oil, soybean oil, rapeseed oil, tall oil, sunflower oil, etc. Oil, sesame oil, olive oil, linseed oil, coconut oil, castor oil, peanut oil, palm oil, mustard oil, cottonseed oil, jatropha oil, ratanjoy oil, wild castor oil, jangli oil, erandi oil, mohuwa oil, karanji honge oil, neem oil, non-edible animal fats, yellow and brown greases, lard, whale oil, fats in milk, fish oil, algal oil, sewage sludge, kufear oil, camelina oil, curcas oil, babassu oil, palm kernel oil, hamanasu oil, fatty acid methyl esters, lard, etc., or any oil derived from natural sources or produced by microbial activity, but not limited thereto. Typical vegetable oils or glycerides of animal fats, FAAE, and FFA contain, within their structures, aliphatic hydrocarbon chains having 8 to 24 carbon atoms, and most fats and oils contain high concentrations of fatty acids having 16 and 18 carbon atoms.

[0031] In some cases, the renewable feedstock 105 can be nitrogen-rich, which means having nitrogen in excess of 100 ppm, or in some embodiments, in excess of 60 ppm.

[0032] Renewable feedstocks can contain various impurities. For example, tall oil contains esters and rosin acids in addition to FFA. Rosin acids are cyclic carboxylic acids. Renewable feedstocks can also contain contaminants such as alkali metals (e.g., sodium and potassium), alkaline earth metals (e.g., calcium and magnesium), phosphorus, proteins, nitrogen, and sulfur, as well as solids, water, and detergents. It is desirable to remove as many of these contaminants as possible.

[0033] The renewable feedstock 105 and optionally the virgin petroleum feedstock 110 can be sent to the surge drum 125. To remove contaminants, from the surge drum 125, the renewable feedstock 130 can be combined with the recycle hydrogen stream 135 and sent to one or more guard beds 140 and / or treatment units 145. If both a guard bed 140 and a treatment unit 145 are present, the effluent 142 from the guard bed 140 is sent to the treatment unit 145.

[0034] The use of a guard bed 140 for removing metal contaminants from renewable feedstock 130 is well known in the art. These can include alumina guard beds with or without a demetallization catalyst such as nickel or cobalt. Filtration and solvent extraction techniques are other options that can be employed.

[0035] Possible processing units 145 include, but are not limited to, those for the deoxygenation of triglyceride molecules, the saturation of olefins, the removal of nitrogen, the removal of sulfur, the removal of metals, and the removal of halides. The deoxygenation of triglyceride molecules involves decarboxylation and / or decarbonylation and / or hydrodeoxygenation to remove oxygen from the renewable feedstock. The saturation of olefins involves the saturation of olefins or unsaturated moieties within the hydrocarbon chain by hydrogen. The saturation of olefins is an exothermic reaction and consumes hydrogen. The amount of olefins varies depending on the source of the feedstock. The removal of nitrogen involves the conversion of organic nitrogen in the feedstock (such as from trace amino acids) to ammonia. Since nitrogen is harmful to the isomerization catalyst, the nitrogen content of the effluent from processing unit 145 must be less than 50 ppb. The removal of sulfur involves converting natural sulfur in the feedstock to H2S. Since the active state of the catalyst is in a sulfided form, additional sulfur (typically dimethyl disulfide (DMDS)) is added to the feed that is also converted to H2S. Next, H2S prevents the oxidation and reduction of the active guard and processing catalyst metals exposed to H2O and H2 in the hydrotreating environment. With regard to the removal of metals, phosphorus and other metals are retained by the catalyst through a combination of adsorption and chemical reactions. The catalyst has a specific maximum allowable capacity for retaining metals. The useful life of the guard and processing catalyst is largely determined by the amount of metals accumulated during operation. Metals (Na, Ca, K, Mg, Al, and Fe) are derived from the renewable feedstock, occur naturally, and are associated with phospholipid compounds present in the feed of the renewable feedstock. Silicon can be a contaminant from the processing of the feed oil, while iron can also be removed from the processing and storage of acidic feeds. determined. Metals (Na, Ca, K, Mg, Al, and Fe) are derived from the renewable feedstock, occur naturally, and are associated with phospholipid compounds present in the feed of the renewable feedstock. Silicon can be a contaminant from the processing of the feed oil, while iron can also be removed from the processing and storage of acidic feeds.

[0036] The guard bed 140 and the processing unit 145 can be separate containers or can be two or more beds within a single container.

[0037] In a single-stage process, the treated stream 150 is sent to the hydroisomerization and hydrocracking reaction section 155. The recycle hydrogen stream 135 is also introduced into the hydroisomerization and hydrocracking reaction section 155. The effluent stream 160 from the hydroisomerization and hydrocracking reaction section 155 is cooled by removing thermal energy in the steam generator 185. The cooled stream 190 is sent to the separation section 165. The separation section 165 includes an isomerization / cracking effluent separator. The effluent stream 200 from the separation section 165 is sent to the cryogenic separation and fractionation section 205.

[0038] In a two-stage process, the treated stream 150' is cooled by removing thermal energy in the steam generator 170. The cooled stream 175 is sent to the extended high-temperature separator of the separation section 165 following the high-temperature separator. The separation section 165 also includes an isomerization / cracking effluent separator. The liquid stream 180 from the extended high-temperature separator of the separation section 165 is sent to the hydroisomerization and hydrocracking reaction section 155. The effluent stream 160' is sent to the isomerization / cracking effluent separator within the separation section 165. The liquid from the isomerization / cracking effluent separator is sent to the high-temperature separator, and the gaseous effluent is sent to the extended high-temperature separator. The steam streams from the high-temperature separator and the extended high-temperature separator form an effluent stream 200' from the separation section 165 and are sent to the cryogenic separation and fractionation section 205.

[0039] The hydrogen isomerization and hydrocracking reaction section 155 may comprise one or more reactors, each of which may include one or more beds containing at least one hydrogen isomerization catalyst, at least one hydrocracking catalyst, or both. Some embodiments may require external heat input. It is contemplated that all reactions may occur simultaneously in one reactor or one bed. However, typical operation is most likely to utilize multiple beds and, if possible, multiple reactors, with different reactions occurring in different beds and / or reactors.

[0040] The hydrogen isomerization and selective hydrocracking of paraffin products can be achieved in any manner known in the art or by using any suitable catalyst known in the art. One or more beds of catalyst may be used. The isomerization is preferably operated in a co-current mode of operation. Both a fixed-bed trickle-bed downflow mode or a fixed-bed liquid-filled upflow mode are suitable.

[0041] The major isomerization products are generally monobranched hydrocarbons. Along with isomerization, hydrocracking of the hydrocarbons occurs. As the conditions in the hydrogen isomerization and hydrocracking reaction section 155 become more severe, the amount of hydrocracking of the hydrocarbons increases. The increase in the hydrocracking level results in a higher yield of hydrocarbons in the boiling range of aviation fuels.

[0042] The hydrogen isomerization and hydrocracking of paraffin hydrocarbons in the hydrogen isomerization and hydrocracking reaction section 155 can be achieved in any manner known in the art or by using any suitable catalyst known in the art. Suitable catalysts include metals of Group VIII (8 - 10 of the IUPAC) of the periodic table and a support material. Suitable V Group III metals include platinum and palladium, each of which can be used alone or in combination. The support material can be amorphous or crystalline. Suitable support materials include alumina, amorphous alumina, amorphous silica-alumina, and the like. The isomerization catalyst may also include a modifier selected from the group consisting of lanthanum, cerium, praseodymium, neodymium, samarium, gadolinium, terbium, and mixtures thereof.

[0043] Generally, the isomerization conditions in the hydroisomerization and hydrocracking section 155 are from 150 °C to 450 °C (302 °F to 842 °F), or from 300 °C to 400 °C (572 °F to 752 °F), or from 300 °C to 360 °C (including 572 °F to 680 °F). A typical isomerization pressure can be from 2760 to 6890 kPa (400 to 1000 psig), or in some embodiments, from 2760 to 4820 kPa (400 to 700 psig). Other operating conditions of the isomerization zone are well known in the art, and the specific operating conditions used are predetermined and depend on the desired product specifications and the relative yields of the products.

[0044] The tightness of the process in the hydroisomerization and hydrocracking section 155 controls the potential yield of the aviation fuel product, the amount of light products not useful for diesel fuel or aviation fuel, and the isomerization / normality ratio of fuels in both the aviation and diesel ranges. Hydrocracking is controlled through catalyst selection and reaction conditions to limit the degree of hydrocracking. Ideally, each paraffin molecule undergoes only a single hydrocracking event, and ideally, a single hydrocracking event results in at least one paraffin in the carbon number range of C9 to C 15 The careful selection of the catalyst and the control of the process conditions in the hydroisomerization and hydrocracking reaction section 155 can maximize the paraffin product in the aviation fuel range while minimizing the production of light paraffins, i.e., paraffins having three or fewer carbon chains that are not useful for diesel fuel or aviation fuel applications.

[0045] Note that the fuel specifications typically do not depend on the carbon number range. Instead, the specifications for different types of fuels are often shown through the acceptable ranges of the chemical and physical requirements of the fuel. For example, often the distillation range from 10% recovery to the final boiling point is used as a major parameter to define different types of fuels. The distillation range is typically measured by ASTM test methods D86 or D2887. To meet different specifications and requirements, it is very common to blend different components.

[0046] The effluent stream 200 / 200' is sent to the cryogenic separation and fractionation section 205. In the cryogenic separation and fractionation section 205, the effluent stream 200 / 200' is separated into an acidic recycle gas stream 210, an acidic liquefied petroleum gas (LPG) stream 215, a lean acidic gas stream 220, a sour water stream 225, a naphtha stream 230, a renewable jet fuel stream 235, and a renewable diesel stream 240. The cryogenic separation and fractionation section 205 will be described in more detail below.

