Process for hydrotreating a feed stream containing biorenewable feedstocks with treatment of an off-gas stream - Patent Application 20070122999

Abstract

A process for hydrotreating a feed stream comprising a biorenewable feedstock is disclosed. The process includes hydrotreating the feed stream in the presence of a hydrotreating hydrogen stream and a hydrotreating catalyst to provide a hydrotreated stream. The hydrotreated stream is separated into a hydrotreated liquid stream and a hydrotreated gas stream. The hydrotreated liquid stream is subjected to stripping to provide a stripper off-gas stream. At least a portion of the stripper off-gas stream is contacted with a caustic stream to provide a sulfur-lean gas stream and a sulfur-rich caustic stream. The sulfur-rich caustic stream is further processed to provide a treated gas stream.

Description

[Technical Field]

[0001] (Priority Claim) This application claims priority to U.S. Patent No. 17 / 498,987, filed October 12, 2021, which is incorporated herein in its entirety.

[0002] FIELD OF THE INVENTION The field relates to processes for hydrotreating feed streams that include biorenewable feedstocks. Specifically, the field relates to processes for hydrotreating feed streams that include biorenewable feedstocks that involve the treatment of caustic and spent caustic process off-gases. [Background technology]

[0003] As the demand for reduced carbon emissions increases, there is growing interest in producing fuels and blending components from sources other than crude oil. These sources, often referred to as biorenewable sources, include, but are not limited to, vegetable oils such as corn, rapeseed, canola, and soybean; microbial oils such as algae oil; animal fats such as inedible tallow; fish oil; and various waste streams such as yellow and brown grease and sewage sludge. A common feature of these sources is that they are composed of glycerides and free fatty acids (FFAs). Both triglycerides and FFAs contain aliphatic carbon chains with 8 to 24 carbon atoms. The aliphatic carbon chains in triglycerides or FFAs can be fully saturated or mono-, di-, or polyunsaturated.

[0004] Hydroprocessing can include processes that convert hydrocarbons into more valuable products in the presence of a hydroprocessing catalyst and hydrogen. Hydrotreating is a process in which hydrogen is contacted with hydrocarbons in the presence of a hydrotreating catalyst that is primarily active for removing heteroatoms, such as sulfur, nitrogen, oxygen, and metals, from the hydrocarbon feedstock. Hydrotreating can saturate hydrocarbons with double and triple bonds, such as olefins.

[0005] The production of hydrocarbon products in the diesel boiling range can be achieved by hydrotreating biorenewable feedstocks. Biorenewable feedstocks can be hydroprocessed by hydrotreating to remove metals and deoxygenate oxygenated hydrocarbons, followed by hydroisomerization to improve the low temperature fluidity of the product diesel. Hydroisomerization, or hydrodewaxing, is a hydroprocessing process that, in the presence of hydrogen and a hydroisomerization catalyst, increases the alkyl branching on the hydrocarbon backbone, improving the low temperature fluidity of the hydrocarbon. Hydroisomerization, as used herein, includes hydrodewaxing.

[0006] Hydroprocessing of biorenewable feedstocks deoxygenates oxygenated hydrocarbons, resulting in the production of HO, CO, and CO in the hydroprocessed effluent. Carbon dioxide can be removed from the recycle hydrogen gas in an amine recycle gas scrubber. However, reducing the carbon monoxide concentration requires purging or other means, such as the water-gas shift reaction to form carbon dioxide. Carbon monoxide is poisonous to hydroprocessing catalysts and must therefore be removed to avoid the accumulation of deactivating levels of carbon monoxide.

[0007] Biorenewable feedstocks contain fewer sulfur-containing hydrocarbons than mineral feedstocks. Therefore, hydroprocessing of biorenewable feedstocks produces relatively less hydrogen sulfide. Hydroprocessing catalysts require sulfiding to ensure the catalyst is activated.

[0008] During the recovery of products from the hydroprocessing stream, a gas stream commonly referred to as "recycle gas" is produced containing impurities such as carbon oxides, hydrogen sulfide, and light hydrocarbons. The recycle gas stream can be subjected to a treatment step to recover valuable products. Typically, the treatment step for the recycle gas stream includes an amine treatment step in a recycle gas scrubber. However, a typical amine treatment for recycle also includes a sulfur recovery unit along with a recycle gas scrubber to remove sulfur from the gas stream coming from the amine treatment unit, and the remaining gas stream is taken out as a treatment stream. Thus, amine treatment can reduce the available sulfur in the recycle gas. Sulfur removal then increases the sulfur injection rate into the process required to ensure the catalyst is activated. Such an amine treatment step can increase the overall capital and operating costs of the process.

[0009] In addition, together with the recycle gas, an "off-gas" stream may also be produced after recovering products from the hydroprocessing stream. Typically, an amine treatment step in an off-gas scrubber is used to remove hydrogen sulfide from the off-gas stream. However, such amine treatment for the off-gas stream requires an amine regeneration unit and a sulfur recovery unit accompanied by the off-gas scrubber, which have high capital and operating costs. If the recycle gas scrubber for amine treatment of the recycle gas is considered to be omitted to save sulfur injection, the total amine required to treat the off-gas and recovered hydrocarbons, such as LPG hydrocarbons, in the amine treatment unit may be reduced, and the cost of the amine treatment unit may also be reduced. However, the cost of the amine treatment unit is still complicated, and the economic scale for a very small amine and sulfur recovery unit for only the off-gas stream is low.

[0010] It would therefore be desirable to provide a process and apparatus for producing distillate hydrocarbons from biorenewable feedstocks that ensures sufficient sulfidation of the hydrotreating catalyst. It would also be desirable to provide a cost-effective process and apparatus for alternative treatment of the off-gas stream to save capital expenditures for the biorenewable feedstock and minimize sulfur injection rates. Summary of the Invention

[0011] The present disclosure provides a process and apparatus for hydrotreating a feedstock in which a caustic treatment is used to treat / purify the off-gas stream. The process does not include an amine treatment step for the off-gas stream. The process ensures optimal sulfur presence in the recycle gas for the process. The process reduces the amount of sulfur that needs to be added to the biorenewable feedstock to ensure proper sulfidation of the hydrotreating catalyst. Applicants have discovered a unique caustic treatment step for the off-gas stream that reduces the overall amount of caustic required for treatment and also produces less spent caustic compared to typical caustic treatment processes. The process also provides an efficient disposal step for the spent caustic. [Brief explanation of the drawings]

[0012] [Figure 1]

[0013] FIG. 1 is a simplified process flow diagram of the present disclosure. definition The term "communication" means operatively permitting the flow of material between the listed components.

[0014] The term "downstream communication" means that at least a portion of the material flowing to the object in the downstream communication can operatively flow from the object in communication. The term "upstream communication" means that at least a portion of the material flowing from the object in the upstream communication can operatively flow to the communicating object.

[0015] The term "direct communication" means that a stream from an upstream component enters a downstream component without passing through a fractionation or conversion unit and undergoing a change in composition by physical fractionation or chemical conversion.

[0016] The term "indirect communication" means that a stream from an upstream component passes through a fractionation or conversion unit and undergoes a change in composition by physical fractionation or chemical conversion before entering a downstream component.

[0017] The term "bypass" means that an object is out of downstream communication with a bypass subject, at least to the extent that it bypasses. The term "column" refers to a distillation column or columns for separating one or more components of different volatility. Unless otherwise specified, each column includes a condenser at the top of the column for condensing and refluxing a portion of the overhead stream that returns to the top of the column, and a reboiler at the bottom of the column for vaporizing a portion of the bottom stream and returning it to the bottom of the column. The feed to a column may be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. The overhead and bottom lines refer to the net lines from column to column downstream of any reflux or reboil. A stripper column may omit the reboiler at the bottom of the column and instead provide the required heat and driving force for separation from a fluidized inert medium such as steam. A stripper column typically feeds the feed to the top tray and removes the main product from the bottom.

[0018] As used herein, the term "component-rich stream" means that the rich stream exiting the vessel has a higher concentration of the component than the feed to the vessel. As used herein, the term "component lean stream" means that the lean stream exiting the vessel has a lower concentration of the component than the feedstock to the vessel.

[0019] As used herein, the term "boiling point temperature" means the atmospheric equivalent boiling point (AEBP) calculated from the observed boiling point and the distillation pressure calculated using the equation provided in ASTM D86 or ASTM D2887.

[0020] As used herein, the term "True Boiling Point" (TBP) refers to a test method for determining the boiling point of a substance, which test method corresponds to ASTM D-2892 for producing liquefied gases, distillate fractions, and residual oils of standardized quality for which analytical data can be obtained, and for determining the yield of said fractions by both mass and volume, where a graph of temperature versus mass % distilled is produced using 15 theoretical plates in a column with a reflux ratio of 5:1.

[0021] As used herein, the terms "T5" or "T95" mean the temperature at which 5 percent or 95 percent, by weight, of a sample boils, using ASTM D-86 or TBP, respectively, as the case may be.

[0022] As used herein, the term "initial boiling point" (IBP) means the temperature at which a sample begins to boil using ASTM D2887, ASTM D-86, or TBP, as the case may be.

[0023] As used herein, the term "end point" (EP) means the temperature at which the sample has completely evaporated using ASTM D2887, ASTM D-86, or TBP, as the case may be.

[0024] As used herein, the term "diesel boiling range" means that hydrocarbons boil within the range of "diesel cut points" including an IBP of 125°C (257°F) to 175°C (347°F) or a T5 of 150°C (302°F) to 200°C (392°F) and a T95 of 343°C (650°F) to 399°C (750°F) using the TBP distillation method.

[0025] As used herein, the term "diesel conversion" means converting a feed boiling above the diesel cut point to a material boiling below the diesel cut point within the diesel boiling range.

