Renewable transportation fuels process using thermal oxidation systems

Abstract

A process for treating effluent streams in a renewable transportation fuel production process is described. One or more of a sour water stream and an acid gas stream are treated directly in a thermal oxidation section. The process allows for the elimination or reduction in size of a sour water stripper unit, a wastewater treatment plant, and a sulfur recovery unit.

Description

[Technical field]

[0001] (Statement of priority) This application claims the benefit of U.S. Provisional Patent Application No. 63 / 060,031, filed August 1, 2020, No. 63 / 065,639, filed August 14, 2020, and No. 63 / 155,465, filed March 2, 2021, which are incorporated by reference in their entireties herein. [Background technology]

[0002] As the demand for diesel and jet boiling range fuels increases worldwide, there is growing interest in sources of feedstock other than crude oil. One such source is what are 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 oils, algae oils, and animal fats such as tallow and fish oils. 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 linear aliphatic carbon chains with 8 to 24 carbon atoms. The aliphatic carbon chains in the glycerides or FFAs can be fully saturated or mono-, di-, or polyunsaturated. The side chains of the glycerides and FFAs in biological oils and fats can be converted into diesel or jet fuel using a number of different processes, such as hydrodeoxygenation and hydroisomerization processes.

[0003] Fuels processed from renewable biological sources are desirable for a variety of reasons. First, the use of renewable biologically sourced fuels reduces the demand for the extraction and use of fossil fuels. This is especially true for transportation fuels such as diesel and jet fuels. In addition to the environmental benefits of using biologically sourced fuels, there is a market demand for such fuels. With fuel purchasers, the use of biologically sourced fuels can promote public relations. Also, certain government policies may require or reward the use of biologically sourced fuels.

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

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

[0006] [Figure 1] FIG. 1 is a diagram of a conventional waste treatment process for a renewable transportation fuel production process. [Diagram 2] FIG. 1 is a diagram of a portion of a process for producing renewable transportation fuels. [Diagram 3] FIG. 2 is a diagram of an embodiment of a cryogenic separation and fractionation section. [Figure 4A] FIG. 1 is a diagram of one embodiment of a waste treatment process for a renewable transportation fuel production process in accordance with the present invention. [Figure 4B] 4B is an alternative embodiment of the waste treatment process of FIG. 4A. [Diagram 5] FIG. 2 is a diagram of another embodiment of a waste treatment process for a renewable transportation fuel production process in accordance with the present invention. [Figure 6] FIG. 1 is a diagram of one embodiment of a thermal oxidation system in accordance with the present invention. [Figure 7] FIG. 2 is a diagram of another embodiment of a thermal oxidation system in accordance with the present invention. [Figure 8] FIG. 7 is a diagram of an embodiment of the thermal oxidation system of FIG. 6 with improved energy recovery. [Figure 9] FIG. 7 is a diagram of another embodiment of the thermal oxidation system of FIG. 6 with improved energy recovery. [Figure 10] FIG. 8 is a diagram of an embodiment of the thermal oxidation system of FIG. 7 with improved energy recovery. [Figure 11] FIG. 8 is a diagram of another embodiment of the thermal oxidation system of FIG. 7 with improved energy recovery. DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

[0007] The renewable transportation fuel production process produces one or more sour water streams. The sour water streams include a low temperature separator sour water stream from a low temperature separator in the low temperature separation and fractionation section, a de-butanizer receiver sour water stream from a de-butanizer 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. The sour water stream is sent to a sour water stripper unit. A portion of the sweet water may be returned to the renewable transportation fuel production process or sent to other units in the refinery complex, such as a hydrotreating unit water wash section, a crude oil desalter, etc. 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 to a belt filter to remove a cake composed of sulfur-containing materials. The gaseous material from the SRU is sent to a thermal oxidizer and / or vented to the atmosphere.

[0008] The process also produces one or more acid gas streams in an acid gas treatment section that 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 off-gas 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) with the acid recycle gas stream from the cold separator in a cold separation and fractionation section in a recycle gas amine contactor. The lean amine stream contacts with the acid LPG stream from the debutanizer receiver vessel in a cold separation and fractionation section in a debutanizer receiver amine contactor. The lean amine stream contacts with the lean acid gas stream from the sponge absorber in a cold separation and fractionation section in a 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 a common amine regenerator to form a lean amine stream and a regenerator overhead stream. The regenerator overhead stream is sent to an amine regenerator overhead condenser and reflux drum to be separated into a liquid reflux and an amine acid gas stream. The liquid reflux is returned to the common amine regenerator. The acid gases containing CO2 and H2S are sent to a sulfur recovery unit.

[0010] One aspect of the invention is a process for treating acid gas and sour water effluent streams in a process for producing renewable transportation fuels. In one embodiment, the process includes thermally oxidizing at least one of a sour water stream from a low temperature separation and fractionation section of a renewable transportation fuel process and an amine acid gas stream from an acid gas processing section of the renewable transportation fuel process in a thermal oxidation system, where the sour water stream is not treated in a sour water stripper unit before being thermally oxidized in the thermal oxidation system, and the amine acid gas stream is not treated in a sulfur recovery unit before being thermally oxidized in the thermal oxidation system, 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, dioxins, and furans, and 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 de-SOx outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxins, and furans, and removing at least one of SOx, HCl, and Cl2 from the flue gas stream includes quenching the flue gas stream in a quench section to form a quenched flue gas stream. and in a scrubbing section, contacting a caustic or NH3-based solution with the quenched flue gas stream to form a de-SOx outlet flue gas stream and a liquid stream comprising 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 a caustic or NH3-based solution to form a de-SOx outlet flue gas stream and a liquid stream comprising at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl.and 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, dioxins, and furans; and filtering, in a filtration section, 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 produce a de-SOx outlet flue gas stream. forming a de-SOx outlet flue gas stream, optionally in a NOx removal section, removing NOx from the de-SOx outlet flue gas stream to form a de-NOx 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 de-SOx outlet flue gas stream or the de-NOx 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. Thermally oxidizing a particular stream means that thermally oxidizable hydrocarbon components in the stream are thermally oxidized. For example, a sour water stream thermally oxidizes thermally oxidizable hydrocarbon components and sulfur and nitrogen components in the sour water stream and vaporizes water.

[0011] In some embodiments, the sour water stream comprises 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.

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

[0013] In some embodiments, the process includes contacting a first portion of the lean amine stream with an acidic recycle gas stream from a cold separator in the cold separation and fractionation section in a recycle gas amine contactor to form a first portion of a rich amine stream; contacting a first portion of the lean amine stream with an acidic recycle gas stream from a cold separator in the cold separation and fractionation section in a debutanizer receiver amine contactor to form a first portion of a rich amine stream; and contacting a third portion of the lean amine stream in a sponge absorber-lean gas overhead amine contactor with a lean acid gas stream from the sponge absorber of the cryogenic separation and fractionation section to form a third portion of a 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.

[0014] In some embodiments, the process includes separating a purge stream from an acid recycle gas stream from a low temperature separator in a low temperature separation and fractionation section into a recycled hydrogen stream and a PSA tail gas stream in a pressure swing adsorption unit, combining the recycled hydrogen stream with the acid recycle gas stream, and introducing the PSA tail gas stream as a fuel into a thermal oxidation system; contacting a second portion of the lean amine stream with an acid liquefied petroleum gas (LPG) stream in a low temperature separation and fractionation section in a debutanizer receiver amine contactor to form a second portion of a rich amine stream; contacting a third portion of the lean amine stream with the lean acid gas stream from the sponge absorber in a low temperature separation and fractionation section in an absorber lean gas overhead amine contactor to form a third portion of a rich amine stream; regenerating at least one of the 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.