[0047] The acidic recycle gas stream 210 containing hydrogen, carbon monoxide, hydrogen sulfide, carbon dioxide, and propane is sent to the recycle gas amine contactor 245 to remove carbon monoxide, hydrogen sulfide, and some carbon dioxide and propane. The recycle hydrogen stream 135 can be combined with the renewable feedstock 130 and sent to the processing unit 145 or to the hydroisomerization and hydrocracking reaction section 155.

[0048] Figure 3 illustrates one embodiment of the cryogenic separation and fractionation section 205. As will be understood by those skilled in the art, other arrangements are possible and not all parts of the apparatus are presented in every process. In the cryogenic separation and fractionation section 205, an effluent stream 200 / 200' containing one or more combinations of the vapor from the high-temperature separator, the vapor from the expanded high-temperature separator, and the liquid from the isomerization / decomposition effluent separator is sent to the cryogenic separation and fractionation sect It is sent to the condenser 440 of the fractionator 205. The condensed stream 445 is sent to the cryogenic separator 450, where it is separated into a liquid hydrocarbon stream 455, a cryogenic separator sour water stream 460, and an acid recycle gas stream 210. The details of the high-temperature separation section 165 and the cryogenic separation and fractionation section 205 are well known to those skilled in the art.

[0049] The liquid hydrocarbon stream 455 from the cryogenic separator 450 is sent to the steam stripper 465. The acid recycle gas stream 210 is sent to the recycle gas amine contactor 245 to remove CO2 and H2S.

[0050] The liquid hydrocarbon stream 455 is separated in the steam stripper 465 into a stripper overhead stream 470 and a stripper bottoms stream 475. The stripper overhead stream 470 is sent to the stripper receiver 480, where it is separated into a stripper receiver liquid stream 485, a stripper receiver offgas stream 490, and a stripper receiver sour water stream 495.

[0051] The stripper receiver offgas stream 490 contacts the sponge absorber 500 to form a sponge absorber liquid stream 505 and a lean acid gas stream 220.

[0052] The stripper receiver liquid stream 485 and optionally the sponge absorber liquid stream 505 are sent to the debutanizer column 510, where they are separated into a debutanizer overhead stream 515 and a debutanizer bottoms stream 520. The debutanizer bottoms stream 520 containing naphtha can be combined with the naphtha stream 230.

[0053] The debutanizer top stream 515 is separated in the debutanizer receiver 525 into an acidic LPG stream 215, a debutanizer receiver sour water stream 530, and a reflux 535. The acidic LPG stream 215 is sent to the debutanizer receiver amine contactor 320. The reflux 535 is returned to the debutanizer column 510.

[0054] The stripper bottom stream 475 is sent to a splitter 477 and split into a naphtha stream 230 and at least one of a renewable jet fuel stream 235 and a renewable diesel stream 240.

[0055] One or more of the cold separator sour water stream 460 from the cold separator 450, the debutanizer receiver sour water stream 530 from the debutanizer receiver 525, and the stripper receiver sour water stream 495 from the stripper receiver 480 can come together in the sour water stream 225 sent to the sour water stripper (SWS) unit 250. The stream 225 can come together in the sour water stream 225 sent to the sour water stripper (SWS) unit 250.

[0056] Returning to FIG. 1, the sour water stream 225 is sent to the SWS unit 250 and separated using steam into an SWS acid gas stream 255 and an SWS bottom stream 260. The SWS bottom stream can be sent to a wastewater treatment plant 265. A portion 270 of the SWS bottom stream 260 can be returned to the renewable transportation fuel production unit 115 or sent to other units within the refinery complex.

[0057] The SWS acid gas stream 255 is sent to a sulfur recovery unit (SRU) 275. Suitable SRUs are known in the art and include, but are not limited to, the Claus process and liquid redox sulfur units or biological processes. The removed sulfur is sent to a filtration section 280 where the sulfur is removed as a sulfur filter cake 282. The gas stream 285 from the SRU 275 is sent to a thermal oxidation section 290. The flue gas 292 is discharged into the atmosphere.

[0058] The acid recycle gas stream 210 contacts a first portion 295 of the lean amine stream 300 in the recycle gas amine contactor 245 to form a first portion 305 of a rich amine stream 310 containing hydrogen sulfide removed from the acid recycle gas stream 210. The recycle hydrogen stream 135 is returned to the renewable transportation fuel production unit 115 as discussed above with respect to FIG. 2.

[0059] The acid LPG stream 215 contacts a second portion 315 of the lean amine stream 300 in the debutanizer receiver amine contactor 320 to form a second portion 325 of a rich amine stream 310 containing hydrogen sulfide from the acid LPG stream 215. The sweet LPG 330 can be sent to a storage facility or used as a feedstock for a hydrogen reformer.

[0060] The lean acid gas stream 220 contacts a third portion 335 of the lean amine stream 300 in the sponge absorber gas overhead amine contactor 345 to form a third portion 350 of a rich amine stream 310 containing hydrogen sulfide from the lean acid gas stream 220. The sweet lean gas 355 can be sent to a fuel gas network.

[0061] The rich amine stream 310 is sent to a heat exchanger 360 to exchange heat with the lean amine stream 300. The rich amine stream 310 is sent to a common amine regenerator 365 and steam stripped to form the lean amine stream 300 and the overhead amine acid gas stream 370. The overhead amine acid gas stream 370 is sent to an amine regenerator overhead condenser 375 and separated into a liquid reflux 380 and an amine acid gas stream 385. The liquid reflux 380 is returned to the common amine regenerator 365. The amine acid gas stream 385 is sent to the SRU 275.

[0062] In some embodiments, a related steam reforming zone 390 can be present. The sweet naphtha stream 395 and / or the sweet LPG stream 400 are sent to the steam reforming zone 390. Other fuels are possible, including but not limited to natural gas, methane, methanol, etc. The reforming zone effluent 405 (e.g., containing mainly hydrogen, as well as small amounts of CH4, CO, and N2 in addition to CO2 and being saturated with water) is sent to a pressure swing adsorption (PSA) unit 410 and separated into a hydrogen stream 415 and a PSA tail gas stream 420. The hydrogen stream 415 can be compressed and sent to the renewable transport fuel production unit 115. The PSA tail gas stream can be split into a PSA tail gas recycle stream 425 sent to the steam reforming zone 390 and an excess PSA tail gas stream 430 that can be sent to the fuel gas network.

[0063] In the process 550 shown in FIG. 4A, the sour water stripper unit, the wastewater treatment plant, and the sulfur recovery unit are eliminated. The sour water stream 225 is sent directly to the thermal oxidation system 555 without being treated in a sour water stripper unit, and there is no SWS acid gas stream. Alternatively, in some arrangements, only the sulfur recovery unit is eliminated. In this case, the SWS acid gas stream 255 is sent directly to a thermal oxidation system (not shown). The amine acid gas stream 385 is sent directly to the thermal oxidation system 555 without the need to be treated in a sulfur recovery unit. The flue gas 557 is discharged into the atmosphere.

[0064] In some embodiments, as described below, the sour water stream 225 is preheated using steam from the renewable transport fuel production unit 115 or waste heat recovered from the thermal oxidation system 555.

[0065] In some embodiments, the fuel gas stream 560 is sent to a steam reforming zone 390 for fuel. The uncompressed surplus PSA tail gas stream 430 is sent as fuel to a thermal oxidation system 555.

[0066] Optionally, the uncompressed surplus PSA tail gas stream 430 from the PSA unit 410 associated with the hydrogen production plant can be sent to a thermal oxidation system 555 used as a fuel source. The surplus PSA tail gas stream 430 is typically recycled at a pressure of 5 psi(g) to a combustion heater within the hydrogen plant. By sending the surplus PSA tail gas stream 430 to the thermal oxidation system 555 at a lower pressure in the range of 2 - 4.9 psi(g), the hydrogen recovery rate in the PSA unit 410 can be increased.

[0067] The fuel requirements for the reformer combustion heater are provided by the fuel gas stream 560 from the LP fuel gas network.

[0068] Figure 4B shows an alternative embodiment. In this process, there is no recycle gas amine contactor 245 and, as a result, no first portion 295 of the lean amine stream 300 and no first portion 305 of the rich amine stream 310. The acidic recycle gas stream 210 is compressed and the recycle hydrogen stream 135 is returned to the process. The purge stream 211 is sent to a PSA unit 212 and separated into a hydrogen stream 213 and a PSA tail gas stream 214. The hydrogen stream is combined with the remainder of the acidic recycle gas stream 210. The PSA tail gas stream is sent to a thermal oxidation system 555.

[0069] In process 565 of FIG. 5, a slip stream 570 of the lean acid gas stream 220 from the sponge absorber 500 is sent to the thermal oxidation system 555 as a fuel source for the thermal oxidation system 555. In this arrangement, the size of the sponge absorber gas overhead amine contactor 345 is reduced. As a result, the size of the common amine regenerator 365 can also be reduced. In an alternative embodiment, the recycle gas amine contactor 245 can be removed, and there may be the PSA unit 212 and attendant modifications described in FIG. 4B.

[0070] One embodiment of the thermal oxidation system 555 is illustrated in FIG. 6. The thermal oxidation system 555 includes a thermal oxidation section 600, an optional waste heat recovery section 605, a quench section 610, a SOx removal section 615, an optional NOx removal 462, and an optional dioxin-furan removal section 625.