[0026] As used herein, the term "separator" means a vessel having an inlet and at least an overhead vapor outlet and a bottoms liquid outlet, and may also have an aqueous outlet from a boot. A flash drum is a type of separator that may be in downstream communication with a separator that may be operated at a higher pressure.

[0027] As used herein, the term "predominant" or "predominantly" means more than 50%, suitably more than 75%, preferably more than 90%. The term “C x " should be understood to refer to a molecule having the number of carbon atoms represented by the subscript "x". Similarly, the term "C x The term "C - " refers to a molecule containing less than or equal to x, preferably x and less, carbon atoms. x "+" refers to a molecule having more than or equal to x, preferably x and more, carbon atoms. DETAILED DESCRIPTION OF THE INVENTION

[0028] Hydrotreating units can process biorenewable feedstocks containing natural oils and fats, such as triglycerides and free fatty acids from animal and plant materials, to convert them into green jet fuel and / or diesel. The biorenewable feedstock undergoes hydrodemetallization and hydrodeoxygenation reactions, followed by hydroisodewaxing, hydroisomerization, and / or hydrocracking. In two-stage units, hydrogen sulfide produced in the hydrodemetallization and hydrodeoxygenation reactions is removed from the interstage hydrotreated stream; therefore, the hydroisodewaxing, hydroisomerization, or hydrocracking reactions occur in a sweet environment. "Sweet" indicates that sulfur is removed from the environment, while "sour" indicates that sulfur is present in the environment. In single-stage units, hydrogen sulfide remains in a sour environment for downstream hydroisodewaxing, hydroisomerization, or hydrocracking reactions.

[0029] Base metal hydrotreating catalysts for hydrodeoxygenation and hydrodemetallization are sulfided to be catalytically active. These hydrotreating reactions produce water and carbon oxides. A reducing hydrogen environment tends to strip sulfur from the hydrotreating catalyst, resulting in deactivation. Because biorenewable feeds do not contain much sulfur, sulfur is injected into the fresh feed in the form of dimethyl disulfide, polysulfides, disulfide oils, or refinery sour gas containing hydrogen sulfide to maintain catalytic activity. This process allows for a reduction in the amount of sulfur injected into the system with the fresh feed by maintaining sufficient hydrogen sulfide in the recycle gas.

[0030] Furthermore, for hydrotreating units processing feeds containing biorenewable feedstocks, the volume of carbon oxides being produced, particularly carbon dioxide, varies as the reaction progresses over time. An acid gas treatment system is required to remove carbon dioxide to maintain hydrogen purity. Additionally, the carbon monoxide produced is a catalyst poison that inhibits the activity of hydrotreating catalysts. Because carbon monoxide is converted to carbon dioxide via the water-gas shift reaction, removing carbon dioxide via an amine solvent absorption column keeps carbon monoxide concentrations low. Traditionally, an amine acid gas treatment system is installed in the recycle gas circuit, and because hydrogen sulfide is a stronger acid than carbon dioxide, both carbon dioxide and hydrogen sulfide are removed by this system.

[0031] The present disclosure provides a process that does not use an amine treatment unit for the off-gas stream and recycle gas stream. The process includes a caustic treatment step for the off-gas stream from a product recovery unit. Applicants have found that the off-gas stream can contain a relatively high volume of carbon dioxide compared to the volume of hydrogen sulfide present in the off-gas stream. The variable volume of carbon dioxide being produced in the hydrotreating unit is related to the volume of carbon dioxide present in the off-gas stream. Applicants have discovered that their process includes selective removal of hydrogen sulfide over carbon dioxide present in the off-gas stream.

[0032] A process for caustic treating an off-gas stream without an amine treatment unit on the recycle gas circuit saves capital and operating costs for the process. In a typical amine treatment unit, there is a sulfur recovery unit to condense any sulfur from the gas stream coming from the amine treatment unit and remove the remaining gas stream. The disclosed process omits the amine treatment unit and the associated sulfur recovery unit.

[0033] The proposed process involves caustic treatment of the off-gas stream, with the spent caustic stream being further processed in a thermal oxidation unit. Therefore, the spent caustic stream may not need to be regenerated. Therefore, the process does not use intermediate unit operations such as an amine treatment unit and associated sulfur recovery unit. Also, because there are no intermediate unit operations such as an amine treatment unit for the recycle gas, a relatively high volume of sulfur is available in the recycle gas circuit in the form of hydrogen sulfide. Therefore, the disclosed process reduces the volume of sulfur injected into the system with the fresh feed by maintaining sufficient hydrogen sulfide in the recycle gas.

[0034] Also, a purge stream from the hydrotreated gas stream can be purified to remove carbon dioxide and, when added back to the recycle gas stream, increase the hydrogen purity of the recycle gas stream. The purification unit can involve contacting the recycle gas stream with one or both of a solid medium or an absorbent stream to remove impurities. Because the recycle gas stream contains most of the hydrogen sulfide from the purge stream, non-inherent sulfur injection into the reactor will be reduced or eliminated.

[0035] In the figure, a process and apparatus 100 for processing a feed stream including a feedstock is shown, according to one exemplary embodiment. The process and apparatus 100 includes a hydrotreating section 121, a separation section 151, a purification unit 160, and a product recovery section 201. In one exemplary embodiment, the feed stream may include a biorenewable feedstock. A feed line 102 transports the feed stream to a feed surge drum 110. The feed stream may be blended with the feedstock to provide a feed including the feedstock. In one exemplary embodiment, the feed stream may be blended with a biorenewable feedstock to provide a feed stream including the biorenewable feedstock. Alternatively, the feed stream may be referred to as a biorenewable feed stream. In another exemplary embodiment, the feed stream may be blended with a mineral feed stream. The mineral feedstock is a conventional feed derived from crude oil extracted from the ground. The biorenewable feedstock may contain a nitrogen concentration of at least 10 wppm, often at least 25 wppm, preferably at least 300 wppm, possibly at least 500 wppm, and up to 800 wppm nitrogen. The biorenewable feedstock may contain 1 to 1000 wppm sulfur. While the diagram depicts a single-stage process for hydrotreating the feedstock, this process is equally applicable to two-stage or multi-stage processes for hydrotreating the feedstock. According to one exemplary embodiment of the present disclosure, the process for hydrotreating the feedstock may be a single-stage process. According to another exemplary embodiment of the present disclosure, the process for hydrotreating the feedstock may be a two-stage process.

[0036] A variety of different biorenewable feedstocks may be suitable for process 100. The term "biorenewable feedstock" is meant to include feedstocks other than those derived from crude oil. Biorenewable feedstocks may include any of those feedstocks that contain glycerides and / or free fatty acids. Most of the glycerides will be triglycerides, but monoglycerides and diglycerides are present and may be similarly processed. Free fatty acids may be derived from phospholipids, which may be a source of phosphorus in the feedstock. Examples of these biorenewable feedstocks include, but are not limited to, camelina oil, canola oil, corn oil, soy oil, rapeseed oil, soybean oil, rapeseed oil, tall oil, sunflower oil, hempseed oil, olive oil, linseed oil, coconut oil, castor oil, peanut oil, palm oil, mustard oil, tallow, yellow and brown grease, lard, whale oil, milk fat, fish oil, algae oil, sewage sludge, etc. Further examples of biorenewable feedstocks include non-edible vegetable oils from the group including Jatropha curcas (ratanjo, wildcaster, jangrierandi), Madhuca indica (mowa), Pongamia pinnata (karanji, hongji), calophyllum inophyllum, moringa oleifera, and Azadirachta indica (neem). Typical vegetable or animal fat triglycerides and FFAs contain aliphatic hydrocarbon chains with 8 to 30 carbon atoms in their structure. As will be appreciated, biorenewable feedstocks may include mixtures of one or more of the foregoing examples. Biorenewable feedstocks may be pretreated to remove contaminants and filtered to remove solids.

[0037] Non-indigenous sulfur, such as dimethyl disulfide, may be added to the biorenewable feed stream from line 101. The biorenewable feed stream in feed line 102 flows from feed surge drum 110 to line 111. The biorenewable feed stream in line 111 is injected with the non-indigenous sulfur in line 101. The biorenewable feed stream in line 111 is then sent via charge pump 104 and combined with a feed hydrotreated hydrogen stream in line 182 to provide a combined biorenewable feed stream in line 112. The combined biorenewable feed stream in line 112 is heated by heat exchange with the combined hot hydrotreated vapor stream in line 145 to provide a heat-exchanged biorenewable feed stream in line 113. The heat-exchanged biorenewable feed stream in line 113 is combined with a hot liquid recycle stream in line 146 to provide a combined biorenewable feed stream in line 114. The recycle to feed ratio can range from 1:1 to 5:1. The combined bio-renewable feed stream 114 can be heated in combined feed exchanger 21 by heat exchange with the hydrotreated stream in hydrotreated line 134 and / or in fired heater 116 to a protective inlet temperature.

[0038] The heated combined biorenewable feed stream in combined feed line 118 is then charged to hydrotreating reactor section 121. The feed stream is hydrotreated in hydrotreating reactor section 121 in the presence of a hydrotreating hydrogen stream and a hydrotreating catalyst to provide a hydrotreated stream. In an exemplary embodiment, hydrotreating reactor section 121 may include a guard bed reactor 120 followed by a hydrotreating reactor 130, or the guard bed reactor may be omitted, possibly by installing a guard bed in hydrotreating reactor 130. In one embodiment, the combined biorenewable feed stream is charged to guard bed reactor 120 and partially hydrotreated. The guard bed inlet temperature may range from 218°C (425°F) to 304°C (580°F). In guard bed reactor 120, the combined biorenewable feed stream in combined feed line 118 is hydrotreated in the presence of a hydrotreating hydrogen stream containing hydrogen sulfide and a hydrotreating catalyst to hydrodeoxygenate the combined biorenewable feed stream to provide a hydrotreated stream. Hydrodeoxygenation reactions occurring in guard bed reactor 120 include hydrodeoxygenation, hydrodecarbonylation, and hydrodecarboxylation. In addition, other hydrotreating reactions may occur in guard bed reactor 120, including olefin saturation, hydrodemetallization to remove phosphorus, hydrodesulfurization, and hydrodenitrogenation. The feed hydrotreating hydrogen stream in line 182 contains hydrogen sulfide, so that hydrogen sulfide is continuously fed to guard bed reactor 120 to maintain the sulfidation of the hydrotreating catalyst and its activity.