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

[0016] In some embodiments, the process further includes introducing the renewable feedstock into a guard bed to remove contaminants from the renewable feedstock, including one or more of alkali metals, oxygen compounds, sulfur compounds, and nitrogen compounds; 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 reactor effluent includes separating the reactor effluent into a liquid hydrocarbon stream, a low temperature separator recycle acid gas stream, and a low temperature separator sour water stream in a low temperature 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 off-gas stream, and a stripper receiver sour water stream in a stripper receiver; and contacting the stripper receiver off-gas stream with a sponge absorber to obtain a sponge absorbent. forming a collector 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 overhead stream, a debutanizer bottoms stream; separating in the debutanizer receiver the debutanizer overhead stream into a sour 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.

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

[0019] In some embodiments, the process further includes at least one of contacting a first portion of the lean amine stream with a cold 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 an acid LPG stream from the debutanizer receiver in a debutanizer receiver amine contactor to form a second portion of a 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 overhead amine contactor to form a third portion of a 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 de-SOx outlet flue gas stream, a de-NOx outlet flue gas stream, a treated outlet flue gas stream, and water.

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

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

[0023] Another aspect of the invention is a process for treating acid gas and sour water effluent streams in a process for producing renewable transportation fuels. In one embodiment, the process includes: introducing a renewable feedstock into a guard bed to remove contaminants from the renewable feedstock, including one or more of alkali metals, oxygen compounds, sulfur compounds, and nitrogen compounds; 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 into a liquid hydrocarbon stream, a low temperature separator recycle acid gas stream, and a low temperature separator sour water stream in a low temperature separator; stripping the liquid hydrocarbon stream into a stripper overhead stream and a stripper bottom stream; separating the stripper overhead stream into a stripper receiver liquid stream, a stripper receiver off-gas stream, and a stripper receiver sour water stream in a stripper receiver; contacting the stripper receiver off-gas 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, a debutanizer bottoms stream; separating the debutanizer overhead stream in a debutanizer receiver into an acidic 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 the lean amine stream with a cold separator acidic 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 an acidic LPG stream from the debutanizer receiver in a debutanizer receiver amine contactor to form a second portion of a rich amine stream;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 a 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; refluxing the reflux liquid stream to the common amine regenerator; 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 thermally oxidizing at least one of the 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, and the sour water stream is not treated in a sulfur recovery unit before being thermally oxidized in the thermal oxidation system, a separator sour water stream, 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, wherein thermally oxidizing at least one of the sour water stream and the amine acid gas stream comprises: 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, dioxins, and furans; 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 de-SOx outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxins, and furans,and removing at least one of Cl2 includes quenching the flue gas stream in a quenching section to form a quenched flue gas stream, and contacting a caustic solution or an NH3-based solution with the quenched flue gas stream in a scrubbing section to form a deSOx outlet flue gas stream and a liquid stream comprising at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl; in a SOx reaction section, the flue gas stream is reacted with reactants including at least one of NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2, and Mg(OH)2 to produce a reaction mixture 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. forming a reaction section flue gas stream, 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 de-SOx outlet flue gas stream; and optionally filtering the reaction section flue gas stream in a NOx removal section to remove N from the de-SOx outlet flue gas stream. and optionally removing dioxins, furans, or both from the de-SOx outlet flue gas stream or the de-NOx 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 HO, CO, N, O, dioxins, and furans.

[0024] In some embodiments, the process further includes preheating the sour water stream using steam from a process for producing renewable transportation fuels or from heat recovered from the waste heat recovery section prior to thermally 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 de-SOx outlet flue gas stream, a de-NOx outlet flue gas stream, a treated outlet flue gas stream, and water.

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

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

[0028] 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 appreciated by those skilled in the art, other arrangements are possible and not all pieces of equipment are shown in every process. Renewable feedstock 105 and optionally petroleum feedstock 110 are introduced in a single or two stage renewable transportation fuel production unit 115 to make renewable transportation fuels.

[0029] Figure 2 provides details of one embodiment of the conventional renewable transportation fuel generation unit 115 of Figure 1. As will be appreciated by one of ordinary skill in the art, other configurations are possible and not all pieces of equipment are shown in every process. As is known in the art, the renewable transportation fuel generation process can be a single stage or a two stage process.

[0030] Renewable feedstocks 105 include, but are not limited to, glycerides, fatty acid alkyl esters (FAAEs), and free fatty acids (FFAs). Most of the glycerides are triglycerides, but mono- and diglycerides can exist and be similarly processed. Examples of renewable feedstocks include, but are not limited to, canola oil, corn oil, soybean oil, rapeseed oil, tall oil, sunflower oil, hemp seed 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, inedible tallow, yellow and brown grease, lard, whale oil, milk fat, fish oil, algae oil, sewage sludge, cuphea oil, camelina oil, curcas oil, babassu oil, palm nut oil, seaweed oil, fatty acid methyl esters, lard, and the like, or any oil derived from natural sources or produced by microbial activity. Typical vegetable oil or animal fat glycerides, FAAEs, and FFAs contain aliphatic hydrocarbon chains with 8 to 24 carbon atoms in their structure, with the majority of fats and oils containing high concentrations of fatty acids with 16 and 18 carbon atoms.

[0031] In some cases, renewable feedstock 105 may be nitrogen-rich, meaning having more than 100 ppm nitrogen, or in some embodiments, more than 60 ppm nitrogen.

[0032] Renewable feedstocks may contain various impurities. For example, tall oil contains esters and rosin acids in addition to FFAs. Rosin acids are cyclic carboxylic acids. Renewable feedstocks may 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 oil feedstock 110 may be sent to a surge drum 125. From the surge drum 125, the renewable feedstock 130 may be combined with a recycled hydrogen stream 135 and sent to one or more guard beds 140 and / or a treatment unit 145 to remove contaminants. If both guard beds 140 and treatment units 145 are present, the effluent 142 from the guard beds 140 is sent to the treatment unit 145.

[0034] The use of guard beds 140 to remove metal contaminants from renewable feedstocks 130 is well known in the art. These can include alumina guard beds with or without demetallization catalysts 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 deoxygenation of triglyceride molecules, saturation of olefins, nitrogen removal, sulfur removal, metal removal, and halide removal. Deoxygenation of triglyceride molecules involves decarboxylation and / or decarbonylation and / or hydrodeoxygenation to remove oxygen from the renewable feedstock. Saturation of olefins involves saturation of olefins or unsaturated moieties in the hydrocarbon chain with hydrogen. Saturation of olefins is an exothermic reaction and consumes hydrogen. The amount of olefins varies depending on the source of the feedstock. Nitrogen removal involves conversion of organic nitrogen in the feedstock (such as from trace amino acids) to ammonia. Nitrogen is poisonous to the isomerization catalyst, so the nitrogen content of the effluent from processing unit 145 must be less than 50 ppb. Sulfur removal involves conversion of natural sulfur in the feedstock to H2S. Since the active state of the catalyst is in the sulfide form, additional sulfur (typically dimethyl disulfide (DMDS)) is added to the feed which also converts to H2S. The H2S then inhibits oxidation and reduction of the active guard and treatment catalyst metals exposed to H2O and H2 in the hydroprocessing environment. With respect to metal removal, phosphorus and other metals are retained on the catalyst by a combination of adsorption and chemical reaction. The catalyst has a certain maximum capacity for retaining metals. The useful life of the guard and treatment catalyst is determined in large part by the amount of metals that accumulate during operation. The metals (Na, Ca, K, Mg, Al, and Fe) are derived from renewable feedstocks and are naturally occurring and associated with phospholipid compounds present in the renewable feedstock feed. Silicon can be a contaminant from feedstock processing, while iron can also be removed from acidic feed processing and storage.