[0071] At least one of the sour water stream 225 and the amine acid gas stream 385 is sent to the thermal oxidation section 600 together with the combustion air stream 630, the natural gas / fuel gas stream 635, and optionally the quench air stream 640. Optionally, the excess PSA tail gas stream 430 and / or the lean acid gas slip stream 570 can also be sent to the thermal oxidation section 600. The inlet temperature of the thermal oxidation section 600 is typically in the range of -30 to 500 °C at a pressure of -1 kPa(g) to 3000 kPa(g). The outlet temperature is typically in the range of 650 to 1300 °C at a pressure of -1 kPa(g) to 50 kPa(g). The residence time in the thermal oxidation section 600 is 0.5 to 2 seconds. Any suitable thermal oxidation section 600 can be used, including but not limited to an adiabatic thermal oxidation device chamber. The thermal oxidation section 600 can be forced draft, induced draft, or a combination of both. In some cases, optional selective non-catalytic reduction (SN A CR section may exist. The inlet temperature of the SNCR section is typically in the range of 650 - 1300 °C at a pressure of -1 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 650 - 1040 °C at a pressure of -1 kPa(g) to 50 kPa(g). The residence time in the SNCR section is 0.2 - 1 second. The thermal oxidation step is separated from the SNCR step through the choke wall in the vessel. Hydrocarbons are converted to H2O and CO2. Sulfides (e.g., H2S) from sulfur species present in the raw material are converted to sulfur oxide particulate matter SOx, including but not limited to SO2, SO3, and H2O. Nitrogen from nitrogen-bonded molecules (e.g., NH3) present in the raw material is converted to nitrogen (N2) and NOx, including but not limited to NO and NO2. HCl and Cl2 (if present) remain.

[0072] The flue gas stream 645 from the thermal oxidation section 600 consists essentially of one or more of H2O, CO2, N2, O2, SOx (i.e., SO2 and SO3), NOx (i.e., NO and NO2), HCl, Cl2, dioxins, and furans. "Consists essentially of" means that one or more of the gases or vapors are present and no other gases or vapors that require treatment before being released to the atmosphere are present. The flue gas stream 645 is sent to an optional waste heat recovery section 605. The inlet temperature of the optional waste heat recovery section 605 is typically in the range of 650 - 1300 °C at a pressure of -2 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200 - 400 °C at a pressure of -2 kPa(g) to 50 kPa(g). Suitable waste heat recovery devices and methods include, but are not limited to, waste heat recovery boilers such as fire-tube boilers or water-tube boilers. The boiler feed water or oil stream 650 enters the waste heat recovery section 605, a portion of which is converted to steam or a high-temperature oil stream 655, and the remainder exits as a blowdown water or oil stream 660. In some cases, the steam can be converted to electricity, for example, using a steam turbine as desired.

[0073] The recovered waste heat in the steam or high-temperature oil stream 655 can be in the form of low-pressure (e.g., less than 350 kPa(g)), medium-pressure (e.g., 350 kPa(g) to 1750 kPa(g)), or high-pressure (e.g., greater than 1750 kPa(g)) saturated steam or superheated steam, high-temperature oil, and / or electricity. The recovered heat can be used to provide heat to one or more parts of the apparatus or process stream in the process for producing renewable transportation fuel or to other parts of the plant. For example, the recovered waste heat in the steam or high-temperature oil stream 655 can be used to supply heat to a reboiler within an amine treating unit, to a fractionation column, and to steam for a stripper column or other locations within the plant, or for other heat requirements.

[0074] The flue gas stream 665 from the optional waste heat recovery section 605 flows to the quench section 610, and the temperature of the flue gas is reduced to the saturation temperature using the quench stream 670. The inlet temperature of the quench section 610 is typically in the range of 200 to 400 °C at a pressure of -3 kPa(g) to 50 kPa(g). In the absence of a waste heat reboiler, the inlet temperature can be up to 1300 °C. The outlet temperature is typically in the range of 45 to 150 °C at a pressure of -3 kPa(g) to 50 kPa(g). Examples of the quench stream 670 include, but are not limited to, water, air, recycled flue gas, or combinations thereof.

[0075] The quenched flue gas stream 675 from the quench section 610 is sent to a SOx removal section 615 for removing at least one of SOx, HCl, and Cl2. The inlet temperature of the SOx removal section 615 is typically in the range of 45 to 150 °C at a pressure of -4 kPa(g) to 50 kPa(g). The outlet temperature is typically is in the range of 45 to 150 °C at a pressure of -4 kPa(g) to 50 kPa(g). For example, the SOx removal section 615 can be a scrubbing section where a stream 680 containing aqueous NaOH is introduced into the scrubbing section and reacts with at least one of SOx, HCl, and Cl2 in the flue gas. An aqueous stream 685 containing aqueous Na2SO3, Na2SO4, and NaCl exits the scrubbing section. Optionally, it can contain a reducing agent such as NaHSO3 or H2O2 to react with Cl2 to form HCl, which in turn reacts to form NaCl. Alternatively, the stream 680 can be an NH3-based solution. NH3 reacts with SOx to form (NH4)2SO4. NH3 reacts with Cl2 to form N2 and HCl, and subsequently, HCl reacts with NH3 to form NH4Cl. When NH3 is used, a separate reducing agent is not required. In this case, the aqueous stream 685 contains H2O, NaCl, (NH4)2SO4, and NH4Cl.

[0076] The desulfurized outlet flue gas stream 690 from the SOx removal section 615 has a reduced level of at least one of SOx, NOx, and Cl2 compared to the incoming quenched flue gas stream 675. The desulfurized outlet flue gas stream 690 contains one of H2O, CO2, N2, O2, NOx, dioxin, and furan.

[0077] When NOx is present in the desulfurized flue gas stream 690, the desulfurized flue gas stream 690 is sent to an optional NOx removal section 620 to remove NOx. The inlet temperature of the NOx removal section 620 is typically in the range of 150 - 300 °C at a pressure of -5 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200 - 350 °C at a pressure of -5 kPa(g) to 50 kPa(g). The desulfurized flue gas stream 690 may need to be heated to obtain the desired inlet temperature of the NOx removal section 620. For example, the NOx removal section 620 can be a selective catalytic reduction (SCR) section , and an ammonia and / or urea stream 695 is introduced into the SCR section to react with NOx to form N2 and H2O. Any suitable SCR catalyst can be used, including, but not limited to, ceramic support materials such as titanium oxide having active catalyst components such as base metal oxides including TiO2, WO3, and V2O5, or activated carbon-based catalysts. The denoxed flue gas stream 700 contains at least one of H2O, CO2, N2, O2, dioxin, and furan.

[0078] If any halogen is present in the raw materials, this can lead to the formation of dioxins and / or furans. These compounds must be removed before the gas can be emitted into the atmosphere. If dioxins and / or furans are present in the desulfurized flue gas stream 690 or the denitrified flue gas stream 700, the desulfurized flue gas stream 690 or the denitrified flue gas stream 700 is sent to an optional dioxin-furan removal section 625 for removing dioxins and / or furans. Dioxins and furans can be removed using a catalyst. The inlet temperature of the dioxin-furan removal section 625 is typically in the range of 150 - 250 °C at a pressure of -6 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 150 - 250 °C at a pressure of -6 kPa(g) to 50 kPa(g). The treated flue gas stream 705, which consists essentially of one or more of H2O, CO2, N2, and O2, can be emitted into the atmosphere.

[0079] If the levels of NOx and dioxins and / or furans in the desulfurized flue gas stream 690 exceed environmental regulations, the system will likely include both a NOx removal section 620 and a dioxin-furan removal section 625. In this case, the desulfurized flue gas stream 690 has a slightly higher temperature than the denitrified flue gas stream 700. The denitrified flue gas stream 700 may need to be quenched before entering the dioxin-furan removal section 625.

[0080] If the desulfurized flue gas stream 690 does not contain NOx, dioxins, or furans, the optional NOx removal section 620 and the optional dioxin-furan removal section 625 do not exist. The desulfurized flue gas stream 710, which consists essentially of one or more of H2O, CO2, N2, and O2, can be emitted into the atmosphere.

[0081] When the desulfurized SOx outlet flue gas stream 690 contains NOx but does not contain dioxin or furan, the optional dioxin-furan removal section 625 does not exist. The desulfurized SOx outlet flue gas stream 715, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0082] When the desulfurized SOx outlet flue gas stream 690 contains dioxin or furan but does not contain NOx, the optional NOx removal section 620 does not exist. The desulfurized SOx outlet flue gas stream 690 is sent to the optional dioxin-furan removal section 625. The treated outlet flue gas stream 705, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0083] When the flue gas stream 645 does not contain SOx or NOx, the SOx removal section 615, the optional NOx removal section 620, and the optional dioxin-furan removal section 625 do not exist. The flue gas stream 720 from the waste heat recovery section 605, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0084] Another embodiment of the thermal oxidation system 555' is illustrated in FIG. 7. The thermal oxidation system 555' includes a thermal oxidation section 800, an optional waste heat recovery section 805, a SOx removal section including a reaction section 810 and a filtration section 815, an optional NOx removal section 820, and an optional dioxin-furan removal section 825.

[0085] At least one of the sour water stream 225 and the amine acid gas stream 385 is introduced into the thermal oxidation section 800 as described above. One or more of the combustion air stream 830, the make-up natural gas or fuel gas stream 835, and optionally the quench stream 840 are also introduced into the thermal oxidation section 800. Optionally, the excess PSA tail gas stream 430 from the PSA unit 410 associated with the hydrogen production plant and / or the lean acid gas slip stream 570 can also be introduced into the thermal oxidation section 800.