[0039] The temperatures of the guard bed reactor and hydrotreating reactor are kept low, below 343°C (650°F) for typical biorenewable feedstocks, and below 304°C (580°F) for feedstocks with higher free fatty acid (FFA) concentrations to avoid polymerization of the olefins found in the FFA.

[0040] The guard bed catalyst may comprise a base metal on a support. Base metals usable in this process include nickel, chromium, molybdenum, and tungsten. In one embodiment, the base metal may be molybdenum or nickel, or both. Other base metals that may be used include tin, indium, germanium, lead, cobalt, gallium, and zinc. The base metals are active in the sulfide form. Hydrogen sulfide is provided in guard bed reactor 120 from the hydrotreating hydrogen stream in line 181 into the feed hydrotreating hydrogen stream in line 182 at a concentration ranging from 50 to 2000 wppm, preferably 500 to 1200 wppm, based on the fresh feed. Suitable guard bed catalysts include BGB-200 or BGB-100, available from UOP LLC. The biorenewable feedstock may be charged at a pressure of 1379 kPa (abs) (200 psia) to 6895 kPa (abs) (1000 psia). In further embodiments, the guard bed catalyst may include a second metal, which may include one or more of the following metals: tin, indium, ruthenium, rhodium, rhenium, osmium, iridium, germanium, lead, cobalt, gallium, zinc, and thallium. Nickel molybdenum on an alumina catalyst may be a suitable catalyst in guard bed reactor 30. Multiple guard beds, such as two, three, four, or more, may be contained within guard bed reactor 120, and hydrogen quench from the guard bed hydrotreating hydrogen stream in line 184 may be injected at spaced or interbed locations to control temperature exotherms. Hydrogen is also supplied to the guard bed in guard bed reactor 120 by interbed quench injection from the hydrotreating hydrogen stream in line 181 and from the guard bed hydrogen stream in line 184. The guard bed hydrogen stream may have the same concentration as the feed hydrotreating hydrogen stream in line 182.

[0041] The contacted biorenewable feed stream exits guard bed reactor 120 in contacted feed line 122 at a guard outlet temperature that is higher than the guard inlet temperature due to the predominant exothermic reactions occurring within guard bed reactor 120. Within guard bed reactor 120, the majority of hydrodemetallization and hydrodeoxygenation reactions, including hydrodecarbonylation and hydrodecarboxylation reactions, will occur, with some denitrification and desulfurization occurring. Metals removed include alkali and alkaline earth metals and phosphorus.

[0042] The contacted biorenewable feed stream in contacted feed line 122 may be heated and charged to hydrotreating reactor 130. Hydrotreating reactor 130 may have a bed of hydrotreating catalyst to further hydrodeoxygenate, hydrodenitrify, and hydrodesulfurize the contacted biorenewable feed stream, including hydrodemetallization, hydrodecarbonylation, and hydrodecarboxylation. The heated, contacted biorenewable feed stream may be charged to hydrotreating reactor 130 at a hydrotreating inlet temperature that may range from 343°C (650°F) to 400°C (752°F).

[0043] In the hydrotreating reactor 130, the heated and contacted biorenewable feed stream is contacted with a hydrotreating catalyst at hydrotreating conditions in the presence of a reactor hydrotreating hydrogen stream from line 186 to saturate the olefinic or unsaturated portions of the n-paraffinic chains in the biorenewable feedstock. The hydrotreating catalyst also catalyzes hydrodeoxygenation reactions, including hydrodecarboxylation and hydrodecarbonylation, to remove oxygenated functional groups from the biorenewable feedstock molecules, which are converted to water and carbon oxides. The hydrotreating catalyst also catalyzes the desulfurization of organic sulfur and the denitrification of organic nitrogen in the biorenewable feedstock. Essentially, the hydrotreating reaction removes heteroatoms from hydrocarbons to saturate the olefins in the feed stream. The hydrotreating catalyst can be provided in one, two, or more beds, and an interbed hydrogen quench stream from the reactor hydrotreating hydrogen stream in line 186 can be used.

[0044] The hydrotreating catalyst may comprise nickel, nickel / molybdenum, or cobalt / molybdenum dispersed on a high surface area support such as alumina. Suitable hydrotreating catalysts include BDO300 or BDO400, available from UOP LLC of Des Plaines, Illinois. The hydrotreating catalyst should be in sulfided form. Hydrogen sulfide from the reactor hydrotreating hydrogen stream in line 38 may provide sulfur for catalyst sulfiding. Due to hydrogen sulfide produced in guard bed reactor 120 and transported in line 122 to the hydrotreating reactor, in addition to the hydrogen sulfide provided in the reactor hydrotreating hydrogen stream in line 186, the hydrogen sulfide concentration in the hydrotreating reactor may be higher than in the guard bed reactor.

[0045] Typically, hydrotreating conditions include pressures of 700 kPa (100 psig) to 21 MPa (3000 psig). Hydrotreating outlet temperatures can range from 343°C (650°F) to 427°C (800°F).

[0046] In one embodiment, the hydrotreating reactor 130 may include a hydrotreating section 131 and a hydroisomerization section 132. The hydrotreating section 131 may include one or more beds of a hydrotreating catalyst. Applicants have found that the amount of carbon oxides produced during the process varies from start of run (SOR) to end of run (EOR). Typically, the guard bed reactor 120 includes a catalyst with a relatively low activity compared to the hydrotreating reactor 130. Therefore, in SOR, when the guard bed reactor 120 initiates the deoxygenation reaction at a relatively low temperature, the guard bed reactor 120 promotes the hydrodeoxygenation reaction, which produces water, over the decarbonation reaction, which produces carbon dioxide, due to the relatively low activity catalyst present in the guard bed reactor 120. As the catalyst in guard bed reactor 120 loses activity over time, the temperature of the guard bed reactor relatively increases, causing the deoxygenation reaction to shift to hydrotreating section 131 in hydrotreating reactor 130, where the hydrotreating catalyst has relatively higher activity than the catalyst in guard bed reactor 120. The hydrotreating catalyst in hydrotreating section 131 promotes decarbonation. Therefore, in EOR, the catalyst in guard bed reactor 120 is almost completely consumed, and hydrotreating section 131 promotes decarbonation. Therefore, more carbon oxides, such as carbon monoxide and carbon dioxide, are produced in EOR.

[0047] The hydrotreated stream produced in hydrotreating section 131 includes a hydrocarbon fraction having a significant n-paraffin concentration. The oxygenate concentration in the hydrocarbon fraction is essentially zero, while the olefin concentration is substantially reduced relative to the contacted biorenewable feed stream. The organic sulfur concentration in the hydrocarbon fraction may be 500 wppm or less, and the organic nitrogen concentration in the hydrocarbon fraction may be less than 10 wppm. Because this hydrocarbon fraction contains a significant concentration of n-paraffins from the biorenewable feedstock, it is useful as a diesel fuel but has poor cold flow properties. As described below, the hydrotreated stream can be contacted with an isomerization catalyst under isomerization conditions to at least partially isomerize the n-paraffins to isoparaffins. The hydrotreated stream can be separated into a hydrotreated liquid stream and a hydrotreated gas stream.

[0048] In a two-stage configuration, the hydrotreated stream may have a hydrocarbon fraction separated from the gas fraction in an enhanced high temperature separator, with the hydrocarbon fraction sent to hydroisomerization section 132. In the single-stage configuration shown in the figure, both the hydrocarbon fraction and the gas fraction are sent to hydroisomerization section 132.

[0049] To improve cold flow properties, the hydrotreated stream may be contacted with a hydroisomerization catalyst under hydroisomerization conditions in hydroisomerization section 132 to hydroisomerize normal paraffins to branched paraffins. The hydrotreated liquid stream may be hydroisomerized over the hydroisomerization catalyst in the presence of a hydrotreating hydrogen stream provided by line 186.

[0050] The hydroisomerization, including hydrodewaxing, of standard hydrocarbons in hydroisomerization section 132 may be accomplished over one or more beds of hydrodewaxing catalyst, which may be operated in a co-current mode of operation.

[0051] Suitable hydroisomerization catalysts may include metals from Group VIII (IUPAC 8-10) of the periodic table supported on support materials, including metal oxides, and molecular sieves. Suitable Group VIII metals include platinum, palladium, and nickel, each of which may be used alone or in combination. When the hydroisomerization catalyst is positioned within a hydrotreating reactor, as shown, non-noble metals that are less susceptible to sulfur deactivation in sour environments should be used. Examples of suitable non-noble metals include Ni, Mo, Co, W, Mn, Cu, Zn, or Ru. Mixtures of hydrogenation metals, such as Co / Mo, Ni / Mo, and Ni / W, may also be used. The amount of hydrogenation metal may range from 0.1 to 5 wt.% based on the catalyst weight. Methods for supporting metals on support materials include, for example, impregnation of the support material with metal salts of the hydrogenation components and heating. Catalyst support materials containing hydrogenation metals may also be sulfided prior to use.