[0036] The guard bed 140 and the treatment unit 145 may be separate vessels, or may be two or more beds within a single vessel.

[0037] In the single stage process, treated stream 150 is sent to hydroisomerization and hydrocracking reaction section 155. Recycle hydrogen stream 135 is also introduced into hydroisomerization and hydrocracking reaction section 155. Effluent stream 160 from hydroisomerization and hydrocracking reaction section 155 is cooled by removing thermal energy in steam generator 185. Cooled stream 190 is sent to separation section 165. Separation section 165 includes an isomerization / cracked effluent separator. Effluent stream 200 from separation section 165 is sent to low temperature separation and fractionation section 205.

[0038] In the two-stage process, the treated stream 150' is cooled by removing heat energy in a steam generator 170. The cooled stream 175 is sent to the high temperature separator followed by an extended high temperature separator in separation section 165. Separation section 165 also includes an isomerization / cracking effluent separator. A liquid stream 180 from the extended high temperature separator in 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 in 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 vapor streams from the high temperature separator and the extended high temperature separator form an effluent stream 200' from separation section 165 and are sent to the low temperature separation and fractionation section 205.

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

[0040] The hydroisomerization and selective hydrocracking of paraffinic products can be accomplished 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 operation mode. Both fixed bed trickle bed downflow mode or fixed bed liquid loaded upflow mode are suitable.

[0041] The primary isomerization products are generally mono-branched hydrocarbons. Along with isomerization, hydrocracking of the hydrocarbons occurs. The more severe the conditions in the hydroisomerization and hydrocracking reaction section 155, the greater the amount of hydrocracking of the hydrocarbons. Increasing the level of hydrocracking results in a higher yield of hydrocarbons in the boiling range of aviation fuel.

[0042] The hydroisomerization and hydrocracking of paraffinic hydrocarbons in hydroisomerization and hydrocracking reaction section 155 can be accomplished in any manner known in the art or by using any suitable catalyst known in the art. Suitable catalysts include metals from Group VIII (IUPAC 8-10) of the periodic table and support materials. Suitable Group VIII metals include platinum and palladium, each of which may be used alone or in combination. The support material may 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, isomerization conditions in the hydroisomerization and hydrocracking reaction section 155 include 150° C. to 450° C. (302° F. to 842° F.), or 300° C. to 400° C. (572° F. to 752° F.), or 300° C. to 360° C. (572° F. to 680° F.). Typical isomerization pressures can be 2760 to 6890 kPa (400 to 1000 psig), or in some embodiments, 2760 to 4820 kPa (400 to 700 psig). Other operating conditions for the isomerization zone are well known in the art, and the particular operating conditions used are predetermined and dependent upon the desired product specifications and the relative yields of the products.

[0044] The severity of the process in the hydroisomerization and hydrocracking section 155 controls the potential yield of aviation fuel products, the amount of diesel fuel or lighter products not useful for aviation fuel, and the isomerized / conventional ratio of fuels in both the aviation and diesel ranges. Hydrocracking is controlled through catalyst selection and reaction conditions to limit the extent of hydrocracking. Ideally, each paraffin molecule undergoes only a single hydrocracking event, and ideally a single hydrocracking event is limited to only a single C9-C 15 Careful selection of catalyst and control of process conditions in hydroisomerization and hydrocracking reaction section 155 can maximize paraffin products in the aviation fuel range while minimizing the production of light paraffins, i.e., paraffins with three or fewer carbon chains that are not useful for diesel or aviation fuel applications.

[0045] It should be noted that fuel specifications are not typically based on carbon number ranges. Instead, the specifications of different types of fuels are often stated through the acceptable range of the fuel's chemical and physical requirements. For example, the distillation range from 10 percent recovery to the final boiling point is often used as the primary parameter that defines different types of fuels. The distillation range is typically measured by ASTM test methods D86 or D2887. It is very common to blend different components to meet different specifications and requirements.

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

[0047] The acid recycle gas stream 210, which contains hydrogen, carbon monoxide, hydrogen sulfide, carbon dioxide, and propane, is sent to a recycle gas amine contactor 245 to remove the carbon monoxide, hydrogen sulfide, and some of the 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 sent to the hydroisomerization and hydrocracking reaction section 155.

[0048] 3 illustrates one embodiment of the low temperature separation and fractionation section 205. As will be appreciated by those skilled in the art, other arrangements are possible and not all pieces of equipment are shown for every process. In the low temperature separation and fractionation section 205, the effluent stream 200 / 200', which includes a combination of one or more of the steam from the high temperature separator, the steam from the extended high temperature separator, and the liquid from the isomerization / cracked effluent separator, is sent to a condenser 440 of the low temperature separation and fractionation section 205. The condensed stream 445 is sent to the low temperature separator 450 and separated into a liquid hydrocarbon stream 455, a low temperature separator sour water stream 460, and an acid recycle gas stream 210. Details of the high temperature separation section 165 and the low temperature separation and fractionation section 205 are familiar to those skilled in the art.

[0049] The liquid hydrocarbon stream 455 from the low temperature separator 450 is sent to a steam stripper 465. The acid recycle gas stream 210 is sent to a recycle gas amine contactor 245 for removal of 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 a stripper receiver 480 and separated into a stripper receiver liquid stream 485, a stripper receiver off-gas stream 490, and a stripper receiver sour water stream 495.

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

[0052] Stripper receiver liquid stream 485 and optionally sponge absorber liquid stream 505 are sent to debutanizer column 510 and separated into debutanizer overhead stream 515 and debutanizer bottoms stream 520. Debutanizer bottoms stream 520, which contains naphtha, may be combined with naphtha stream 230.

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

[0054] The stripper bottoms stream 475 is sent to a fractionator 477 and fractionated 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 low temperature separator sour water stream 460 from the low temperature 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 may be combed into the sour water stream 225 sent to the sour water stripper (SWS) unit 250.

[0056] Returning to Figure 1, sour water stream 225 is sent to SWS unit 250 and separated using steam into SWS acid gas stream 255 and SWS bottoms stream 260. The SWS bottoms stream may be sent to a wastewater treatment plant 265. A portion 270 of SWS bottoms stream 260 may be sent back to renewable transportation fuels production unit 115 or to other units within the refining complex.

[0057] The SWS acid gas stream 255 is sent to a sulfur recovery unit (SRU) 275. Suitable SRUs are known in the art, including, but not limited to, the Claus process, and liquid oxidation-reduction 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. A gas stream 285 from the SRU 275 is sent to a thermal oxidation section 290 and flue gas 292 is vented to the atmosphere.

[0058] The acid recycle gas stream 210 contacts the 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 the hydrogen sulfide removed from the acid recycle gas stream 210. The recycled hydrogen stream 135 is returned to the renewable transportation fuel production unit 115, as discussed above with respect to FIG.