[0086] The inlet temperature of the thermal oxidation section 800 is typically in the range of -30 to 500 °C at a pressure of -1 kPa(g) to 3000 kPa(g). The outlet temperature is typically in the range of 650 to 1300 °C at a pressure of -1 kPa(g) to 50 kPa(g). The residence time within the thermal oxidation section 800 is 0.5 to 2 seconds. Any suitable thermal oxidation section 800 can be used, including but not limited to an adiabatic thermal oxidation device chamber. The thermal oxidation section 800 can be forced draft, induced draft, or a combination of both. The inlet temperature of an optional SNCR section is typically in the range of 650 to 1300 °C at a pressure of -1 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 650 to 1040 °C at a pressure of -1 kPa(g) to 50 kPa(g). The residence time within the SNCR section is 0.2 to 1 second. The thermal oxidation step is separated from the SNCR step through the choke wall within the vessel.

[0087] The flue gas stream 845 from the thermal oxidation section 800 contains one or more of H2O, CO2, N2, O2, SOx, NOx, HCl, Cl2, dioxins, and furans. The flue gas stream 845 is sent to an optional waste heat recovery section 805. The boiler feed water or oil stream 850 enters the optional waste heat recovery section 805, a portion of which is converted into a steam or high-temperature oil stream 855, and the remainder exits as blowdown water or oil 860. The inlet temperature of the optional waste heat recovery section 805 is typically in the range of 650 to 1300 °C at a pressure of -2 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200 to 400 °C at a pressure of -2 kPa(g) to 50 kPa(g). Suitable waste heat recovery devices and methods are described above. The recovered waste heat in the steam or high-temperature oil stream 855 can be in the form of low-pressure, medium-pressure, or high-pressure saturated steam or superheated steam, high-temperature oil, and / or electricity. The recovered waste heat in the steam or high-temperature oil stream 855 can be used to supply heat to a reboiler within an amine treating unit, to a fractionation column, and to steam for other locations within a stripper column or plant, or for other heat requirements.

[0088] The flue gas stream 865 from an optional waste heat recovery section 805 is sent to a SOx removal section that may include a reaction section 810 and a filtration section 815 to convert at least one of SOx, HCl, and Cl2. The inlet temperature of the reaction section 810 is typically in the range of 200 to 400 °C at a pressure of -3 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200 to 400 °C at a pressure of -3 kPa(g) to 50 kPa(g). A fresh adsorbent 870 and optionally a regenerated adsorbent 875 (including a mixture of one or more of NaCl, Na2CO3, Na2SO4, CaCl2, CaSO4, CaCO3, MgCl2, MgCO3, MgSO4, and MgCO3 depending on the compounds used in the reactants as discussed below) can be added to the flue gas stream 865. For example, the SOx removal section 810 may contain reactants such as NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2, and Mg(OH)2 and react with SOx, NOx, and HCl to form NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, MgCl2, MgCO3, MgSO4, and Mg(NO3)2, dioxins, and furans. The reaction section flue gas stream 880 has less HCl, SOx, and NOx compared to the incoming flue gas stream 865. The reaction section flue gas stream 880 includes one or more of H2O, CO2, N2, O2, NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, Mg(NO3)2, Cl2, NOx, dioxins, and furans.

[0089] The reaction section flue gas stream 880 is combined with a quench stream 885 that includes air and / or water and / or quenched flue gas. The temperature of the reaction section flue gas stream 880 is typically reduced from 200 - 400 °C at a pressure of -4 kPa(g) to 50 kPa(g) to 150 - 250 °C at a pressure of -4 kPa(g) to 50 kPa(g). The quenched reaction section flue gas stream 880 is sent to a filtration section 815 for removing Na2CO3, Na2SO4, and NaCl. The inlet temperature of the filtration section 815 is typically in the range of 150 - 350 °C at a pressure of -5 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 150 - 350 °C at a pressure of -5 kPa(g) to 50 kPa(g). The filtration section 815 is equipped with a bag filter and / or a ceramic filter and / or an electrostatic precipitator (ESP). Instrument air purge or high voltage DC 890 is introduced into the filtration section 815. In the case of the instrument air purge, residual material is purged from the filter. In the case of the high voltage stream, the cathode of the ESP is charged. Particulate matter is removed from the ESP by vibration. A dry residue stream 895 containing one or more of NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, Ca2CO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, and Mg(NO3)2 exits the filtration section 815. The filtered flue gas stream 900 contains one or more of H2O, CO2, N2, O2, NOx, dioxin, and furan.

[0090] If NOx is present in the filtered flue gas stream 900, the filtered flue gas stream 900 is sent to an optional NOx removal section 820 to remove NOx, as discussed above. The inlet temperature of the NOx removal section 820 is typically in the range of 150 to 300 °C at a pressure of -6 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200 to 350 °C at a pressure of -6 kPa(g) to 50 kPa(g). For example, the NOx removal section 820 can be a selective catalytic reduction (SCR) section, and an ammonia and / or urea stream 905 is introduced into the SCR section, where it reacts with NOx to form N2 and H2O. Any suitable SCR catalyst can be used, including, but not limited to, ceramic support materials such as titanium oxide having active catalyst components such as base metal oxides including TiO2, WO3, and V2O5, or activated carbon-based catalysts. The denoxed outlet flue gas stream 910 consists essentially of one or more of H2O, CO2, N2, O2, dioxins, and furans.

[0091] If any halogen is present in the raw materials, this can lead to the formation of dioxins and / or furans. These compounds must be removed before the gas can be discharged into the atmosphere. If dioxins and / or furans are present in the filtered flue gas stream 900 or the de-NOx outlet flue gas stream 910, the filtered flue gas stream 900 or the de-NOx outlet flue gas stream 910 is sent to an optional dioxin-furan removal section 825 for removing dioxins and / or furans. Dioxins and furans can be removed by using a catalyst or by co-injecting activated carbon. For example, dioxins and furans react with the catalyst, such as a catalyst containing TiO2, WO3, and V2O5, to form trace amounts of CO2, H2O, and HCl. In the case of activated carbon, it is co-injected upstream of the SOx removal section 810 together with the dry adsorbent 871. Dioxins and / or furans are adsorbed onto the carbon and removed via the dry residue stream 895. The inlet temperature of the dioxin-furan removal section 825 is typically in the range of 150 to 250 °C at a pressure of -7 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 150 to 250 °C at a pressure of -7 kPa(g) to 50 kPa(g). The treated outlet flue gas stream 915, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0092] If the filtered flue gas stream 900 does not contain NOx, dioxins, or furans, the optional NOx removal section 820 and the optional dioxin-furan removal section 825 do not exist. The filtered flue gas stream 920, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0093] If the filtered flue gas stream 900 contains NOx but does not contain dioxins or furans, the optional dioxin-furan removal section 825 does not exist. The denox exit flue gas stream 925, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0094] If the filtered flue gas stream 900 contains dioxins or furans but does not contain NOx, the optional NOx removal section 820 does not exist. The filtered flue gas stream 900 is sent to the optional dioxin-furan removal section 825. The treated exit flue gas stream 915, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0095] If the flue gas stream 845 does not contain SOx, NOx, dioxins, or furans, the optional reaction section 810, the optional filtration section 815, the optional NOx removal section 820, and the optional dioxin-furan removal section 825 do not exist. The flue gas stream 930 from the waste heat recovery section 805, which consists essentially of one or more of H2O, CO2, N2, and O2, can be discharged into the atmosphere.

[0096] FIG. 8 illustrates an embodiment of the thermal oxidation system 555 of FIG. 6 with improved energy recovery. In this embodiment, energy can be recovered from the exhaust steam stream 1000 by condensing the water in the exhaust steam stream 1000. The condensate stream can be used as process water for other parts of the process, optionally after treatment such as neutralization and / or deaeration and / or filtration.

[0097] The exhaust steam stream 1000 can be sent to an optional secondary heat exchanger 1005. The exhaust steam stream 1000 can be the treated outlet flue gas stream 705, the de-NOx outlet flue gas stream 715, or the de-SOx outlet flue gas stream 710. The exhaust steam stream 1000 is sent to the second side of the secondary heat exchanger 1005.

[0098] The process stream is sent to the first side of the secondary heat exchanger 1005. Depending on the temperature of the exhaust steam stream 1000 and the number of process streams to be heated, one or more secondary heat exchangers 1005 can be provided.

[0099] The process stream can be all or part of the combustion air stream 630 and / or all or part of the boiler feed water or oil stream 650.

[0100] The process stream is heated by heat exchange with the exhaust steam stream 1000, as a result of which the exhaust steam stream 1000 is cooled to form a first cooled exhaust steam stream 1010.

[0101] The heated combustion air stream 630 is sent to the thermal oxidation section 600, while the heated boiler feed water or oil stream 650 is sent to the waste heat recovery section 605, thereby enhancing the steam generation or high-temperature oil production efficiency.

[0102] The first cooled exhaust steam stream 1010 from the secondary heat exchanger 1005 is sent to the primary heat exchanger 1015.

[0103] The sour water stream 225 is passed through the first side of the primary heat exchanger 1015. Depending on the temperature of the exhaust steam stream 1000 or the first cooled exhaust steam stream 1010, one or more primary heat exchangers 1015 can be provided.

[0104] The sour water stream 225 is optionally compressed at a pressure of 0 to 75 psig to 100 to 400 psig in a pump and / or compressor 1020 before being introduced into the primary heat exchanger 1015 to avoid flashing and / or boiling in the primary heat exchanger 1015. It can be compressed.

[0105] The first cooled exhaust steam stream 1010 is sent to the primary heat exchanger 1015 and passed through the second side of the primary heat exchanger 1015. Alternatively, in the absence of the secondary heat exchanger 1005, the exhaust steam stream 1000 is sent directly to the primary heat exchanger 1015.