[0052] The metal oxide-containing support material may include alumina, silica, titania, or silica-alumina, or a combination thereof. Suitable molecular sieves include those with topologies such as AEI, AEL, AFO, AFX, ATO, BEA, CHA, FAU, FER, MEL, MFI, MOR, MRE, MTT, and MWW, or those with TON topologies such as EU-2, ZSM-11, ZSM-22, ZSM-23, SAPO-5, SAPO-11, SAPO-31, SAPO-34, SAPO-41, SSZ-13, SSZ-16, SSZ-39, MCM-22, zeolite Y, ferrierite, mordenite, ZSM-5, or zeolite beta. A related advantage of such materials is their activity in the hydroisomerization of linear hydrocarbons. SAPO-11 has been found to be particularly useful. SAPO-11, SAPO-31, and SAPO-41 are described in U.S. Patent No. 4,440,871. As taught in U.S. Patent Nos. 4,795,623 and 4,924,027, many naturally occurring zeolites, such as ferrierite, which initially have reduced pore size, can be converted to a form suitable for olefin skeletal isomerization by ammonium ion exchange and calcination to remove associated alkali or alkaline earth metals and produce substantially the hydrogen form. Additional catalysts and conditions for skeletal isomerization are disclosed in U.S. Patent Nos. 5,510,306, 5,082,956, and 5,741,759. The hydroisomerization catalyst may also contain a modifier selected from the group consisting of lanthanum, cerium, praseodymium, neodymium, samarium, gadolinium, terbium, and mixtures thereof, as described in U.S. Patent Nos. 5,716,897 and 5,851,949.Other suitable support materials include ZSM-22, ZSM-23, and ZSM-35, which are described for use in dewaxing in U.S. Patent No. 5,246,566 and in an article by S.J. Miller entitled "New Molecular Sieve Process for Lube Dewaxing by Wax Isomerization," 2 Microporous Materials 439-449 (1994). U.S. Patent Nos. 5,444,032 and 5,608,968 teach suitable bifunctional catalysts composed of amorphous silica-alumina gel and one or more metals belonging to Group VIIIA, which are effective in the hydroisomerization of long-chain normal paraffins containing more than 15 carbon atoms. U.S. Patent Nos. 5,981,419 and 5,908,134 teach suitable bifunctional catalysts comprising (a) a porous crystalline material isostructurally similar to beta zeolite selected from borosilicates (BOR-B) and boroaluminosilicates (Al-BOR-B) with a SiO2:Al2O3 ratio greater than 300:1, and (b) one or more metals belonging to Group VIIIA selected from platinum and palladium in an amount ranging from 0.05 to 5% by weight. V. Calemma et al., App. Catal. A: Gen., 190 (2000), 207, teaches yet another suitable catalyst. Alumina or silica may be added to the support material.

[0053] DI-200, DI-211, and DI-100, available from UOP LLC of Des Plaines, Illinois, may be used as suitable hydroisomerization catalysts. Hydroisomerization conditions generally include temperatures from 150°C (302°F) to 450°C (842°F) and pressures from 1724 kPa (abs) (250 psia) to 13.8 MPa (abs) (2000 psia). In another embodiment, hydroisomerization conditions include temperatures from 300°C (572°F) to 360°C (680°F) and pressures from 3102 kPa (abs) (450 psia) to 6895 kPa (abs) (1000 psia).

[0054] The hydrodewaxing catalysts useful in the processes according to the present disclosure may be self-bonded or may include a binder. In some embodiments, the hydrodewaxing catalysts used in the processes according to the present disclosure are formulated using a low surface area binder, and the low surface area binder is 100 m 2 / g or less, or 80m 2 / g or less, or 70m 2 / g or less, or 60m 2 / g or less, or 50m 2 / g or less, or 40m 2 / g or less, or 30m 2 / g or less.

[0055] Alternatively, the binder and zeolite particle size are selected to provide a catalyst with a desired micropore surface area to total surface area ratio. In the hydrodewaxing catalyst used in accordance with the present disclosure, the micropore surface area corresponds to the surface area from the one-dimensional pores of the zeolite in the hydrodewaxing catalyst. The total surface corresponds to the micropore surface area plus the external surface area. Any binder used in the catalyst does not contribute to the micropore surface area and does not significantly increase the total surface area of ​​the catalyst. The external surface area represents the remainder after subtracting the micropore surface area from the surface area of ​​the total catalyst. Both the binder and the zeolite can contribute to the external surface area value. Preferably, the ratio of the micropore surface area to the total surface area of ​​the hydrodewaxing catalyst will be 25% or more, or 30% or more, or 35% or more, or 40% or more.

[0056] The zeolite can be combined with the binder in any convenient manner. For example, a bound catalyst can be produced by starting with powders of both the zeolite and binder, mixing and kneading the powders with added water to form a mixture, and then extruding the mixture to produce the bound catalyst of the desired size. Extrusion aids can also be used to modify the extrusion flow characteristics of the zeolite and binder mixture. The amount of framework alumina in the catalyst can range from 0.1 to 2.7 wt.%, or 0.2 to 2 wt.%, or 0.3 to 1 wt.%.

[0057] In yet another embodiment, a binder comprised of two or more metal oxides may be used, in which the weight percentage of the low surface area binder is preferably greater than the weight percentage of the high surface area binder.

[0058] Alternatively, if both metal oxides used to form the mixed metal oxide binder have sufficiently low surface areas, the proportion of each metal oxide in the binder is not critical. When two or more metal oxides are used to form the binder, the two metal oxides can be incorporated into the catalyst by any convenient method. For example, one binder can be mixed with the zeolite during the formation of the zeolite powder, such as during spray drying. The spray-dried zeolite / binder powder can then be mixed with a second metal oxide binder before extrusion.

[0059] In one aspect of the present disclosure, the catalytic hydrodewaxing catalyst comprises 0.1 wt. % to 2.7 wt. % framework alumina, 0.1 wt. % to 5 wt. % Pt, a SiO:AlO ratio of 200:1 to 30:1, and 100 m 2 at least one low surface area refractory metal oxide binder having a surface area of ​​less than or equal to 1 / g.

[0060] Catalysts are typically bound with a binder or matrix material before use. The binder is resistant to the desired operating temperature and is attrition-resistant. The binder may be catalytically active or inactive and may include other inorganic materials such as other zeolites, clays, and metal oxides such as alumina, silica, titania, zirconia, and silica-alumina. Clays such as kaolin, bentonite, and montmorillonite are commercially available. They may also be blended with other materials, such as silicates. Other porous matrix materials include, in addition to silica-alumina, other binary materials such as silica-magnesia, silica-thoria, silica-zirconia, silica-beryllia, and silica-titania, as well as ternary materials such as silica-alumina-magnesia, silica-alumina-thoria, and silica-alumina-zirconia. The matrix may be in the form of a cogel.

[0061] Hydroisomerization conditions generally include temperatures from 150°C (302°F) to 450°C (842°F) and pressures from 1724 kPa (abs) (250 psia) to 13.8 MPa (abs) (2000 psia). In another embodiment, hydroisomerization conditions include temperatures from 300°C (572°F) to 360°C (680°F) and pressures from 3102 kPa (abs) (450 psia) to 6895 kPa (abs) (1000 psia).

[0062] The hydrotreated stream in hydrotreated line 133 from isomerization section 132 is preferably a branched paraffin-rich stream containing greater than 50% by mass of branched paraffins of the total paraffin content. It is contemplated that the hydroisomerized effluent may contain 70, 80, or 90% by mass of branched paraffins of the total paraffin content. Only minimal branching is required, sufficient to improve the low temperature fluidity of the hydrotreated stream to meet specifications. Hydroisomerization conditions are selected to avoid undesirable cracking, and therefore the predominant products in the hydroisomerized effluent in hydrotreated line 133 are mono-branched paraffins.

[0063] The hydrotreated stream in line 133 contains hydrogen, hydrogen sulfide, and carbon oxides in addition to hydrocarbons. The hydrotreated stream in line 133 may first flow to hydrotreated effluent heat exchanger 31 to heat the cold hydrotreated liquid stream in cold hydrotreated liquid line 156 and cool the hydrotreated stream. As previously mentioned, the cooled hydrotreated stream in hydrotreated line 133 may then exchange heat with the combined biorenewable feed stream in combined feed effluent exchanger 21 to cool the hydrotreated stream in hydrotreated line 133 and heat the combined biorenewable feed stream in line 114. The cooled hydrotreated steam in hydrotreated line 134 may then be further cooled in steam generator 135 to generate steam. In steam generator 135 , the hydrotreated steam in hydrotreated line 134 is further cooled by heat exchange with a water stream in line 136 to provide steam in line 137 .

[0064] A further cooled hydrotreated stream may be removed from steam generator 135 in line 138. The cooled hydrotreated stream in line 138 may be passed to high temperature separator 140. The cooled hydrotreated stream may be separated in high temperature separator 140 to provide a high temperature hydrocarbonaceous hydrotreated gas stream in high temperature overhead line 142 and a high temperature hydrocarbonaceous hydrotreated liquid stream in high temperature bottoms line 141. High temperature separator 140 may be in downstream communication with hydrotreating reactor 130. High temperature separator 140 operates at a temperature between 177°C (350°F) and 371°C (700°F), preferably between 232°C (450°F) and 315°C (600°F). High temperature separator 140 may be operated at a slightly lower pressure than hydrotreating reactor 130 to account for pressure drops due to intervening equipment. High temperature separator 140 may be operated at a pressure between 3.4 MPa (gauge) (493 psig) and 20.4 MPa (gauge) (2959 psig). The high temperature hydrotreated vapor stream in high temperature overhead line 142 may have a temperature at the operating temperature of high temperature separator 140.

[0065] The hot liquid stream in hot bottoms line 141 may be pumped via pump 143 and split into two streams: a process liquid stream in process line 144, which is removed from the hot liquid stream in hot bottoms line 141, and a hot recycle liquid stream in recycle line 146, which is also removed from the hot hydrotreated liquid stream in hot bottoms line 141. The hot recycle liquid stream in recycle line 146 may be combined with the biorenewable feed stream in line 102, as previously described.