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

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

[0061] Rich amine stream 310 is sent to heat exchanger 360 to exchange heat with lean amine stream 300. Rich amine stream 310 is sent to common amine regenerator 365 where it is steam stripped to form lean amine stream 300 and overhead amine acid gas stream 370. Overhead amine acid gas stream 370 is sent to amine regenerator overhead condenser 375 where it is separated into liquid reflux 380 and amine acid gas stream 385. Liquid reflux 380 is returned to common amine regenerator 365. Amine acid gas stream 385 is sent to SRU 275.

[0062] In some embodiments, there may be an associated steam reforming zone 390. A sweet naphtha stream 395 and / or a 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 primarily hydrogen, with small amounts of CH4, CO, and N2 in addition to CO2, and 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 may be compressed and sent to the renewable transportation fuels production unit 115. The PSA tail gas stream may be split into a PSA tail gas recycle stream 425 sent to the steam reforming zone 390 and a surplus PSA tail gas stream 430 that may be sent to the fuel gas network.

[0063] In the process 550 shown in Figure 4A, the sour water stripper unit, wastewater treatment plant, and sulfur recovery unit are eliminated. The sour water stream 225 is sent directly to the thermal oxidation system 555 without treatment in the 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 the thermal oxidation system (not shown). The amine acid gas stream 385 is sent directly to the thermal oxidation system 555 without the need for treatment in the sulfur recovery unit. The flue gas 557 is vented to the atmosphere.

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

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

[0066] In some cases, the uncompressed excess PSA tail gas stream 430 from the PSA unit 410 associated with the hydrogen production plant may be sent to a thermal oxidation system 555 for use as a fuel source. The excess PSA tail gas stream 430 is typically recycled to a fired heater in the hydrogen plant at a pressure of 5 psi(g). By sending the excess PSA tail gas stream 430 to the thermal oxidation system 555 at a lower pressure in the range of 2 to 4.9 psi(g), the hydrogen recovery yield at the PSA unit 410 can be increased.

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

[0068] 4B shows an alternative embodiment, in which the recycle gas amine contactor 245 and, consequently, the first portion 295 of the lean amine stream 300 and the first portion 305 of the rich amine stream 310 are not present. The acid recycle gas stream 210 is compressed and the recycle hydrogen stream 135 is returned to the process. The purge stream 211 is sent to the 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 acid recycle gas stream 210. The PSA tail gas stream is sent to a thermal oxidation system 555.

[0069] 5, a slipstream 570 of the lean acid gas stream 220 from the sponge absorber 500 is sent to the thermal oxidation system 555 as a fuel supply 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 may also be reduced. In an alternative embodiment, the recycle gas amine contactor 245 may be eliminated and the PSA unit 212 and associated modifications described in FIG. 4B may be present.

[0070] One embodiment of a thermal oxidation system 555 is illustrated in Figure 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 along 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 may also be sent to the thermal oxidation section 600. The inlet temperature of the thermal oxidation section 600 typically ranges from -30 to 500°C at pressures of -1 kPa(g) to 3000 kPa(g). The outlet temperature typically ranges from 650 to 1300°C at pressures 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 may be used, including, but not limited to, an adiabatic thermal oxidizer chamber. The thermal oxidation section 600 can be forced draft, induced draft, or a combination of both. In some cases, there may be an optional selective non-catalytic reduction (SNCR) section. The inlet temperature of the SNCR section typically ranges from 650 to 1300°C at pressures of -1 kPa(g) to 50 kPa(g). The outlet temperature typically ranges from 650 to 1040°C at pressures of -1 kPa(g) to 50 kPa(g). The residence time in the SNCR section is 0.2 to 1 seconds. The thermal oxidation step is separated from the SNCR step via a choke wall in the vessel. Hydrocarbons are converted to H2O and CO2. Sulfides from sulfur species present in the feedstock (e.g., H2S) are converted to sulfur oxide particulate matter SOx, including but not limited to SO2 and SO3 and H2O. Nitrogen from nitrogen-binding molecules (e.g., NH3) present in the feedstock is converted to nitrogen (N2) and NOx, including, but not limited to, NO, 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. "Consisting essentially of" means that one or more of the gases or vapors are present and that there are no other gases or vapors that require treatment before being released to the atmosphere. The flue gas stream 645 is sent to the 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 pressures of -2 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200-400°C at pressures 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, including, but not limited to, fire tube boilers or water tube boilers. Boiler feed water or oil stream 650 enters waste heat recovery section 605 where a portion is converted to steam or hot oil stream 655 and the remainder exits as blowdown water or oil stream 660. In some cases, the steam can be converted to electricity, for example, using a steam turbine, if desired.

[0073] The recovered waste heat in the steam or hot oil stream 655 can be in the form of low pressure (e.g., less than 350 kPa(g)), medium pressure (e.g., between 350 kPa(g) and 1750 kPa(g)), or high pressure (e.g., greater than 1750 kPa(g)) saturated or superheated steam, hot oil, and / or power. The recovered heat can be used to provide heat to one or more pieces of equipment or process streams in the process to produce renewable transportation fuels, or to other parts of the plant. For example, the recovered waste heat in the steam or hot oil stream 655 can be used to provide heat to the reboiler in the amine treatment unit, to the fractionation column, and to steam for the stripper column or elsewhere in the plant, or other heat requirements.

[0074] The flue gas stream 665 from the optional waste heat recovery section 605 flows to a quench section 610 where the temperature of the flue gas is reduced to saturation temperature using a quench stream 670. The inlet temperature of the quench section 610 is typically in the range of 200-400°C at pressures of -3 kPa(g) to 50 kPa(g). If no waste heat reboiler is present, the inlet temperature can be up to 1300°C. The outlet temperature is typically in the range of 45-150°C at pressures of -3 kPa(g) to 50 kPa(g). The quench stream 670 can include, but is 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 45-150°C at a pressure of -4 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 45-150°C at a pressure of -4 kPa(g) to 50 kPa(g). For example, the SOx removal section 615 may be a scrubbing section where a stream 680 containing aqueous NaOH is introduced into the scrubbing section to react 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, a reducing agent such as NaHSO3 or H2O2 may be included to react with Cl2 to form HCl, which reacts to form NaCl. Alternatively, 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, which then reacts with HCl and NH3 to form NH4Cl. If NH3 is used, no separate reducing agent is required. In this case, aqueous stream 685 contains H2O, NaCl, (NH4)2SO4, and NH4Cl.

[0076] The de-SOx outlet flue gas stream 690 from the SOx removal section 615 has reduced levels of at least one of SOx, NOx, and Cl2 compared to the incoming quenched flue gas stream 675. The de-SOx outlet flue gas stream 690 includes one of H2O, CO2, N2, O2, NOx, dioxins, and furans.

[0077] If NOx is present in the deSOx outlet flue gas stream 690, the deSOx outlet flue gas stream 690 is sent to an optional NOx removal section 620 for removal of 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 deSOx outlet 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 may be a selective catalytic reduction (SCR) section, where 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 may be used, including, but not limited to, ceramic support materials such as titanium dioxide having active catalytic components such as oxides of base metals including TiO2, WO3, and V2O5, or activated carbon based catalysts. The deNOx outlet flue gas stream 700 includes at least one of H2O, CO2, N2, O2, dioxins, and furans.