[0106] The first cooled exhaust steam stream 1010 entering the primary heat exchanger 1015 has a temperature higher than the dew point. The heat exchange with the sour water stream 225 reduces the temperature of the first cooled exhaust steam stream 1010. In some cases, the temperature is reduced to a temperature below the dew point, resulting in the condensation of water from the first cooled exhaust steam stream 1010. The resulting second cooled exhaust steam stream 1025 can be sent to the exhaust stack and discharged into the atmosphere.

[0107] In other cases, the temperature is not reduced sufficiently to condense some, most, or all of the water from the first cooled exhaust steam stream 1010. In this case, an optional tertiary heat exchanger 1030 can be used to reduce the temperature of the second cooled exhaust steam stream 1025 to a temperature below the dew point at which condensate formation occurs. The cooling medium of the tertiary heat exchanger can be, for example, cold air / ambient air or cold water.

[0108] The condensate is recovered and exits the primary heat exchanger 1015 and / or the tertiary heat exchanger as a condensate stream 1035. The condensate stream 1035 can be sent to the quench section 610 as a quench stream 670 or used in other processes.

[0109] The heated sour water stream 1040 from the primary heat exchanger 1015 is passed through a valve 1045 (e.g., a throttle valve or a downcomer valve) to reduce the pressure to a pressure lower than that of the primary heat exchanger 1015 (e.g., a pressure of 1 to 20 psig) and is sent to the flash tank 1050. When the higher pressure heated sour water stream 1040 enters the lower pressure flash tank 1050, it is flashed into a vapor stream 1055 and a liquid stream 1060. The vapor stream 1055 and the liquid stream 1060 are sent to the thermal oxidation section 600 of the thermal oxidation system 555. An optional pump and / or compressor 1065 can be present on the line of the liquid stream 1060.

[0110] FIG. 9 illustrates an alternative energy recovery system for the thermal oxidation system 555 of FIG. 6. In this arrangement, the sour water stream 225 (with optional compression by a pump and / or compressor 1020) is sent to a flash tank 1050 for initial flash separation. A portion 1070 of the liquid from the flash tank 1050 can be compressed by an optional pump or compressor 1075 and sent to the first side of the primary heat exchanger 1015. Then, the heated sour water stream 1040 is passed through the valve 1045 to reduce the pressure and returned to the flash tank 1050 for further separation.

[0111] Water is recycled back from the flash tank 1050 to the primary heat exchanger 1015. The ratio of the supply rate of sour water to the flash tank to the recycle rate (i.e., the flow rate from the flash tank to the primary heat exchanger and back) is 1:2 to 1:10.

[0112] This process is designed to minimize the time that the sour water stream 225 spends in the primary heat exchanger 1015 in order to avoid the formation of vapor in the primary heat exchanger 1015.

[0113] Figure 10 shows a similar energy recovery system to the thermal oxidation system of Figure 7. In this embodiment, the exhaust steam stream 1000 can be the treated outlet flue gas stream 915, the de-NOx outlet flue gas stream 925, or the filtered flue gas stream 920.

[0114] The exhaust steam stream 1000 can be sent to the second side of an optional secondary heat exchanger 1005. The process stream is sent to the first side of the secondary heat exchanger 1005. One or more secondary heat exchangers 1005 can be present depending on the temperature of the exhaust steam stream and the number of process streams to be heated.

[0115] The process stream can be all or part of the combustion air stream 830 and / or the boiler feed water or oil stream 850.

[0116] The process stream is heated by heat exchange with the exhaust steam stream 1000, as a result of which the exhaust steam stream 1000 is cooled. The heated combustion air stream 830 is sent to the thermal oxidation section 800, while the heated boiler feed water or oil stream 850 is sent to the waste heat recovery section 805, thereby enhancing the steam generation or high-temperature oil generation efficiency.

[0117] The sour water stream 225 is passed through the first side of the primary heat exchanger 1015. One or more primary heat exchangers 1015 can be present. The sour water stream 225 can be optionally compressed in a pump and / or compressor 1020 before being introduced into the primary heat exchanger 1015.

[0118] The first cooled exhaust steam stream 1010 is passed through the second side of the primary heat exchanger 1015. Alternatively, in the absence of the secondary heat exchanger 1005, the exhaust steam stream 1000 is sent to the primary heat exchanger 1015.

[0119] The first cooled exhaust steam stream 1010 entering the primary heat exchanger 1015 has a temperature higher than the dew point. Heat exchange with the sour water stream 225 reduces the temperature of the first cooled exhaust steam stream 1010. In some cases, the temperature is reduced to a temperature below the dew point, resulting in condensation of water from the first cooled exhaust steam stream 1010. The resulting second cooled exhaust steam stream 1025 can be sent to the exhaust stack and discharged into the atmosphere.

[0120] In other cases, the temperature is not reduced sufficiently to condense some, most, or all of the water from the first cooled exhaust steam stream 1010. In this case, an optional tertiary heat exchanger 1030 can be used to reduce the temperature of the second cooled exhaust steam stream 1025 to a temperature below the dew point at which condensate formation occurs. The cooling medium for the tertiary heat exchanger 1030 can be, for example, cold air / ambient air or chilled water.

[0121] The condensate is recovered and exits the primary heat exchanger 1015 and / or the tertiary heat exchanger 1030 as the condensate stream 1035. The condensate stream 1035 can be used as the quench stream 885 or in other processes.

[0122] The heated sour water stream 1040 is sent through the valve 1045 to a lower pressure (e.g., a pressure of 1 - 20 psig) than the primary heat exchanger 1015 and into the flash tank 1050. When the higher pressure heated sour water stream 1040 enters the lower pressure flash tank 1050, it flashes into a vapor stream 1055 and a liquid stream 1060. The vapor stream 1055 and the liquid stream 1060 are sent to the thermal oxidation section 800 of the thermal oxidation system 555'. An optional pump and / or compressor 1065 can be present on the line of the liquid stream 1060 and can be.

[0123] FIG. 11 illustrates an alternative arrangement in which the sour water stream 225 is first sent to the flash tank 1050.

[0124] As used herein, the terms “unit,” “zone,” and “section” can refer to a region that includes one or more pieces of equipment, depending on the type of unit, zone, or section, and / or one or more sub - zones or sub - sections. Examples of equipment include, but are not limited to, one or more reactors or reaction vessels, separation vessels, adsorbent chambers, distillation columns, heaters, exchangers, pipes, pumps, compressors, and controllers. In addition, equipment such as reactors, dryers, adsorbent chambers, or vessels can further include one or more sections, sub - sections, zones, or sub - zones.

[0125] Specific embodiments The following is described in conjunction with specific embodiments, but it should be understood that this specification is illustrative of the foregoing description and the scope of the appended claims and is not intended to be limiting.