[0066] A process liquid stream removed from the hot liquid stream in process line 144 may be mixed with a hot hydrotreated vapor stream in hot overhead line 142 to provide a combined hot hydrotreated vapor stream in line 145, which may be cooled in hot steam combined feed heat exchanger 11 by heat exchange with the biorenewable feed stream in line 112. The cooled combined hot hydrotreated vapor stream in line 145 may be further cooled and fed to cold separator 150. The cooled combined hot hydrotreated vapor stream is separated in cold separator 150 into a cold hydrotreated vapor stream in cold overhead line 152 containing hydrogen sulfide, carbon oxides, hydrogen, and light C1-C6 hydrocarbons. The hot hydrotreated liquid stream in the combined hot hydrotreated vapor stream in line 145 picks up the hydrotreated liquid material in the vapor and entrains it in the cold hydrotreated liquid stream. An aqueous stream may be removed from the boot of cold separator 150. A cold hydrotreated liquid stream exits cold separator 150 in cold bottoms line 156. The cold hydrotreated liquid stream, which comprises hydrocarbons in the distillate range, is heated by heat exchange in stripper bottoms exchanger 41 with the stripper bottoms stream in stripper bottoms line 221 and in hydrotreated effluent exchanger 31 and is supplied to product recovery section 201. In an exemplary embodiment, the product recovery section comprises a stripper column or stripper 220, a sponge absorption column 230, a fractionation column 250, a caustic scrubber unit 270, a selective caustic scrubber unit 260, and a thermal oxidation unit 280.

[0067] Within stripper column 220, vapor components, such as hydrogen sulfide, are stripped from the hydrotreated liquid stream by contact with a stripping gas, such as steam, supplied to the bottom of stripper column 220 via line 212. The vapor components separate into an overhead gaseous stream which rises in overhead line 222. The overhead gaseous stream in overhead line 222 may be condensed to produce a naphtha stream in a stripper overhead liquid stream in line 224, while leaving liquefied petroleum gas (LPG) and light gases containing primarily C3 and C4 hydrocarbons in a stripper off-gas stream in line 227. The condensed overhead gaseous stream may be sent to stripper column receiver 223 to provide a stripper off-gas stream in line 227 and a stripper overhead liquid stream in line 224. The stripper overhead liquid stream in line 224 may be fractionated in fractionation tower 250. In one embodiment, a reflux stream may be removed from the stripper overhead liquid stream in line 224. The reflux stream removed in line 225 is recycled to the top of fractionation column 250. The remaining portion of the stripper overhead liquid stream in line 226 is sent to fractionation column 250. A stripped distillate stream may exit stripper column 220 in stripper bottoms line 221. The stripped distillate stream may be recovered as a diesel product in line 221 or may be transported for further product recovery. Further fractionation of the stripped distillate stream in stripper bottoms line 221 may produce a kerosene / jet range stream and a diesel range stream.

[0068] The cold hydrotreated vapor stream in the cold separator overhead line contains hydrogen, hydrogen sulfide, carbon dioxide, carbon monoxide, and light C1-C6 hydrocarbons. Typically, this cold hydrotreated vapor stream is fed to a scrubber column that contacts the cold hydrotreated vapor stream with an amine solvent to scrub the cold hydrotreated vapor stream of acid gases, so that the purified cold hydrotreated vapor stream can be recycled to hydrotreating section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130, to provide the hydrogen demand. Carbon dioxide is an acid gas that is desirably removed from the cold hydrotreated vapor stream before recycling it to hydrotreating section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130. Carbon dioxide can accumulate in the system and must be removed. Additionally, carbon monoxide is controlled by conversion to carbon dioxide in a water-gas shift reaction in hydrotreating reactor 130. Carbon dioxide concentration must be controlled to avoid pushing the water-gas shift equilibrium too far in favor of carbon monoxide, which is not easily removed from the system.

[0069] Another acid gas, hydrogen sulfide, is retained in the cold hydrotreated vapor stream that is recycled to hydrotreating section 121, particularly guard bed 120 and / or hydrotreating reactor 130. Hydrogen sulfide is essential to replenish the sulfur stripped from the hydrogenation metals on the hydrotreating catalyst. Sulfur is essential to keep the hydrogenation metals sulfided and therefore active. Conventionally, the entire cold hydrotreated gas stream is subjected to solvent scrubbing to remove acid gases before any portion thereof is recycled to hydrotreating section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130. In one embodiment, a portion of the cold hydrotreated gas stream bypasses the acid gas removal column and is recycled to hydrotreating section 25, particularly guard bed reactor 30 and / or hydrotreating reactor 32, along with all of its hydrogen sulfide.

[0070] According to this process, the cold hydrotreated gas stream in cold overhead line 152 is split into a recycle gas stream in recycle line 154 and a purge gas stream in purge line 153. The recycle gas stream in recycle line 154, along with any hydrogen sulfide therein, is recycled to hydrotreating reactor section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130. A supplemental make-up hydrogen gas stream in line 175 can be added to the recycle gas stream in line 154 to provide a recycle hydrogen stream in line 176. The recycle hydrogen stream is compressed in compressor 180 to provide a hydrotreated hydrogen stream in line 181, which is recycled to hydrotreating section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130. The supplemental make-up hydrogen gas stream in line 175 has a higher hydrogen concentration than the recycle gas stream to increase the hydrogen concentration of the hydrotreated hydrogen stream recycled to hydrotreating section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130.

[0071] The hydrotreated hydrogen stream in line 181 comprises at least a portion of the low temperature hydrotreated gas stream in line 152 and the recycle gas stream in line 154. According to one exemplary embodiment, the hydrotreated hydrogen stream in line 181 may contain from 50 wppm sulfur to 2000 wppm sulfur, or at least 50 wppm hydrogen sulfide to 2000 wppm hydrogen sulfide. According to another exemplary embodiment, the hydrotreated hydrogen stream in line 181 may contain from 100 wppm sulfur to 1500 wppm sulfur, or at least 100 wppm to 1500 wppm hydrogen sulfide. According to yet another exemplary embodiment, the hydrotreated hydrogen stream in line 181 will contain at least 400 wppm to 1000 wppm sulfur, or 400 to 1000 wppm hydrogen sulfide.

[0072] The purge gas stream in line 153 may comprise 1 to 50 wt. % of the cryogenic hydrotreated gas stream in line 152, preferably 5 to 25 wt. %. In one embodiment, the purge gas stream may comprise 5 to 15 wt. % of the cryogenic hydrotreated gas stream in line 152. The remainder of the cryogenic hydrotreated gas stream may be a recycle gas stream in line 154. The amount of the purge gas stream may be selected to ensure that the concentration of carbon monoxide in the hydrotreated hydrogen stream is less than 1 wt. % or less than 2 wt. Sometimes, removal of a purge stream in line 153 may not be required in SOR. Furthermore, the amount of purge stream removed in line 153 may increase toward EOR. Therefore, including in SOR scenarios, the purge gas stream in line 153 may comprise 0 to 50 wt. % of the cryogenic hydrotreated gas stream in line 152.

[0073] The purge gas stream in purge gas line 153 may be purified in purification unit 160 to increase the hydrogen concentration of the purge gas stream. In an exemplary embodiment, purification unit 160 includes a solid media purification unit 161. The purge gas stream in purge gas line 153 may be further purified by contacting it with a solid media in solid media purification unit 161 to remove impurities from the purge gas stream and provide a contacted purified gas stream. Solid media purification unit 161 utilizes a solid media to remove impurities from the purge gas stream in line 153.

[0074] Solid media purification unit 161 is preferably a pressure swing adsorption (PSA) unit 164. The purge gas stream in line 153 may be fed directly to PSA unit 161, where hydrogen passes through adsorbents in multiple beds 165, while larger molecules such as impurities, carbon monoxide, carbon dioxide, hydrogen sulfide, and hydrocarbons adsorb onto the adsorbents in the beds.

[0075] The exemplary PSA unit 161 operates on the principle of selectively adsorbing hydrocarbons and impurities such as carbon monoxide, hydrogen sulfide, and / or nitrogen onto an adsorbent at a relatively high pressure, such as 1,920 to 5,520 kPa gauge pressure, to form a contacted purified gas stream 166, and desorbing the hydrocarbons and impurities from the adsorbent at a relatively low pressure, such as 7 to 840 kPa gauge pressure, to regenerate the adsorbent and form a tail gas impurity-rich stream 168 containing hydrocarbons and / or other impurities such as carbon monoxide and hydrogen sulfide.

[0076] In one exemplary embodiment, PSA unit 161 includes multiple fixed adsorbent beds 165 containing solid media that are adsorbents. Each adsorbent bed 165 includes layers of different adsorbent materials, with one or more lower layers packed with weaker adsorbent materials that have a relatively low affinity for adsorbing gaseous hydrocarbons and one or more upper layers packed with stronger adsorbent materials that have a relatively high affinity for adsorbing gaseous hydrocarbons and impurities. For example, the lower layers may contain weak adsorbent materials such as activated alumina and / or silica gel, while the middle layers may contain intermediate strength adsorbent materials such as activated carbon, and the upper layers may contain strong adsorbent materials such as zeolites and / or molecular sieve materials.