[0078] If any halogens are present in the feedstock, this may result in the formation of dioxins and / or furans. These compounds must be removed before the gas can be discharged to the atmosphere. If dioxins and / or furans are present in the de-SOx outlet flue gas stream 690 or the de-NOx outlet flue gas stream 700, the de-SOx outlet flue gas stream 690 or the de-NOx outlet flue gas stream 700 are sent to an optional dioxin-furan removal section 625 for removing dioxins and / or furans. Dioxins and furans may 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 exit flue gas stream 705, consisting essentially of one or more of H2O, CO2, N2, and O2, may be discharged into the atmosphere.

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

[0080] If the de-SOx outlet flue gas stream 690 does not contain NOx, dioxins, or furans, then the optional NOx removal section 620 and the optional dioxin-furan removal section 625 are not present. The de-SOx outlet flue gas stream 710, consisting essentially of one or more of HO, CO, N, and O, may be discharged to the atmosphere.

[0081] If the de-SOx outlet flue gas stream 690 contains NOx but no dioxins or furans, then there is no optional dioxin-furan removal section 625. The de-SOx outlet flue gas stream 715, consisting essentially of one or more of HO, CO, N, and O, may be discharged to the atmosphere.

[0082] If the de-SOx outlet flue gas stream 690 contains dioxins or furans but no NOx, then the optional NOx removal section 620 is not present. The de-SOx outlet flue gas stream 690 is sent to the optional dioxin-furan removal section 625. The treated outlet flue gas stream 705, consisting essentially of one or more of H2O, CO2, N2, and O2, may be discharged to the atmosphere.

[0083] If the flue gas stream 645 does not contain SOx, NOx, then the SOx removal section 615, the optional NOx removal section 620, and the optional dioxin-furan removal section 625 are not present. The flue gas stream 720 from the waste heat recovery section 605, consisting essentially of one or more of H2O, CO2, N2, and O2, may be discharged to the atmosphere.

[0084] Another embodiment of a thermal oxidation system 555' is illustrated in Figure 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 are introduced into the thermal oxidation section 800, as described above. One or more of a combustion air stream 830, a make-up natural gas or fuel gas stream 835, and optionally a quench stream 840 are also introduced into the thermal oxidation section 800. Optionally, an excess PSA tail gas stream 430 from a PSA unit 410 associated with a hydrogen production plant and / or a lean acid gas slipstream 570 may also be introduced into the thermal oxidation section 800.

[0086] The inlet temperature of the thermal oxidation section 800 typically ranges from -30 to 500°C at pressures of -1 kPa(g) to 3000 kPa(g). The outlet temperature typically ranges from 650 to 1300°C at pressures of -1 kPa(g) to 50 kPa(g). The residence time in 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 oxidizer chamber. The thermal oxidation section 800 can be forced draft, induced draft, or a combination of both. The inlet temperature of the optional SNCR section typically ranges from 650 to 1300°C at pressures of -1 kPa(g) to 50 kPa(g). The outlet temperature typically ranges from 650 to 1040°C at pressures of -1 kPa(g) to 50 kPa(g). The residence time in the SNCR section is 0.2-1 s. The thermal oxidation step is separated from the SNCR step via a choke wall in the vessel.

[0087] A 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. A boiler feed water or oil stream 850 enters the optional waste heat recovery section 805 where a portion is converted to steam or hot 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 650-1300°C at pressures of -2 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200-400°C at pressures of -2 kPa(g) to 50 kPa(g). Suitable waste heat recovery apparatus and methods are described above. The recovered waste heat in the steam or hot oil stream 855 can be in the form of low, medium or high pressure saturated or superheated steam, hot oil, and / or power. The recovered waste heat in the steam or hot oil stream 855 can be used to provide heat to the reboilers, fractionation columns in the amine treatment unit, and to provide steam for the stripper column or elsewhere in the plant, or other heat requirements.

[0088] A flue gas stream 865 from the optional waste heat recovery section 805 is sent to a SOx removal section, which may comprise 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 200-400°C at a pressure of -3 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 200-400°C at a pressure of -3 kPa(g) to 50 kPa(g). Fresh sorbent 870 and optionally regenerated sorbent 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 used, 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, which react with the 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 comprising 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). Filtration section 815 includes bag filters, and / or ceramic filters, and / or electrostatic precipitators (ESPs). Instrument air purge or high voltage DC 890 is introduced into filtration section 815. In the case of instrument air purge, residual material is purged from the filters. In the case of high voltage stream, the cathode of the ESP is charged. Particulate matter is removed from the ESP by vibration. A dry residue stream 895 including one or more of NaCl, Na2CO3, Na2SO4, NaNO3, CaCl2, CaSO4, Ca2CO3, Ca(NO3)2, MgCl2, MgCO3, MgSO4, and Mg(NO3)2 exits filtration section 815. Filtered flue gas stream 900 includes one or more of H2O, CO2, N2, O2, NOx, dioxins, and furans.

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

[0091] If any halogens are present in the feedstock, this may result in the formation of dioxins and / or furans. These compounds must be removed before the gas can be discharged to the atmosphere. If dioxins and / or furans are present in the filtered flue gas stream 900 or the deNOx outlet flue gas stream 910, the filtered flue gas stream 900 or the deNOx outlet flue gas stream 910 is sent to an optional dioxin-furan removal section 825 to remove dioxins and / or furans. Dioxins and furans can be removed using a catalyst or by co-injecting activated carbon. For example, with a catalyst such as a catalyst containing TiO2, WO3, and V2O5, the dioxins and furans react with the catalyst to form traces of CO2, H2O, and HCl. In the case of activated carbon, it is co-injected with the dry sorbent 871 upstream of the SOx removal section 810. The 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 150-250° C. at a pressure of −7 kPa(g) to 50 kPa(g). The outlet temperature is typically in the range of 150-250° C. at a pressure of −7 kPa(g) to 50 kPa(g). The treated outlet flue gas stream 915, consisting essentially of one or more of H2O, CO2, N2, and O2, may be discharged to the atmosphere.

[0092] If the filtered flue gas stream 900 does not contain NOx, dioxins, or furans, then the optional NOx removal section 820 and the optional dioxin-furan removal section 825 are not present. The filtered flue gas stream 920, consisting essentially of one or more of HO, CO, N, and O, may be discharged to the atmosphere.

[0093] If the filtered flue gas stream 900 contains NOx but no dioxins or furans, then there is no optional dioxin-furan removal section 825. The de-NOx outlet flue gas stream 925, consisting essentially of one or more of HO, CO, N, and O, may be discharged to the atmosphere.

[0094] If the filtered flue gas stream 900 contains dioxins or furans but no NOx, then the optional NOx removal section 820 is not present. The filtered flue gas stream 900 is sent to the optional dioxin-furan removal section 825. The treated outlet flue gas stream 915, consisting essentially of one or more of H2O, CO2, N2, and O2, may be discharged to the atmosphere.

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

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

[0097] The exhaust steam stream 1000 may be sent to an optional secondary heat exchanger 1005. The exhaust steam stream 1000 may 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 a second side of the secondary heat exchanger 1005.

[0098] The process stream is sent to a first side of a secondary heat exchanger 1005. There can be one or more secondary heat exchangers 1005 depending on the temperature of the exhaust vapor stream 1000 and the number of process streams being heated.

[0099] The process streams may be all or a portion of the combustion air stream 630 and / or all or a portion of the boiler feed water or oil stream 650 .

[0100] The process stream is heated by heat exchange with the exhaust vapor stream 1000 which results in cooling of the exhaust vapor stream 1000 to form a first cooled exhaust vapor 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 increasing the efficiency of steam generation or hot oil production.