[0126] The first embodiment of the present invention is a process for treating an acid gas and a sour water effluent stream in a process for producing a renewable transport fuel, the process comprising, in a thermal oxidation system, thermally oxidizing at least one of a sour water stream from a low-temperature separation and fractionation section of a renewable transport fuel process and an amine acid gas stream from an acid gas treatment section of a renewable transport fuel process, wherein the sour water stream is not treated in a sour water stripper unit before being thermally oxidized in the thermal oxidation system, the amine acid gas stream is not treated in a sulfur recovery unit before being thermally oxidized in the thermal oxidation system, and thermally oxidizing at least one of the sour water stream and the amine acid gas stream in a thermal oxidation section to form a flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, SOx, NOx, HCl, Cl2, dioxin, and furan; and optionally recovering waste heat from the flue gas stream in a waste heat recovery section; and removing at least one of SOx, HCl, and Cl2 from the flue gas stream in a SOx removal section to form a desulfurized outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxin, and furan, wherein removing at least one of SOx, HCl, and Cl2 from the flue gas stream comprises quenching the flue gas stream in a quench section to form a quenched flue gas stream, and contacting the quenched flue gas stream with a caustic solution or an NH3-based solution in a scrubbing section to form a desulfurized outlet flue gas stream and a liquid stream containing at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl, or reacting the flue gas stream with NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2 in a SOx reaction section,React with a reactant containing at least one of Mg(OH)2 to form a reaction section flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, Mg(NO3)2, Cl2, NOx, dioxin, and furan, and in the filtration section, filter the reaction section flue gas stream to remove NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO, 4. Removing CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, and Mg(NO3)2 to form a desulfurized outlet flue gas stream, including forming a desulfurized outlet flue gas stream, and optionally, in a NOx removal section, removing NOx from the desulfurized outlet flue gas stream to form a denitrified outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, dioxins, and furans, and optionally, in a dioxin-furan removal section, removing dioxins, furans, or both from the desulfurized outlet flue gas stream or the denitrified outlet flue gas stream to form a treated outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, and O2, including thermal oxidation. One embodiment of the present invention is any one, any combination, or all of the embodiments from the previous embodiments of this paragraph to the first embodiment of this paragraph. The sour water stream includes at least one of a cold separator sour water stream from a cold separator in a cold separation and fractionation section, a debutanizer receiver sour water stream from a debutanizer in a cold separation and fractionation section, and a stripper receiver sour water stream from a stripper receiver in a cold separation and fractionation section. One embodiment of the present invention is any one, any combination, or all of the embodiments from the previous embodiments of this paragraph to the first embodiment of this paragraph. The amine acid gas stream includes a regenerator amine acid gas stream from a common amine regenerator overhead condenser and reflux drum.One embodiment of the present invention is one, any, or all of the embodiments from the embodiment following this paragraph to the first embodiment of this paragraph. In a recycle gas amine contactor, contacting a first portion of the lean amine stream with a cold separator sour water stream from a cold separator in a cold separation and fractionation section to form a first portion of the rich amine stream; in a debutanizer receiver amine contactor, contacting a first portion of the lean amine stream with an acidic liquefied petroleum gas (LPG) stream from a debutanizer receiver vessel in a cold separation and fractionation section to form a second portion of the rich amine stream; and in a sponge absorber lean gas overhead amine contactor, contacting a third portion of the lean amine stream with a lean acidic gas stream from a sponge absorber in a cold separation and fractionation section to form a third portion of the rich amine stream; performing at least one of the above; in a common amine regenerator, regenerating at least one of the first portion, the second portion, and the third portion of the rich amine stream to form a lean amine stream and an overhead regenerator amine acid gas stream; in an amine regenerator overhead condenser, separating the overhead amine acid gas stream into a regenerator amine acid gas stream and a reflux liquid stream; and refluxing the reflux liquid stream to the common amine regenerator.One embodiment of the present invention is one, any, or all of the embodiments from the embodiments prior to this paragraph to the first embodiment of this paragraph. In a pressure swing adsorption unit, a purge stream from an acidic recycle gas stream from a cryogenic separator in a cryogenic separation and fractionation section is separated into a recycle hydrogen stream and a PSA tail gas stream. The recycle hydrogen stream is combined with the acidic recycle gas stream, and the PSA tail gas stream is introduced as fuel into a thermal oxidation system. In a cryogenic separation and fractionation section in a debutanizer receiver amine contactor, a second portion of a lean amine stream is contacted with an acidic liquefied petroleum gas (LPG) stream to form a second portion of a rich amine stream. In a cryogenic separation and fractionation section in a sponge absorber lean gas overhead amine contactor, a third portion of the lean amine stream is contacted with a lean acidic gas stream from the sponge absorber to form a third portion of the rich amine stream. In a common amine regenerator, at least one of the second and third portions of the rich amine stream is regenerated to form a lean amine stream and an overhead regenerator amine acidic gas stream. In an amine regenerator overhead condenser, the overhead amine acidic gas stream is separated into a regenerator amine acidic gas stream and a reflux liquid stream, and the reflux liquid stream is refluxed to the common amine regenerator. One embodiment of the present invention is one, any, or all of the embodiments from the embodiments prior to this paragraph to the first embodiment of this paragraph. Yes, and before thermally oxidizing the sour water stream, it further includes preheating the sour water stream using steam from a process for producing renewable transportation fuel or from heat recovered from a waste heat recovery section. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiment of this paragraph to the first embodiment of this paragraph, and introducing a renewable feedstock into a guard bed to remove contaminants including one or more of alkali metals, oxygen compounds, sulfur compounds, and nitrogen compounds from the renewable feedstock; treating the renewable feedstock to remove additional oxygen compounds from the renewable feedstock; in a hydroisomerization and hydrocracking section, contacting the renewable feedstock with a hydroisomerization catalyst, a hydrocracking catalyst, or both in the presence of hydrogen under hydroisomerization and hydrocracking conditions to form a reaction effluent; and in a low-temperature separation and fractionation section, separating and fractionating the reaction effluent to form at least one renewable transportation fuel.One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiments in this paragraph to the first embodiment in this paragraph. Separating and fractionating the reaction effluent includes, in a cryogenic separator, separating the reactor effluent into a liquid hydrocarbon stream, a cryogenic separator recycle acid gas stream, and a cryogenic separator sour water stream; stripping the liquid hydrocarbon stream into a stripper overhead stream and a stripper bottoms stream; in a stripper receiver, separating the stripper overhead stream into a stripper receiver liquid stream, a stripper receiver offgas stream, and a stripper receiver sour water stream; contacting the stripper receiver offgas stream with a sponge absorber to form a sponge absorber liquid stream and a lean acid gas stream; in a debutanizer column, separating the stripper receiver liquid stream and optionally the sponge absorber liquid stream into a debutanizer overhead stream and a debutanizer bottoms stream; in a debutanizer receiver, separating the debutanizer overhead stream into an acid liquefied petroleum gas (LPG) stream, a debutanizer receiver sour water stream, and reflux; and fractionating the stripper bottoms stream into at least one of a renewable jet fuel stream, a renewable diesel fuel stream, and a naphtha stream. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiments in this paragraph to the first embodiment in this paragraph. The sour water stream includes at least one of the cryogenic separator sour water stream, the stripper receiver sour water stream, and the debutanizer receiver sour water stream.One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph. In a recycled gas amine contactor, contacting a first portion of a lean amine stream with a low-temperature separator acidic recycled gas stream to form a first portion of a rich amine stream; in a debutanizer receiver amine contactor, contacting a second portion of the lean amine stream with an acidic LPG stream from the debutanizer receiver to form a second portion of the rich amine stream; and in a sponge absorber overhead amine contactor, contacting a third portion of the lean amine stream with a lean acidic gas stream from the sponge absorber to form a third portion of the rich amine stream. At least one of these steps is performed. In a common amine regenerator, at least one of the first, second, and third portions of the rich amine stream is regenerated to form a lean amine stream and an overhead amine acidic gas stream. In an amine regenerator overhead condenser, the overhead amine acidic gas stream is separated into an amine acidic gas stream and a reflux liquid stream, and the reflux liquid stream is refluxed to the common amine regenerator. One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph. Quenching a flue gas stream includes quenching the flue gas stream with at least one of air, a quenched flue gas stream, a desulfurized outlet flue gas stream, a denitrified outlet flue gas stream, a treated outlet flue gas stream, and water. One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph. A non-compressed pressure swing adsorption (PSA) tail gas stream is used for hydrogen production. At least one of contacting a third portion of the lean amine stream with a lean acidic gas stream from the sponge absorber to form a third portion of the rich amine stream; regenerating at least one of the first, second, and third portions of the rich amine stream in a common amine regenerator to form a lean amine stream and an overhead amine acidic gas stream; separating the overhead amine acidic gas stream into an amine acidic gas stream and a reflux liquid stream in an amine regenerator overhead condenser; and refluxing the reflux liquid stream to the common amine regenerator is further included. One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph. Quenching a flue gas stream includes quenching the flue gas stream with at least one of air, a quenched flue gas stream, a desulfurized outlet flue gas stream, a denitrified outlet flue gas stream, a treated outlet flue gas stream, and water. One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph. A non-compressed pressure swing adsorption (PSA) tail gas stream is used for hydrogen production. Further including introducing from a PSA unit connected to a synthesis plant as a fuel source into a thermal oxidation system. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiments in this paragraph to the first embodiment in this paragraph, and further includes introducing a slip stream of a lean acid gas stream from a sponge absorber into the thermal oxidation system as a fuel source. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiments in this paragraph to the first embodiment in this paragraph, which is passing a sour water stream through a first side of a primary heat exchanger and passing an exhaust steam stream from the thermal oxidation system through a second side of the primary heat exchanger, wherein the exhaust steam stream includes a treated outlet flue gas stream, a de-NOx outlet flue gas stream, or a de-SOX outlet flue gas stream, passing through the second side, transferring heat from the exhaust steam stream to the sour water stream, cooling the exhaust steam stream to form a cooled exhaust steam stream, heating the sour water stream to form a heated sour water stream, depressurizing the heated sour water stream, passing the depressurized heated sour water stream through a flash tank having a pressure lower than the pressure of the primary heat exchanger to form a vapor stream and a liquid stream, passing the vapor stream and the liquid stream through a thermal oxidation section of the thermal oxidation system, and passing the cooled exhaust stream through an exhaust stack.One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph, and is passing a process stream to a first side of a secondary heat exchanger, wherein the process stream is at least one of a combustion air stream and a boiler feed water or oil stream; passing an exhaust steam stream to a second side of the secondary heat exchanger to lower the temperature of the exhaust steam stream and heat at least one process stream to form a second cooled exhaust steam stream and at least one of a heated combustion air stream and a heated boiler feed water or oil stream before passing the exhaust steam stream to a primary heat exchanger; passing the second cooled exhaust steam stream to a second side of the primary heat exchanger, wherein passing the exhaust steam stream from a thermal oxidation system to the second side of the primary heat exchanger includes passing the second cooled exhaust steam stream to the second side of the primary heat exchanger; and performing at least one of passing the heated combustion air stream to a thermal oxidation section of the thermal oxidation system and passing the heated boiler feed water or oil stream to a waste heat recovery section. One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph, and further includes introducing a sour water stream into a flash tank to form a liquid and a vapor and compressing at least a portion of the liquid before passing the sour water stream to a primary heat exchanger, wherein passing the sour water stream to a first side of the primary heat exchanger includes passing a portion of the compressed liquid from the flash tank to the primary heat exchanger, depressurizing the heated sour water stream includes depressurizing the heated compressed liquid from the primary heat exchanger, and passing the depressurized heated sour water stream to the flash tank includes passing the depressurized heated compressed liquid to the flash tank. One embodiment of the present invention is one, any, or all of the embodiments from the embodiment prior to this paragraph to the first embodiment of this paragraph, and in the primary heat exchanger, the exhaust steam stream is cooled to a temperature below the dew point to condense the water in the exhaust steam stream and form a first condensate stream.One embodiment of the present invention is one, any, or all of the embodiments from the embodiments prior to this paragraph to the first embodiment of this paragraph, and further includes passing the first condensate stream through a quench section. One embodiment of the present invention is one, any, or all of the embodiments from the embodiments prior to this paragraph to the first embodiment of this paragraph, and the cooled exhaust steam stream is passed through a tertiary heat exchanger before being passed through the exhaust stack, and the cooled exhaust steam stream is further cooled to a temperature below the dew point in the tertiary heat exchanger to condense the water of the cooled exhaust steam stream and form a second condensate stream. One embodiment of the present invention is one, any, or all of the embodiments from the embodiments prior to this paragraph to the first embodiment of this paragraph, and further includes passing the second condensate stream through a quench section. One embodiment of the present invention is from the embodiments prior to this paragraph to the embodiments of this paragraph. One, any, or all of the embodiments up to the first embodiment, and further includes compressing the sour water stream before passing the sour water stream through the primary heat exchanger.