[0077] In one exemplary embodiment, PSA unit 161 operates according to a five-step pressure swing cycle, including an adsorption step, a cocurrent depressurization step, a countercurrent depressurization step, a purge step, and a repressurization step. Adsorbent beds 165 may be connected in series to cycle between pressures. During the adsorption step, a purge gas stream in line 153 enters the lower section of the fixed-bed adsorption unit at a relatively high pressure. As the feed gas rises within the unit, hydrocarbons and impurities (e.g., carbon monoxide and / or hydrogen sulfide) are adsorbed onto various layers of adsorbent material according to their respective adsorption selectivities to form a contacted purified gas stream in line 166. The cocurrent depressurization step, countercurrent depressurization step, and purge step reduce the pressure within the fixed-bed adsorption unit and purge the unit with high-purity gas from the contacted purified gas stream in line 166 or the cocurrent depressurization step, respectively, to remove hydrocarbons and impurities and regenerate the adsorbent material. Flow to each adsorbent bed 165 is periodically stopped, and the pressure in the stopped bed is reduced in stages to release void space gas and then blowdown. Blowdown pressures of 7 kPa (1 psig) to 840 kPa (120 psig) can be used to desorb hydrogen from the adsorbent. The depressurization or blowdown desorbs adsorbed impurities from the adsorbent in the bed and passes them into a tail gas impurity-rich stream in line 168. A repressurization step increases the pressure in the fixed-bed adsorption unit in preparation for the next adsorption step, using either feed gas from the purge gas stream in line 153 or the contacted purified gas stream in line 166. Other pressure swing adsorption configurations may also be used.

[0078] In one exemplary embodiment, a hydrogen recovery of 70 to 75 mole percent can be achieved from purge gas stream 153 supplied to PSA unit 164 at a blowdown pressure of 689 kPa (100 psig) to 1034 kPa (150 psig). As a result, the tail gas impurities-rich stream in line 168 exits at a pressure that allows it to enter product recovery section 201. To maximize hydrogen recovery, the tail gas impurities-rich stream in line 168 is removed at a lower blowdown pressure, such as 7 kPa (1 psig) to 35 kPa (5 psig), to obtain at least 92 mole percent hydrogen in purge gas stream 153, at a purity of 90 to 99 mole percent. The lower tail gas pressure allows for greater removal of light hydrocarbons, such as LPG and naphtha, in the tail gas impurities-rich stream from the purge gas stream. In one embodiment, a tail gas compressor (not shown) may be installed on the tail gas impurities rich line 168 to improve the recovery of LPG and naphtha in the product recovery section 201 .

[0079] An impurity-rich stream rich in carbon oxides, hydrogen sulfide, and light hydrocarbons exits PSA unit 164 and enters a tail gas stream in line 168. In accordance with the present disclosure, the tail gas stream in line 168 may be sent to product recovery section 201 for hydrocarbon recovery. The tail gas stream in line 168 may be sent to one or more of stripper column 220, sponge absorber column 230, or selective caustic scrubber unit 260. In an exemplary embodiment, the tail gas stream in line 168 may be sent to sponge absorber column 230.

[0080] PSA unit 161 produces a contacted purified gas stream in purified gas line 166. The contacted purified gas stream in line 166 may be mixed with a recycle gas stream in line 154 to increase the hydrogen concentration in the recycle gas stream recycled to hydrotreating section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130. The contacted purified gas stream in line 166 may have at least 98 mole % hydrogen, suitably at least 99 mole % hydrogen, and preferably at least 99.9 mole % hydrogen, at a pressure of 3.5 MPa (500 psia) to 5.5 MPa (800 psia). In one embodiment, the contacted purified gas stream in line 166 may supplement a make-up gas stream in line 174 having a similar hydrogen concentration and pressure. Make-up gas in line 174 may be provided from a make-up gas header in line 162 and, after undergoing one or two stages of compression, supplemented with the contacted purified gas stream in line 166 to provide a make-up gas stream in line 175. The make-up gas stream in line 175 may then be mixed with the recycle gas stream in line 154 and compressed in a recycle gas compressor to provide a hydrotreated hydrogen stream in line 181. In one embodiment, the make-up gas stream in line 174 is mixed with the purified gas stream in line 166 and the recycle gas stream in line 154 to provide a recycle hydrogen stream in line 176.

[0081] The hydrotreated hydrogen stream in line 181 may be provided in three branches: a feed hydrotreated hydrogen stream in line 182, a guard bed hydrotreated hydrogen stream in line 184, and a reactor hydrotreated hydrogen stream in line 186. The hydrotreated hydrogen stream contains at least 60% by weight hydrogen, preferably at least 80% by weight hydrogen, more preferably at least 92% by weight hydrogen, preferably at least 94% by weight hydrogen, and less than 1 mol% carbon monoxide, and hydrogen sulfide to maintain sulfidation of the hydrotreating catalyst in guard bed reactor 120 and hydrotreating reactor 130 of hydrotreating reactor section 121, as described above. The hydrogen sulfide in the recycled hydrogen stream in line 176 that is recycled to the reactor allows for the reduction or elimination of any sulfur addition to biorenewable feed stream 102.

[0082] The compressed hydrotreated hydrogen stream in line 181 supplies hydrogen to the hydrotreated hydrogen stream in hydrotreated hydrogen line 182, the guard bed hydrogen stream in guard bed hydrogen line 184, and the reactor hydrogen stream in reactor hydrogen line 186. The greater the ratio of the purge gas stream in line 153 to the recycle gas stream in line 154, the greater the proportion of supplemental make-up gas that must be mixed with the recycle gas and recycled to hydrotreating section 121, particularly guard bed reactor 120 and / or hydrotreating reactor 130. However, the use of solid media gas purification unit 161 to increase the hydrogen purity of the purge gas stream allows for a reduction in the make-up gas rate in line 174 to the extent that the contacted purified gas stream in line 166 provides make-up gas in line 175 that is mixed with the recycle gas in line 154.

[0083] Referring to stripper column 220, the stripper off-gas stream in line 227 is in the LPG range C 3+The fractionator off-gas stream in line 252 may be sent to sponge absorber column 230 to recover hydrocarbons containing the hydrocarbons. The fractionator off-gas stream in line 252 may also be sent to sponge absorber column 230. In an exemplary embodiment, the stripper off-gas stream in line 227 may be combined with the fractionator off-gas stream in line 252 to provide a combined off-gas stream in line 228. The combined off-gas stream in line 228 may be sent to sponge absorber column 230. In another embodiment, the stripper off-gas stream in line 227 and the fractionator off-gas stream in line 252 may be sent separately to absorber column 230. A tail gas stream in line 168 is also sent to absorber column 230, possibly above the combined off-gas stream in line 228. In sponge absorber column 230, the stripper off-gas stream in line 227, the fractionator off-gas stream in line 252, and the tail gas stream in line 168 contact a sponge oil stream that is sent to sponge absorber column 230 via line 258. A sponge oil stream rich in LPG hydrocarbons is removed from the bottom of sponge absorber column 230 in bottoms line 234. A sponge off-gas stream comprising one or more of hydrogen sulfide, water, and carbon dioxide may be removed from the top of sponge absorber column 230 in overhead line 232. At least a portion of the sponge off-gas stream may be contacted with a caustic stream to provide a sulfur-lean sponge off-gas stream and a sulfur-rich caustic stream. In an exemplary embodiment, the sponge off-gas stream in line 232 may be sent to knock-out drum 240 to further separate light gases from the sponge off-gas stream in an overhead lean stream in line 242. A liquid stream may be removed from knock-out drum 240 in bottoms line 244.

[0084] According to the present process, the stripper overhead liquid stream in line 226, the LPG hydrocarbon-rich sponge oil stream in line 234, and the liquid stream in bottoms line 244 may be fractionated in fractionation column 250. In one exemplary embodiment, the stripper overhead liquid stream in line 226 and the LPG hydrocarbon-rich sponge oil stream in line 234 may be combined to provide a first combined stream in line 236, which may be sent to fractionation column 250. In another exemplary embodiment, the first combined stream in line 236 and the liquid stream in bottoms line 244 are combined to provide a second combined stream in line 246, which may be sent to fractionation column 250. The stripper overhead liquid stream in line 226, the LPG hydrocarbon-rich sponge oil stream in line 234, and the liquid stream in bottoms line 244 may be sent separately to fractionation column 250. The stripper overhead liquid stream in line 226, the LPG-hydrocarbon-rich sponge oil stream in line 234, and the liquid stream in bottoms line 244 are fractionated in fractionation column 250 to provide a fractionator overhead gaseous stream in line 251 and a fractionator bottoms naphtha stream in line 257. The fractionator overhead gaseous stream may be condensed and passed to fractionator receiver 253 to separate a fractionator off-gas stream in line 252 from a liquid stream comprising LPG hydrocarbons in line 254. The fractionator off-gas stream in line 252 may be recycled to sponge absorption column 230 as previously indicated. The LPG-hydrocarbon-containing liquid stream in line 254 is separated into a first portion of a liquid stream comprising LPG hydrocarbons in line 255 and a second portion of a liquid stream comprising LPG hydrocarbons in line 256. The second portion of the liquid stream may be sent to the top of fractionation column 250 as a reflux stream in line 256. The fractionator bottoms naphtha stream in line 257 may be split into a fractionator boiler stream in fractionator reboil line 291 and a net fractionator bottoms naphtha stream in line 290. The fractionator boiler stream in fractionator reboil line 291 is returned to fractionator 250 after being reboiled in reboiler 51. In one embodiment, the net fractionator bottoms naphtha stream in line 290 may be separated into a bottoms naphtha product stream in line 259 and a bottoms naphtha recycle stream in line 258.In one exemplary embodiment, the bottoms naphtha recycle stream may be sent to sponge absorber column 230 as sponge oil in line 258. In another embodiment, the stripped distillate stream in stripper bottoms line 221 may be sent to sponge absorber column 230 as sponge oil in line 258.

[0085] The liquid stream containing LPG hydrocarbons in line 256 and the sponge off-gas stream in line 242 contain, among other things, carbon oxides and hydrogen sulfide. These streams can be further purified to separate the carbon oxides and / or hydrogen sulfide and recover a purified / treated gas stream. According to this process, the liquid stream containing LPG hydrocarbons in line 255 and the sponge off-gas stream in line 242 are contacted with caustic (NaOH) in respective caustic scrubbers to separate the carbon oxides and / or hydrogen sulfide and recover a purified / treated gas stream and a liquid stream. In a typical caustic process, a single caustic process step contacts a gas stream with a caustic stream. Such a process step contacts a batch of caustic with the gas stream. When the caustic begins to consume the recovery from the gas stream, the spent caustic is washed away and replaced with a new batch of caustic. This process requires a large vessel for contacting the gas stream with the caustic stream. Also, the volume of caustic that contacts the gas stream is significantly higher, generating large amounts of spent caustic that must be properly disposed of / handled.