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

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

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

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

[0106] The first cooled exhaust steam stream 1010 entering the primary heat exchanger 1015 has a temperature above 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 an exhaust stack and released to the atmosphere.

[0107] In other cases, the temperature is not lowered 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 lower the temperature of the second cooled exhaust steam stream 1025 to a temperature below the dew point that leads to the formation of condensed water. The cooling medium for the tertiary heat exchanger can be, for example, cold / ambient air or cold water.

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

[0109] The heated sour water stream 1040 from the primary heat exchanger 1015 is reduced in pressure through a valve 1045 (e.g., a throttling valve or a letdown valve) to a lower pressure (e.g., a pressure of 1-20 psig) than the primary heat exchanger 1015 and sent to a flash tank 1050. Upon entering the lower pressure flash tank 1050, the higher pressure heated sour water stream 1040 is flashed into a vapor stream 1055 and a liquid stream 1060. The vapor stream 1055 and liquid stream 1060 are sent to the thermal oxidation section 600 of the thermal oxidation system 555. An optional pump and / or compressor 1065 may be in line with the liquid stream 1060.

[0110] Figure 9 illustrates an alternative energy recovery system to the thermal oxidation system 555 of Figure 6. In this arrangement, the sour water stream 225 (with optional compression in 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 may be compressed in an optional pump or compressor 1075 and sent to a first side of the primary heat exchanger 1015. The heated sour water stream 1040 is then passed through a valve 1045 to reduce pressure and returned to the flash tank 1050 for further separation.

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

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

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

[0114] The exhaust steam stream 1000 may be routed to a second side of an optional secondary heat exchanger 1005. A process stream is routed to a first side of the secondary heat exchanger 1005. There may be one or more secondary heat exchangers 1005 depending on the temperature of the exhaust steam stream and the number of process streams being heated.

[0115] The process streams may be all or a portion of the combustion air stream 830 and / or the boiler feed water or oil stream 850 .

[0116] The process streams are heated by heat exchange with the exhaust steam stream 1000, which in turn cools the exhaust steam stream 1000. 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 increasing the efficiency of steam generation or hot oil production.

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

[0118] The first cooled exhaust vapor stream 1010 is passed to a second side of the primary heat exchanger 1015. Alternatively, in the absence of the secondary heat exchanger 1005, the exhaust vapor 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 above 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 an exhaust stack and released to the atmosphere.

[0120] In other cases, the temperature is not lowered 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 lower the temperature of the second cooled exhaust steam stream 1025 to a temperature below the dew point that leads to the formation of condensate. The cooling medium for the tertiary heat exchanger 1030 can be, for example, cold / ambient air or cold water.

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

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

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

[0124] As used herein, the terms "unit," "zone," and "section" can refer to an area that includes one or more pieces of equipment, depending on the type of unit, zone, or section, and / or one or more subzones or subsections. Equipment can include, but is 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, subsections, zones, or subzones.

[0125] Specific Embodiments While the following is described in conjunction with specific embodiments, it will be understood that this description is illustrative and not intended to limit the scope of the foregoing description and the appended claims.