[0127] The second embodiment of the present invention is a process for treating acid gas and sour water effluent streams in a process for producing renewable transportation fuels, the process comprising introducing a renewable feedstock to a guard bed to remove contaminants including one or more of alkali metals, oxygen compounds, sulfur compounds, and nitrogen compounds from the renewable feedstock, treating the renewable feedstock to remove additional oxygen compounds from the renewable feedstock, hydroisomerizing and hydrocracking the renewable feedstock to form a reactor effluent, separating the reactor effluent in a cryogenic separator into a liquid hydrocarbon stream, a cryogenic separator recycle acid gas stream, and a cryogenic separator sour water stream, stripping the liquid hydrocarbon stream into a stripper overhead stream and a stripper bottoms stream, separating the stripper overhead stream in a stripper receiver into a stripper receiver liquid stream, a stripper receiver offgas stream, and a stripper receiver sour water stream, contacting the stripper receiver offgas stream with a sponge absorber to form a sponge absorber liquid stream and a lean acid gas stream, separating the stripper receiver liquid stream and optionally the sponge absorber liquid stream in a debutanizer column into a debutanizer overhead stream and a debutanizer bottoms stream, separating the debutanizer overhead stream in a debutanizer receiver into an acid liquefied petroleum gas (LPG) stream, a debutanizer receiver sour water stream, and reflux, fractionating the stripper bottoms stream into at least one of a renewable jet fuel stream, a renewable diesel fuel stream, and a naphtha stream, contacting a first portion of a lean amine stream with the cryogenic separator acid recycle gas stream in a recycle gas amine contactor to form a first portion of a rich amine stream, contacting a second portion of the lean amine stream with the acid LPG stream from the debutanizer receiver in a debutanizer receiver amine contactor to form a second portion of a rich amine stream, and in a sponge absorber overhead amine contactor,Contacting at least one of a third portion of the lean amine stream with the lean acid gas stream from the sponge absorber to form a third portion of the rich amine stream; regenerating at least one of the first, second, and third portions of the rich amine stream in a common amine regenerator to form a lean amine stream and an overhead amine acid gas stream; separating the overhead amine acid gas stream into an amine acid gas stream and a reflux liquid stream in an amine regenerator overhead condenser; refluxing the reflux liquid stream to the common amine regenerator; thermally oxidizing at least one of a sour water stream from the low temperature separation and fractionation section and the amine acid gas stream in a thermal oxidation system, wherein the sour water stream is not treated in a sour water stripper unit before being thermally oxidized in the thermal oxidation system, the amine acid gas stream is not treated in a sulfur recovery unit before being thermally oxidized in the thermal oxidation system, the sour water stream includes at least one of a low temperature separator sour water stream from a low temperature separator in the low temperature separation and fractionation section, a debutanizer receiver sour water stream from a debutanizer in the low temperature separation and fractionation section, and a stripper receiver sour water stream from a stripper receiver in the low temperature separation and fractionation section, and thermally oxidizing at least one of the sour water stream and the amine acid gas stream forms a flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, SOx, NOx, HCl, Cl2, dioxin, and furan in a thermal oxidation section; optionally recovering waste heat from the flue gas stream in a waste heat recovery section; removing at least one of SOx, HCl, and Cl2 from the flue gas stream in a SOx removal section to form a flue gas stream consisting of H2O, CO2, N2, O2, NOx, dioxin, forming a flue gas stream that consists essentially of at least one of SOx, HCl, and Cl2 from the flue gas stream, quenching the flue gas stream in a quench section to form a quenched flue gas stream, and contacting the quenched flue gas stream with a caustic solution or an NH3-based solution in a scrubbing section to form a desulfurized outlet flue gas stream and a liquid stream containing at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl, or reacting the flue gas stream with a reactant containing at least one of NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2, and Mg(OH)2 in a SOx reaction section to form a reaction section flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, Mg(NO3)2, Cl2, NOx, dioxins, and furans, and filtering the reaction section flue gas stream in a filtration section to remove NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, CaCO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, and Mg(NO3)2 to form a desulfurized outlet flue gas stream, including forming a desulfurized outlet flue gas stream, and optionally, removing NOx from the desulfurized outlet flue gas stream in a NOx removal section to form a denitrified outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, dioxins, and furans, and optionally, removing dioxins, furans, or both from the desulfurized outlet flue gas stream or the denitrified outlet flue gas stream in a dioxin-furan removal section to form a treated outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, and O2, includingincluding thermal oxidation. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiment to the second embodiment of this paragraph, and before thermally oxidizing the sour water stream, from a process for producing renewable transportation fuel or using steam recovered from waste heat recovery section to preheat the sour water stream. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiment to the second embodiment of this paragraph, and quenching the flue gas stream includes quenching the flue gas stream with at least one of air, quenched flue gas stream, desulfurized SOx outlet flue gas stream, denitrified NOx outlet flue gas stream, treated outlet flue gas stream, and water. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiment to the second embodiment of this paragraph, and further includes introducing the non-compressed pressure swing adsorption (PSA) tail gas stream as a fuel source into the thermal oxidation system from a PSA unit connected to a hydrogen production plant. One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiment to the second embodiment of this paragraph, and further includes introducing a slip stream of the lean acid gas stream as a fuel source into the thermal oxidation system from a sponge absorber.,

[0128] Without further elaboration, using the foregoing description, those skilled in the art should be able to utilize the present invention to the greatest extent without departing from the spirit and scope of the present invention, and can easily confirm the essential characteristics of the present invention, make various changes and modifications to the present invention, and adapt to various uses and conditions. Therefore, the foregoing preferred specific embodiments should be construed as merely illustrative and not limiting the remainder of the present disclosure in any way, and are intended to cover various modifications and equivalent configurations within the scope of the appended claims.

[0129] In the above, all temperatures are described in degrees Celsius, and all parts and percentages are by weight unless otherwise specified.

Claims

Claim 1 A process for treating an acid gas and a sour water effluent stream in a process for producing a renewable transport fuel, in a thermal oxidation system (555), thermally oxidizing at least one of a sour water stream (225) from a low temperature separation and fractionation section (205) of the renewable transport fuel process and an amine acid gas stream (385) from an acid gas treatment section of the renewable transport fuel process, wherein the sour water stream (225) is not treated in a sour water stripper unit before being thermally oxidized in the thermal oxidation system (555), the amine acid gas stream (385) is not treated in a sulfur recovery unit before being thermally oxidized in the thermal oxidation system (555), and thermally oxidizing the at least one of the sour water stream (225) and the amine acid gas stream (385) is In the thermal oxidation section (600), thermally oxidize at least one of the sour water stream (225) and the amine acid gas stream (385) to form a flue gas stream (645) consisting essentially of at least one of H ２ O, CO ２ 2 ２ 2 ２ 2, SOx, NOx, HCl, Cl ２ 2, dioxins, and furans. optionally, recovering waste heat from the flue gas stream (645) in a waste heat recovery section (605); and In the SOx removal section (615), at least one of SOx, HCl, and Cl is removed from the flue gas stream (645) to form a desulfurized outlet flue gas stream (690) consisting essentially of at least one of H ２ O, CO ２ , N ２ , O ２ , NOx, dioxin, and furan, wherein removing at least one of SOx, HCl, and Cl from the flue gas stream is ２ and ２ the at least one of them is removed quenching the flue gas stream (645) in a quench section (610) to form a quenched flue gas stream (675), and In the scrubbing section, contacting a caustic solution or an NH ３ -based solution (680) with the quenched flue gas stream (675) to form a desulfurized outlet flue gas stream (690) and a liquid stream (685) containing at least one of H ２ O, Na ２ SO ３ , Na ２ SO ４ , NaHSO ３ , Na ２ CO ３ , NaCl, (NH ４ ) ２ SO ４ , and NH ４ Cl. or In the Sox reaction section (810), the flue gas stream (845) is reacted with a reactant containing at least one of NaHCO ３ NaHCO ３ ·Na ２ CO ３ ·(H ２ O), CaCO ３ Ca(OH) ２ and Mg(OH) ２ to form a reaction section flue gas stream (880) consisting essentially of at least one of H ２ O, CO ２ N ２ O ２ NaCl, Na ２ CO ３ Na ２ SO ４ NaNO ３ CaCl ２ CaSO ４ CaCO ３ Ca(NO ３ ) ２ MgCl ２ MgCO ３ MgSO ４ Mg(NO ３ ) ２ Cl ２ NOx, dioxin, and furan, and In the filtration section (815), the reaction section flue gas stream (880) is filtered to remove NaCl, Na ２ CO ３ , Na ２ SO ４ , NaNO ３ , CaCl ２ , CaSO ４ , CaCO ３ , Ca(NO ３ ) ２ , MgCl ２ , MgCO ３ , MgSO ４ , and Mg(NO ３ ) ２ to form the desulfurized outlet flue gas stream (900), including forming and Optionally, in the NOx removal section (620), NOx is removed from the desulfurized outlet flue gas stream (690) to form a denitrified outlet flue gas stream (700) consisting essentially of at least one of H ２ O, CO ２ 、N ２ 、O ２ 、dioxin, and furan. optionally, in a dioxin-furan removal section (625), removing the Removing dioxin, furan, or both from the SOx outlet flue gas stream (690) or the DeNOx outlet flue gas stream (700) to form a treated outlet flue gas stream (705) consisting essentially of at least one of H ２ O, CO ２ , N ２ , and O ２ ; and a process comprising thermal oxidation. Claim 2 The process according to claim 1, wherein the sour water stream (225) comprises at least one of a low temperature separator sour water stream (460) from a low temperature separator (450) in the low temperature separation and fractionation section (205), a debutanizer receiver sour water stream (530) from a debutanizer receiver (525) in the low temperature separation and fractionation section (205), and a stripper receiver sour water stream (495) from a stripper receiver (480) in the low temperature separation and fractionation section (205), or the amine acid gas stream (385) comprises a regenerator amine acid gas stream (385) from a common amine regenerator overhead condenser and reflux drum (375), or both. Claim 3 In a recycle gas amine contactor (245), contacting a first portion (295) of a lean amine stream (300) with an acidic recycle gas stream (210) from a cryogenic separator (450) within the cryogenic separation and fractionation section (205) to form a first portion (305) of a rich amine stream (310), or in a pressure swing adsorption unit (212), separating a purge stream (211) from the acidic recycle gas stream (210) from the cryogenic separator (450) within the cryogenic separation and fractionation section (205) into a recycle hydrogen stream (213) and a PSA tail gas stream (214), combining the recycle hydrogen stream (213) with the acidic recycle gas stream (210), and introducing the PSA tail gas stream (214) as fuel into the thermal oxidation system (555), In a debutanizer receiver amine contactor (320), contacting a second portion (315) of the lean amine stream (310) with an acidic liquefied petroleum gas (LPG) stream (215) from a debutanizer receiver vessel (525) within the cryogenic separation and fractionation section (205) to form a second portion (325) of the rich amine stream (310), and In a sponge absorber lean gas overhead amine contactor (345), contacting a third portion (335) of the lean amine stream (300) with a lean acidic gas stream (220) from a sponge absorber (500) within the cryogenic separation and fractionation section (205) to form a third portion (350) of the rich amine stream (310), at least one of which is performed, In the common amine regenerator (365), regenerating at least one of the first portion (305), the second portion (325), and the third portion (350) of the rich amine stream (310) to form the lean amine stream (300) and an overhead regenerator amine acidic gas stream (370), In an amine regenerator overhead condenser (375), separating the overhead amine acidic gas stream (370) into a regenerator amine acidic gas stream (385) and a reflux liquid stream (380), The process according to claim 1 or 2, further comprising refluxing the reflux liquid stream (380) to the common amine regenerator (365).