[0086] Applicants have found that the sponge off-gas stream in line 242 has a relatively high hydrogen sulfide to carbon dioxide molar ratio compared to the liquid stream containing LPG hydrocarbons in line 255. Specifically, the amount of hydrogen sulfide present in the sponge off-gas stream in line 242 is relatively higher than in the liquid stream containing LPG hydrocarbons in line 255. The disclosed process includes a selective caustic treatment step for the sponge off-gas stream in line 242. The selective caustic treatment step for the sponge off-gas stream in line 242 selectively removes more sulfur, particularly hydrogen sulfide, from the sponge off-gas stream than carbon dioxide. To ensure selective removal of sulfur from the sponge off-gas stream, the sponge off-gas stream in line 242 contacts a caustic stream in a selective caustic scrubber unit 260 for a very short contact time. The selective caustic contact time may alternatively be referred to as the residence time of the selective caustic scrubber unit 260. The caustic treatment for the liquid stream containing LPG hydrocarbons in line 255 can be a batch process. The disclosed process with selective caustic treatment for sulfur removal reduces the overall capital expenditure of the process by reducing the size of the selective caustic scrubber unit for the sponge off-gas stream in line 242. Because the process uses selective caustic treatment for the sponge off-gas stream in line 242 in selective caustic scrubber unit 260, less spent caustic is produced after treating the sponge off-gas stream in line 242. This reduces the total volume of spent caustic from selective caustic scrubber unit 260 and caustic scrubber unit 270. The process also provides an efficient and environmentally friendly method of treating spent caustic to produce a treated gas stream, as described in detail below.

[0087] In an exemplary embodiment, the sponge off-gas stream in line 242 may be split into a first portion of the sponge off-gas stream in line 247 and a second portion in line 248. The first portion of the sponge off-gas stream in line 247 is contacted with a caustic stream in line 261 in a selective caustic scrubber unit 260. In the selective caustic scrubber unit 260, the caustic stream in line 261 selectively removes sulfur from the first portion of the sponge off-gas stream in line 247 over carbon dioxide. According to an exemplary embodiment of the present process, the first portion of the sponge off-gas stream in line 247 is contacted with the caustic stream in line 261 for a period ranging from 2 milliseconds to 2 seconds to selectively remove sulfur from the first portion of the sponge off-gas stream to provide a sulfur-lean sponge off-gas stream 262 and a sulfur-rich spent caustic stream in line 264. The sulfur-lean sponge off-gas stream may be removed in line 262. The short contact time between the sponge off-gas stream in line 247 and the caustic stream in line 261 in the selective caustic scrubber unit 260 ensures that no or substantially little carbon dioxide transfers to the caustic stream while removing hydrogen sulfide to the caustic stream. In one exemplary embodiment, the caustic stream in line 261 can selectively remove at least 99 wt.% of the hydrogen sulfide in the sponge off-gas stream in line 247 in the selective caustic scrubber unit 260, removing hydrogen sulfide in amounts from 5000 wppm to 50 wppm from the sponge off-gas stream in line 247. According to another exemplary embodiment of the present disclosure, the sulfur-lean sponge off-gas stream 262 can contain less than 50 wppm of hydrogen sulfide. The lack of or substantially little carbon dioxide transfer avoids operational problems, including sodium carbonate formation and plugging of the selective caustic scrubber unit 260, and minimizes unnecessary caustic use. Thus, the present process requires a relatively low volume of caustic and selectively removes sulfur from the sponge off-gas stream in line 247. According to the present process, selective caustic scrubbing can reduce caustic consumption by a factor in the range of 4 to 60 compared to non-selective conventional processes.Selective caustic scrubbing for the sponge off-gas stream in line 247 offers the advantage of lower capital costs for caustic scrubbing compared to amine systems. In one exemplary embodiment of the present disclosure, the caustic stream in line 261 can be sent to a selective caustic scrubber unit 260 at a flow rate of 45 kg / hr (100 lb / hr) to 454 kg / hr (1000 lb / hr) to selectively remove sulfur from a first portion of the sponge off-gas stream in line 247. The caustic stream in line 261 can include a caustic solution having a concentration of 5 wt% to 15 wt%, or a caustic solution having a concentration of 6 wt% to 12 wt%. In the selective caustic scrubber unit 260, the caustic from the caustic stream in line 261 can react with hydrogen sulfide present in the sponge off-gas stream in line 247 to produce sulfides and disulfides of sodium. The produced sodium sulfide and disulfide remain in the sulfur-rich spent caustic stream in line 264. In one exemplary embodiment, the sulfur-rich spent caustic stream in line 264 may contain sodium sulfide and / or sodium disulfide in an amount of 4% to 8% by weight. The amount of sodium carbonate and / or sodium bicarbonate in the sulfur-rich spent caustic stream in line 264 is expected to be minimal.

[0088] Referring back to fractionation column 250, a first portion of the liquid stream comprising LPG hydrocarbons in line 255 may be contacted with a caustic stream in line 271 in a caustic scrubber unit 270. The first portion of the liquid stream comprising LPG hydrocarbons in line 255 may be purified in the caustic scrubber unit 270 to provide a sulfur-lean LPG stream 272 and a spent caustic stream in line 274. The caustic treatment step for the liquid stream comprising LPG hydrocarbons in line 255 in the caustic scrubber unit 270 need not be a selective caustic treatment for sulfur removal as used for the sponge off-gas stream in line 247. The caustic stream in line 271, when contacted with the first portion of the liquid stream comprising LPG hydrocarbons in line 255, removes, among other things, carbon dioxide and hydrogen sulfide from liquid stream 255 in a spent caustic stream in line 274. In one exemplary embodiment, the caustic stream in line 271 can remove at least 99.9% by weight of the carbon dioxide in the liquid stream containing LPG hydrocarbons in line 255 into the spent caustic stream in line 274. In another exemplary embodiment, the caustic stream in line 271 can remove at least 99% by weight of the hydrogen sulfide from the liquid stream containing LPG hydrocarbons in line 255. According to another exemplary embodiment of the present disclosure, the sulfur-lean LPG stream 272 can contain 10 wppm or less of hydrogen sulfide and 10 wppm or less of carbon dioxide. The sulfur-lean LPG stream is removed in line 272. Thus, both the spent caustic stream in line 274 and the sulfur-rich spent caustic stream in line 264 remove sulfur from the gas stream. Therefore, the spent caustic stream in line 274 can also be referred to as the sulfur-rich spent caustic stream in line 274. However, the sulfur-rich spent caustic stream in line 264 contains a relatively higher concentration of removed hydrogen sulfide than the spent caustic stream in line 274 .

[0089] The present process also discloses a spent caustic treatment step for efficient and environmentally friendly handling and disposal of the spent caustic stream with reduced disposal costs. The caustic treatment step of the present process converts the spent caustic stream into solid sulfur products / salts and provides a treated gas stream. According to the present process, the sulfur-rich spent caustic stream in line 264 and the spent caustic stream in line 274 may be sent to a thermal oxidation unit 280 where they may be treated.

[0090] In caustic scrubber unit 270, the caustic in the caustic stream in line 271 may react with hydrogen sulfide present in the liquid stream containing LPG hydrocarbons in line 255 to produce sodium sulfide and disulfide. The produced sodium sulfide and disulfide remain in the spent caustic stream in line 274. The spent caustic stream in line 274 contains sodium sulfide, sodium disulfide, and sodium carbonate. Because the caustic scrubbing in caustic scrubber unit 270 is non-selective caustic scrubbing, the caustic also reacts with carbon dioxide while reacting with hydrogen sulfide to produce sodium carbonate. The spent caustic stream in line 274 may also contain unreacted caustic, water, and trace amounts of hydrocarbons, primarily C3 and C4, dissolved in the liquid phase. In one exemplary embodiment, the spent caustic stream in line 274 may contain sodium sulfide and / or sodium disulfide in an amount between 4% and 8% by weight.

[0091] The composition of the sulfur-rich spent caustic stream in line 264 is similar to the spent caustic stream in line 274, with one important difference: it may contain no or only very small amounts of sodium carbonate due to selective scrubbing in the selective caustic scrubber unit 260. In the selective caustic scrubber unit 260, the contact time between the first portion of the sponge off-gas stream in line 247 and the caustic stream in line 261 is very short, so there is little or no reaction of the caustic with carbon dioxide. Therefore, the caustic has sufficient time to react only with hydrogen sulfide and not with carbon dioxide to produce sodium carbonate. The sulfur-rich spent caustic stream in line 264 may also have trace amounts of C1 and C2 hydrocarbons dissolved in the liquid phase.

[0092] Thermal oxidation unit 280 includes a thermal oxidation section, a quench section, and a scrubbing section. Thermal oxidation unit 280 may optionally include a nitrogen oxide removal section. The sulfur-rich spent caustic stream in line 264 and the spent caustic stream in line 274 are sent to the thermal oxidation section. A hydrocarbonaceous gas stream is also sent to the thermal oxidation section of thermal oxidation unit 280 as a fuel gas. In an exemplary embodiment, a second portion of the sponge off-gas stream in line 248 may be sent to the thermal oxidation section of thermal oxidation unit 280 as a fuel gas. An air stream in line 249 is also sent to the thermal oxidation section. The sulfur-rich spent caustic stream in line 264 and the spent caustic stream in line 274 are thermally oxidized in the thermal oxidation section of thermal oxidation unit 280. Thermal oxidation of the sulfur-rich spent caustic stream in line 264 and the spent caustic stream in line 274 is carried out at a temperature between 800° C. and 1300° C. with a residence time of 0.5 to 2 seconds.