[0126] A first embodiment of the invention is a process for treating acid gas and sour water effluent streams in a process for producing renewable transportation fuels, the process comprising: thermally oxidizing in a thermal oxidation system at least one of a sour water stream from a cryogenic separation and fractionation section of the renewable transportation fuels process and an amine acid gas stream from an acid gas processing section of the renewable transportation fuels process, wherein the sour water stream is not treated in a sour water stripper unit prior to being thermally oxidized in the thermal oxidation system, and the amine acid gas stream is not treated in a sulfur recovery unit prior to being thermally oxidized in the thermal oxidation system; 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 HO, CO, N, O, SOx, NOx, HCl, Cl, dioxins, and furans; and, optionally, waste heat recovery. section, recovering waste heat from the flue gas stream; and removing at least one of SOx, HCl, and Cl2 from the flue gas stream in a SOx removal section to form a de-SOx outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxins, and furans, 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 de-SOx outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxins, and furans. and contacting a caustic or NH3-based solution with the quenched flue gas stream in a scrubbing section to form a de-SOx outlet flue gas stream and a liquid stream comprising at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl; or contacting the flue gas stream with a caustic or NH3-based solution in a SOx reaction section to form a de-SOx outlet flue gas stream and a liquid stream comprising at least one of NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2,and 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, dioxins, and furans; and filtering, in a filtration section, 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 produce a de-SOx outlet flue gas stream. forming a de-SOx outlet flue gas stream comprising: forming a de-SOx outlet flue gas stream comprising a NOx removal section; optionally removing NOx from the de-SOx outlet flue gas stream in a NOx removal section to form a de-NOx outlet flue gas stream consisting essentially of at least one of HO, CO, N, O, dioxins, and furans; and optionally removing dioxins, furans, or both from the de-SOx outlet flue gas stream or the de-NOx 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 HO, CO, N, and O. An embodiment of the present invention is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, wherein the sour water stream comprises at least one of a cold separator sour water stream from a cold separator in the 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. An embodiment of the present invention is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, wherein the amine acid gas stream comprises a regenerator amine acid gas stream from a common amine regenerator overhead condenser and reflux drum. An embodiment of the present invention is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, wherein the amine acid gas stream comprises a regenerator amine acid gas stream from a common amine regenerator overhead condenser and reflux drum.Any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, further comprising: contacting a first portion of the lean amine stream with a cold separator sour water stream from a cold separator in the cold separation and fractionation section in a recycle gas amine contactor to form a first portion of a rich amine stream; contacting a first portion of the lean amine stream with a sour liquefied petroleum gas (LPG) stream from a debutanizer receiver vessel in the cold separation and fractionation section in a debutanizer receiver amine contactor to form a second portion of a rich amine stream; and contacting a first portion of the lean amine stream with a sour liquefied petroleum gas (LPG) stream from a debutanizer receiver vessel in the cold separation and fractionation section in a sponge absorber lean gas overhead amine contactor to form a second portion of a rich amine stream. contacting a third portion of the amine stream with a lean acid gas stream from a sponge absorber of the cryogenic separation and fractionation section to form a third portion of a rich amine stream; regenerating at least one of the first portion, the second portion, and the third portion 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. An embodiment of the present invention is one, any, or all of the previous embodiment of this paragraph through the first embodiment of this paragraph, further comprising: in the pressure swing adsorption unit, separating a purge stream from an acid recycle gas stream from a cryogenic separator in a cryogenic separation and fractionation section into a recycled hydrogen stream and a PSA tail gas stream, combining the recycled hydrogen stream with the acid recycle gas stream, and introducing the PSA tail gas stream as fuel into a thermal oxidation system; in the cryogenic separation and fractionation section in a debutanizer receiver amine contactor, contacting a second portion of the lean amine stream with an acid liquefied petroleum gas (LPG) stream to form a second portion of a rich amine stream; and in the cryogenic separation and fractionation section in a sponge absorber lean gas overhead amine contactor,contacting a third portion of the lean amine stream with the lean acid gas stream from the sponge absorber to form a third portion of a rich amine stream, regenerating at least one of the 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.An embodiment of the present invention is one, any, or all of the previous embodiment to the first embodiment of this paragraph, further comprising preheating the sour water stream using steam from a process for producing renewable transportation fuels or from heat recovered from the waste heat recovery section prior to thermally oxidizing the sour water stream. An embodiment of the present invention is one, any, or all of the previous embodiment of this paragraph through the first embodiment of this paragraph, further comprising: introducing the renewable feedstock into a guard bed to remove contaminants from the renewable feedstock, including one or more of alkali metals, oxygen compounds, sulfur compounds, and nitrogen compounds; processing 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. An embodiment of the present invention is one, any or all of the preceding embodiment of this paragraph through the first embodiment of this paragraph, wherein separating and fractionating the reaction effluent includes separating the reactor effluent into a liquid hydrocarbon stream, a low temperature separator recycle acid gas stream, and a low temperature separator sour water stream in a low temperature separator; stripping the liquid hydrocarbon stream into a stripper overhead stream and a stripper bottom stream; and separating the stripper overhead stream into a stripper receiver liquid stream and a low temperature separator sour water stream in a stripper receiver.contacting the stripper receiver off-gas 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, a debutanizer bottoms stream; separating the debutanizer overhead stream in the debutanizer receiver into a sour 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. An embodiment of the present invention is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, wherein the sour water stream comprises at least one of a low temperature separator sour water stream, a stripper receiver sour water stream, and a debutanizer receiver sour water stream. An embodiment of the present invention is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, wherein the sour water stream comprises at least one of a low temperature separator sour water stream, a stripper receiver sour water stream, and a debutanizer receiver sour water stream. An embodiment of the present invention is any one, any or all of the preceding embodiments of this paragraph through the first embodiment of this paragraph, wherein the and contacting 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. An embodiment of the present invention is one, any, or all of the previous embodiment to the first embodiment of this paragraph, wherein quenching the flue gas stream includes quenching the flue gas stream with at least one of air, a quenched flue gas stream, a de-SOx outlet flue gas stream, a de-NOx outlet flue gas stream, a treated outlet flue gas stream, and water. An embodiment of the invention is one, any, or all of the previous embodiments of this paragraph through the first embodiment of this paragraph, further comprising introducing an uncompressed pressure swing adsorption (PSA) tail gas stream from a PSA unit connected to the hydrogen production plant to the thermal oxidation system as a fuel source.An embodiment of the invention is one, any, or all of the previous embodiments of this paragraph through the first embodiment of this paragraph, further comprising introducing a slipstream of the lean acid gas stream from the sponge absorber to the thermal oxidation system as a fuel source.An embodiment of the present invention is one, any, or all of the previous embodiment of this paragraph to the first embodiment of this paragraph, further comprising: passing the sour water stream to a first side of the primary heat exchanger; passing an exhaust steam stream from the thermal oxidation system to a second side of the primary heat exchanger, the exhaust steam stream comprising a treated outlet flue gas stream, a de-NOx outlet flue gas stream, or a de-SOX outlet flue gas stream; transferring heat from the exhaust steam stream to the sour water stream, cooling the exhaust steam stream to form a cooled exhaust steam stream, and heating the sour water stream to form a heated sour water stream; reducing the pressure of the heated sour water stream; passing the reduced pressure heated sour water stream through a flash tank having a pressure lower than the pressure of the primary heat exchanger to form a steam stream and a liquid stream; passing the steam stream and the liquid stream through a thermal oxidation section of the thermal oxidation system; and passing the cooled exhaust stream to an exhaust stack. An embodiment of the present invention is one, any or all of the previous embodiment of this paragraph to the first embodiment of this paragraph, further comprising passing a process stream to a first side of a secondary heat exchanger, the process stream being at least one of a combustion air stream and a boiler feed water or oil stream, and passing the exhaust steam stream to a second side of a secondary heat exchanger to reduce the temperature of the exhaust steam stream and heat the at least one process stream and generate a second cooled exhaust steam stream and a heated exhaust steam stream prior to passing the exhaust steam stream to the primary heat exchanger. forming at least one of a combustion air stream and a heated boiler feed water or oil stream; passing the second cooled exhaust steam stream through a primary heat exchanger, where passing the exhaust steam stream from the thermal oxidation system to a 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 at least one of passing the heated combustion air stream through a thermal oxidation section of the thermal oxidation system and passing the heated boiler feed water or oil stream through a waste heat recovery section.An embodiment of the present invention is any one, any or all of the previous embodiment of this paragraph through the first embodiment of this paragraph, further including: prior to passing the sour water stream to the primary heat exchanger, introducing the sour water stream into a flash tank to form liquid and vapor, and compressing at least a portion of the liquid, where 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, where depressurizing the heated sour water stream includes depressurizing the heated compressed liquid from the primary heat exchanger, and where passing the depressurized heated sour water stream to the flash tank includes passing the depressurized heated compressed liquid to the flash tank. An embodiment of the present invention is any one, any or all of the previous embodiment of this paragraph through the first embodiment of this paragraph, where the exhaust steam stream is cooled to a sub-dew point temperature in the primary heat exchanger to condense water in the exhaust steam stream to form a first condensed stream. An embodiment of the invention is any one, any or all of the previous embodiments to the first embodiment of this paragraph, further comprising passing the first condensed stream to a quench section. An embodiment of the invention is any one, any or all of the previous embodiments to the first embodiment of this paragraph, further comprising passing the first condensed stream to a quench section. An embodiment of the invention is any one, any or all of the previous embodiments to the first embodiment of this paragraph, further comprising passing the first condensed stream to a quench section. An embodiment of the invention is any one, any or all of the previous embodiments to the first embodiment of this paragraph, further comprising compressing the sour water stream to the primary heat exchanger before passing the sour water stream to the primary heat exchanger.

[0127] A 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 into a guard bed to remove contaminants from the renewable feedstock, the contaminants including one or more of alkali metals, oxygen compounds, sulfur compounds, and nitrogen compounds; 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 into a liquid hydrocarbon stream, a low temperature separator recycle acid gas stream, and a low temperature separator sour water stream in a low temperature separator; stripping the liquid hydrocarbon stream into a stripper overhead stream and a stripper bottom stream; separating the stripper overhead stream into a stripper receiver liquid stream, a stripper receiver off-gas stream, and a stripper receiver sour water stream in a stripper receiver; contacting the stripper receiver off-gas stream with a sponge absorber to remove the sponge absorbent. forming a collector 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, a debutanizer bottoms stream; separating the debutanizer overhead stream into an acid liquefied petroleum gas (LPG) stream, a debutanizer receiver sour water stream, and reflux in the debutanizer receiver; 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 the lean amine stream with a 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 an acid LPG stream from the debutanizer receiver in a debutanizer receiver amine contactor to form a second portion of a rich amine stream;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 a 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; and thermally oxidizing at least one of the 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, and the sour water stream is not treated in a sulfur recovery unit before being thermally oxidized in the thermal oxidation system. a separator sour water stream, 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, wherein thermally oxidizing at least one of the sour water stream and the amine acid gas stream comprises: 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, dioxins, and furans; 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 de-SOx outlet flue gas stream consisting essentially of at least one of H2O, CO2, N2, O2, NOx, dioxins, and furans,and removing at least one of Cl2 includes quenching the flue gas stream in a quenching section to form a quenched flue gas stream, and contacting a caustic solution or an NH3-based solution with the quenched flue gas stream in a scrubbing section to form a deSOx outlet flue gas stream and a liquid stream comprising at least one of H2O, Na2SO3, Na2SO4, NaHSO3, Na2CO3, NaCl, (NH4)2SO4, and NH4Cl; or in a SOx reaction section, the flue gas stream is reacted with reactants including at least one of NaHCO3, NaHCO3·Na2CO3·2(H2O), CaCO3, Ca(OH)2, and Mg(OH)2 to produce a 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. forming a de-SOx outlet flue gas stream, comprising: forming a reaction section flue gas stream; 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 de-SOx outlet flue gas stream; and optionally filtering the reaction section flue gas stream in a NOx removal section from the de-SOx outlet flue gas stream. and optionally removing dioxins, furans, or both from the de-SOx outlet flue gas stream or the de-NOx 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 HO, CO, N, and O. One embodiment of the present invention is one, any, or all of the previous embodiment of this paragraph to the second embodiment of this paragraph,Prior to thermally oxidizing the sour water stream, the method further comprises preheating the sour water stream using steam from a process for producing renewable transportation fuels or from heat recovered from the waste heat recovery section.An embodiment of the invention is any one, any or all of the previous to the second embodiment of this paragraph, wherein quenching the flue gas stream comprises quenching the flue gas stream with at least one of air, a quenched flue gas stream, a de-SOx outlet flue gas stream, a de-NOx outlet flue gas stream, a treated outlet flue gas stream, and water.An embodiment of the invention is any one, any or all of the previous to the second embodiment of this paragraph, wherein the method further comprises introducing an uncompressed pressure swing adsorption (PSA) tail gas stream from a PSA unit connected to the hydrogen production plant to the thermal oxidation system as a fuel supply. An embodiment of the present invention is one, any, or all of the previous embodiment of this paragraph through the second embodiment of this paragraph, further comprising introducing a slipstream of the lean acid gas stream from the sponge absorber to the thermal oxidation system as a fuel source.