4. Introducing a renewable feedstock (105) into a guard bed (140) to remove contaminants including one or more of alkali metals, oxygen compounds, sulfur compounds, and nitrogen compounds from the renewable feedstock (110); Treating the renewable feedstock (105) to remove additional oxygen compounds from the renewable feedstock (105); In a hydroisomerization and hydrocracking section (155), contacting the renewable feedstock (105) with a hydroisomerization catalyst, a hydrocracking catalyst, or both in the presence of hydrogen under hydroisomerization and hydrocracking conditions to form a reaction effluent (160); In the low-temperature separation and fractionation section (205), separating and fractionating the reaction effluent to form at least one renewable transportation fuel (235, 240), the process according to claim 1 or 2.

5. Separating and fractionating the reaction effluent In a low-temperature separator (450), separating the reactor effluent into a liquid hydrocarbon stream (455), a low-temperature separator recycle acid gas stream (210), and a low-temperature separator sour water stream (460); Stripping the liquid hydrocarbon stream (455) into a stripper overhead stream (470) and a stripper bottoms stream (475); In a stripper receiver (480), separating the stripper overhead stream (470) into a stripper receiver liquid stream (485), a stripper receiver offgas stream (490), and a stripper receiver sour water stream (495); Contacting the stripper receiver offgas stream (490) with a sponge absorber (500) to form a sponge absorber liquid stream (505) and a lean acid gas stream (220); In a debutanizer column (510), separating the stripper receiver liquid stream (485) and optionally the sponge absorber liquid stream (505) into a debutanizer overhead stream (515) and a debutanizer bottoms stream (520); ​ In a debutanizer receiver (525), separating the debutanizer overhead stream (515) into an acidic liquefied petroleum gas (LPG) stream (215), a debutanizer receiver sour water stream (530), and a reflux (535); fractionating the stripper bottoms stream (475) into at least one of a renewable jet fuel stream (235), a renewable diesel fuel stream (240), and a naphtha stream (230); The process of claim 4, wherein the sour water stream (225) includes at least one of the cryogenic separator sour water stream (460), the stripper receiver sour water stream (495), and the debutanizer receiver sour water stream (530). **Claim 6** In a recycle gas amine contactor (245), contacting a first portion (295) of a lean amine stream (300) with the cryogenic separator acidic recycle gas stream (210) to form a first portion (305) of a rich amine stream (310), or in a pressure swing adsorption unit (212), separating a purge stream (211) from the acidic recycle gas stream (210) from a cryogenic separator (450) within the cryogenic separation and fractionation section (205) into a recycle hydrogen stream (213) and a PSA tail gas stream (214), combining the recycle hydrogen stream (213) with the acidic recycle gas stream (210), and introducing the PSA tail gas stream (214) as fuel to the thermal oxidation system (555); In a debutanizer receiver amine contactor (320), contacting a second portion (315) of the lean amine stream (310) with the acidic LPG stream (215) from the debutanizer receiver (525) to form a second portion (325) of the rich amine stream (310); and In a sponge absorber overhead amine contactor (345), contacting a third portion (335) of the lean amine stream (300) with the lean acidic gas stream (220) from the sponge absorber (500) to form a third portion (350) of the rich amine stream (310), performing at least one of these. In a common amine regenerator (365), regenerating at least one of the first portion (305), the second portion (325), and the third portion (350) of the rich amine stream (310) to form the lean amine stream (300) and the overhead amine acid gas stream (370); In an amine regenerator overhead condenser (375), separating the overhead amine acid gas stream (370) into the amine acid gas stream (385) and a reflux liquid stream (380); The process according to claim 5, further comprising refluxing the reflux liquid stream (380) to the common amine regenerator (365).

7. Introducing the non-compressed pressure swing adsorption (PSA) tail gas stream (430) as a fuel source from a PSA unit (410) connected to a hydrogen production plant to the thermal oxidation system (555), and The process according to claim 1 or 2, further comprising at least one of introducing a slip stream 570) of the lean acid gas stream (220) as a fuel source from a sponge absorber (500) to the thermal oxidation system (555).

8. Passing the sour water stream (225) through a first side of a primary heat exchanger (1015); Passing an exhaust steam stream (1000) from the thermal oxidation system through a second side of the primary heat exchanger (1000), wherein the exhaust steam stream (1000) contains the treated outlet flue gas stream 9705, the de-NOx outlet flue gas stream (715), or the de-SOx outlet flue gas stream (710), passing through the second side; Transferring heat from the exhaust steam stream (1000) to the sour water stream (225), cooling the exhaust steam stream (1000) to form a cooled exhaust steam stream (1025), and heating the sour water stream (225) to form a heated sour water stream (1040); Reducing the pressure of the heated sour water stream (1040); Passing the depressurized heated sour water stream (1040) through a flash tank (1050) having a pressure lower than that of the primary heat exchanger (1015) to form a vapor stream (1055) and a liquid stream (1060); Passing the steam stream (1055) and the liquid stream (1060) through the thermal oxidation section (600) of the thermal oxidation system (555), Passing the cooled exhaust stream (1025) through an exhaust stack, the process according to claim 1 or 2, further comprising.

9. Passing a process stream through a first side of a secondary heat exchanger (1005), wherein the process stream is at least one of a combustion air stream (630) and a boiler feed water or oil stream (650), passing through the first side, Before passing the exhaust steam stream (1000) through the primary heat exchanger (1015), passing the exhaust steam stream (1000) through a second side of the secondary heat exchanger (1005) to lower the temperature of the exhaust steam stream (1000) and heat the at least one process stream, forming a second cooled exhaust steam stream (1010), and at least one of a heated combustion air stream (630) and a heated boiler feed water or oil stream (650), Passing the second cooled exhaust steam stream (1010) through the primary heat exchanger (1015), wherein passing the exhaust steam stream (1000) from the thermal oxidation system (555) through a second side of the primary heat exchanger (1015) is the second cooling Including passing the cooled exhaust steam stream (1010) through the second side of the primary heat exchanger (1015), passing through, Passing the heated combustion air stream (630) through the thermal oxidation section (600) of the thermal oxidation system (555), and At least one of passing the heated boiler feed water or oil stream (650) through the waste heat recovery section (605), the process according to claim 8, further comprising.

10. Before passing the sour water stream (225) through the primary heat exchanger (1015), introducing the sour water stream (225) into the flash tank (1050) to form a liquid and a vapor, Further comprising compressing at least a portion of the liquid (1070), Passing the sour water stream (225) to the first side of the primary heat exchanger (1015) includes passing a portion of the compressed liquid (1070) from the flash tank (1050) to the primary heat exchanger (1015), Depressurizing the heated sour water stream (1040) includes depressurizing the heated compressed liquid from the primary heat exchanger (1015), The process of claim 8, wherein passing the depressurized heated sour water stream (1040) to the flash tank (1050) includes passing the depressurized heated compressed liquid to the flash tank (1050).

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