[0128] Without further elaboration, it is believed that, using the preceding description, one skilled in the art can utilize the present invention to its fullest extent and easily ascertain the essential characteristics of the present invention without departing from the spirit and scope of the present invention, and can make various changes and modifications to the present invention to adapt it to various uses and conditions. The preceding preferred specific embodiments are therefore to be construed as merely illustrative, and are not limitative of the remainder of the disclosure in any way, but are intended to cover various modifications and equivalent arrangements falling within the scope of the appended claims.

[0129] Above, all temperatures are set forth in degrees Celsius and all parts and percentages are by weight unless otherwise stated.

Claims

1. 1. A process for treating acid gas and sour water effluent streams in a process for producing renewable transportation fuels, comprising: thermally oxidizing in a thermal oxidation system (555) at least one of a sour water stream (225) from a cryogenic separation and fractionation section (205) of the process for producing renewable transportation fuels and an amine acid gas stream (385) from an acid gas processing section of the process for producing renewable transportation fuels; wherein the sour water stream (225) is not treated in a sour water stripper unit prior to being thermally oxidized in the thermal oxidation system (555), and wherein the amine acid gas stream (385) is not treated in a sulfur recovery unit prior to being thermally oxidized in the thermal oxidation system (555); thermally oxidizing the at least one of the sour water stream (225) and the amine acid gas stream (385); In a thermal oxidation section (600), the at least one of the sour water stream (225) and the amine acid gas stream (385) is thermally oxidized to produce H ２ O, CO ２ , N ２ , O ２ , SOx, NOx, HCl, Cl ２ forming a flue gas stream (645) comprising at least one of: In a SOx removal section (615), SOx, HCl, and Cl are removed from the flue gas stream (645). ２ At least one of the following is removed to obtain H ２ O, CO ２ , N ２ , O ２ forming a de-SOxed outlet flue gas stream (690) comprising at least one of NOx, dioxins, and furans; Including, SOx, HCl, and Cl from the flue gas stream ２ removing said at least one of quenching the flue gas stream (645) in a quench section (610) to form a quenched flue gas stream (675); and In the scrubbing section, caustic solution or NH ３ A system solution (680) is contacted with the quenched flue gas stream (675) to produce the deSOx outlet flue gas stream (690) and H ２ O, Na ２ SO ３ , Na ２ SO ４ , NaHSO ３ , Na ２ CO ３ , NaCl, (NH ４ ) ２ SO ４ , and N.H. ４ and forming a liquid stream (685) comprising at least one of: Or, SOx, HCl, and Cl from the flue gas stream ２ removing said at least one of In a SOx reaction section (810), the flue gas stream (845) is reacted with NaHCO ３ , NaHCO ３ ・Na ２ CO ３ ・(H ２ O), CaCO ３ , Ca(OH) ２ , and Mg(OH) ２ to react with reactants comprising at least one of 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 forming a reaction section flue gas stream (880) comprising at least one of NOx, dioxins, and furans; and The reaction section flue gas stream (880) is filtered in a filtration section (815) 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 said deSOx outlet flue gas stream (900). process.

2. 2. The process of 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.

3. contacting a first portion (295) of the lean amine stream (300) with an acid recycle gas stream (210) from a low temperature separator (450) in said low temperature separation and fractionation section (205) in a recycle gas amine contactor (245) to form a first portion (305) of a rich amine stream (310); or separating a purge stream (211) from an acid recycle gas stream (210) from a low temperature separator (450) in said low temperature separation and fractionation section (205) in a pressure swing adsorption unit (212) into a recycle hydrogen stream (213) and a PSA tail gas stream (214), combining said recycle hydrogen stream (213) with said acid recycle gas stream (210), and introducing said PSA tail gas stream (214) as a fuel into said thermal oxidation system (555); contacting a second portion (315) of the lean amine stream (310) with a sour liquefied petroleum gas (LPG) stream (215) from a debutanizer receiver vessel (525) in said cryogenic separation and fractionation section (205) in a debutanizer receiver amine contactor (320) to form a second portion (325) of a rich amine stream (310); and at least one of contacting a third portion (335) of the lean amine stream (300) with a lean acid gas stream (220) from a sponge absorber (500) in said cryogenic separation and fractionation section (205) in a sponge absorber-lean gas overhead amine contactor (345) to form a third portion (350) of a rich amine stream (310); regenerating at least one of the first portion (305), the second portion (325), and the third portion (350) of the rich amine stream (310) in the common amine regenerator (365) to form the lean amine stream (300) and an overhead regenerator amine acid gas stream (370); separating said overhead regenerator amine acid gas stream (370) in an amine regenerator overhead condenser (375) into said regenerator amine acid gas stream (385) and a reflux liquid stream (380); 3. The process of claim 2, further comprising refluxing said reflux liquid stream (380) to said common amine regenerator (365).

4. A process as described in any one of claims 1 to 3, wherein thermally oxidizing at least one of the sour water stream (225) and the amine acid gas stream (385) further comprises recovering waste heat from the flue gas stream (645) in a waste heat recovery section (605).

5. The process of any one of claims 1 to 4, wherein thermally oxidizing the at least one of the sour water stream (225) and the amine acid gas stream (385) further comprises removing NOx from the de-SOx outlet flue gas stream (690) in a NOx removal section (620) to form a de-NOx outlet flue gas stream (700) comprising at least one of H2O, CO2, N2, O2, dioxins, and furans.

6. The process of any one of claims 1 to 5, wherein thermally oxidizing at least one of the sour water stream (225) and the amine acid gas stream (385) further comprises removing dioxins, furans, or both from the de-SOx outlet flue gas stream (690) or the de-NOx outlet flue gas stream (700) in a dioxin-furan removal section (625) to form a treated outlet flue gas stream (705) consisting of at least one of H2O, CO2, N2, and O2.

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