[0093] Sodium ions react with carbon dioxide (CO) and oxygen (O) from the hydrocarbon combustion to form sodium oxide and carbonate particulates, including, but not limited to, NaO, NaCO, and NaHCO (and their hydrates). NaHCO may be further converted to NaCO. Sulfides from the spent caustic feed are converted to sulfur oxide particulates, including, but not limited to, SO and SO. The formed flue gas flows to a quench section, where the temperature of the flue gas stream is reduced. In the quench section, a quench medium is sent to reduce the temperature of the flue gas stream. Suitable quench media may include air, water, or a suitable gas stream.

[0094] The sulfur oxidation unit may include an optional waste heat recovery section having a waste heat boiler for producing steam or hot oil by recovering heat from the flue gas stream. The flue gas stream from the thermal oxidation section is then sent to a scrubbing section. The scrubbing section may be referred to as a sulfur oxide removal section for the flue gas stream from the thermal oxidation section. According to this process, the scrubbing section can remove sulfur oxides above the acid and water dew point, known as dry scrubbing, or below the acid and water dew point, known as wet scrubbing. Dry scrubbing can use one or more of the following scrubbing reagents: sodium bicarbonate (NaHCO), NaHCO·NaCO·2(H O), calcium carbonate (CaCO), calcium hydroxide (Ca(OH)), and magnesium hydroxide (Mg(OH)). For dry scrubbing, the flue gas stream is first cooled to a temperature above the acid and water dew point. The need to cool to a temperature above the acid and water dew point is due to the design temperature of a filter system used to separate solid particles that may form during dry scrubbing of the flue gas stream. In dry scrubbing of a flue gas stream, any of the following sulfur oxide scrubbing products may be produced when the flue gas contacts a scrubbing reagent: sodium carbonate (Na2CO3), sodium sulfate (Na2SO4), calcium sulfate (CaSO4), calcium carbonate (CaCO3), magnesium carbonate (MgCO3), and magnesium sulfate (MgSO4). Therefore, dry scrubbing of a flue gas stream can produce one or more sodium, magnesium, or calcium salts. In some cases, thermal decomposition of the scrubbing reagent may occur during dry scrubbing of a flue gas stream. Therefore, carbonate salts may also be formed during dry scrubbing of a flue gas stream. For example, NaHCO3 injected into a flue gas stream thermally decomposes to Na2CO3, which then reacts with sulfur oxides to form Na2SO4. A suitable filtration system may be used to separate the solid particles formed, such as Na2CO3 and Na2SO4. Suitable filtration steps may include a bag filter or an electrostatic precipitator (ESP) to separate solid particles.

[0095] For wet scrubbing of flue gas streams, caustic (NaOH) can be used as the scrubbing reagent. The caustic in contact with the flue gas stream reacts with sulfur oxides to produce liquid sodium salts in the form of Na2SO3 and / or Na2SO4.

[0096] The scrubbing step removes SO2 and SO3 from the flue gas by converting them to sodium salts, which are continuously purged from the scrubbing section.

[0097] The presence of halogens in the feed can result in the formation of dioxins and / or furans. These compounds must be removed before the gas is released. Therefore, the flue gas from the scrubbing section can be sent to an optional nitrogen oxide removal section and a dioxin / furan destruction section. A fuel gas stream and air are also sent to the nitrogen oxide removal section for combustion. An ammonia and / or urea stream can also be introduced into the nitrogen oxide removal section. Any dioxin or furan compounds in the flue gas stream from the scrubbing section are removed and / or NOx is reduced to N2 to form a treated gas in the nitrogen oxide removal section. The treated gas can be released to the atmosphere in line 282. If no halogens are present in the feed, the flue gas from the scrubbing section is a treated gas stream, which can then be released to the atmosphere through the stack in line 282.

[0098] Any of the above-mentioned lines, conduits, units, devices, vessels, ambient environments, zones, or the like may be equipped with one or more monitoring components, including sensors, measurement devices, data acquisition devices, or data transmission devices. Signals, process, or condition measurements and data from the monitoring components can be used to monitor conditions in, around, and on the process equipment. Signals, measurements, and / or data generated or recorded by the monitoring components may be collected, processed, and / or transmitted over one or more networks or connections, which may be private or public, general or specific, direct or indirect, wired or wireless, encrypted or unencrypted, and / or combinations thereof. This specification is not intended to be limiting in this respect. Furthermore, the figures show one or more exemplary sensors, such as 12, 22, 32, 42, and 52, positioned on one or more conduits. Nevertheless, there may be a sensor on each stream so that corresponding parameters can be controlled accordingly.

[0099] Signals, measurements, and / or data generated or recorded by the monitoring components may be transmitted to one or more computing devices or systems. The computing devices or systems may include at least one processor and memory storing computer-readable instructions that, when executed by the at least one processor, cause the one or more computing devices to perform a process, which may include one or more steps. For example, the one or more computing devices may be configured to receive data related to at least one piece of equipment associated with the process from one or more monitoring components. The one or more computing devices or systems may be configured to analyze the data. Based on the analysis of the data, the one or more computing devices or systems may be configured to determine one or more recommended adjustments to one or more parameters of one or more processes described herein. The one or more computing devices or systems may be configured to transmit encrypted or unencrypted data including one or more recommended adjustments to one or more parameters of one or more processes described herein. [Example]

[0100] An example process simulation was performed to demonstrate the selective removal of hydrogen sulfide from a portion of the stripper off-gas stream using very short contact times between the caustic stream and the process stream. The simulation results are shown in the table below:

[0101] [Table 1]

[0102] As shown in the table, in SOR, due to the significantly lower off-gas rate and lower absolute CO2 content, a 2-second contact time was required to achieve less than 50 molar ppm HS. In EOR, due to the higher CO2 content, the pH was less than 10. Therefore, a significantly shorter contact time was required to shift the pH above 10. The shorter residence or contact time ensures less CO2 pickup by the caustic, maintaining a pH value greater than 10 with less carbonate and bicarbonate accumulation. Simulation results indicated that a 2-millisecond EOR contact time was required to achieve less than 50 molar ppm HS. As evident from the table, selective caustic treatment of the off-gas stream significantly reduces the caustic required for HS removal compared to the stoichiometric amount of caustic required for both HS and CO2 removal. Therefore, the total caustic required for treating the off-gas stream to remove both HS and CO2 was reduced by selective caustic treatment.

[0103] Specific Embodiments While the following will be described in conjunction with specific embodiments, it will be understood that this description is illustrative, but not intended to limit the scope of the foregoing description and appended claims.

[0104] A first embodiment of the present disclosure is a process for hydrotreating a feedstock, the process including: hydrotreating a feed stream comprising the feedstock in the presence of a hydrotreating hydrogen stream and a hydrotreating catalyst to provide a hydrotreated stream; separating the hydrotreated stream into a hydrotreated liquid stream and a hydrotreated gas stream; stripping the hydrotreated liquid stream to provide a stripper off-gas stream; and contacting at least a portion of the stripper off-gas stream with a caustic stream to provide a sulfur-lean gas stream and a sulfur-rich spent caustic stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, up to and including the first embodiment of this paragraph, wherein contacting at least a portion of the stripper off-gas stream with a caustic stream includes selectively removing sulfur from at least a portion of the off-gas stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further including combusting sulfur in the sulfur-rich spent caustic stream to provide sodium salts and a flue gas stream; and purifying the flue gas stream to provide a treated gas stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including up to the first embodiment of this paragraph, wherein the step of stripping the hydrotreated liquid stream includes passing the hydrotreated liquid stream to a stripper column to provide an overhead gaseous stream and a bottoms stream comprising diesel; condensing the overhead gaseous stream to provide a stripper off-gas stream and a stripper overhead liquid stream; contacting the stripper off-gas stream with a sponge oil stream in a sponge absorber to provide an LPG hydrocarbon-rich sponge oil stream, and a sponge off-gas stream comprising one or more of hydrogen sulfide, water, and carbon dioxide; and contacting at least a portion of the sponge off-gas stream with a caustic stream to provide a sulfur-lean sponge off-gas stream and a sulfur-rich spent caustic stream.An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, wherein contacting at least a portion of the sponge off-gas stream with a caustic stream includes selectively removing a greater proportion of hydrogen sulfide from the sponge off-gas stream than carbon dioxide in the sulfur-rich caustic stream.An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, wherein contacting at least a portion of the sponge off-gas stream with a caustic stream includes dividing the sponge off-gas stream into a first portion and a second portion of the sponge off-gas stream, and contacting the first portion of the sponge off-gas stream with the caustic stream to provide a sulfur-lean sponge off-gas stream and a sulfur-rich spent caustic stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising: fractionating the stripper overhead liquid stream and / or the LPG hydrocarbon-rich sponge oil stream in a fractionation tower to provide a fractionation tower overhead gaseous stream and a fractionation tower bottoms naphtha stream; condensing the fractionation tower overhead gaseous stream to provide a fractionation tower off-gas stream and a liquid stream comprising LPG hydrocarbons; purifying a first portion of the liquid stream comprising LPG hydrocarbons in a caustic scrubber to provide a sulfur-lean LPG stream and a spent caustic stream; and recycling a second portion of the liquid stream comprising LPG hydrocarbons to the fractionation tower. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising treating the sulfur-rich spent caustic stream and the spent caustic stream in a thermal oxidation unit. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, wherein treating the sulfur-rich spent caustic stream and the spent caustic stream includes passing the sulfur-rich spent caustic stream to a thermal oxidation unit and combusting sulfur present in the sulfur-rich spent caustic stream to provide a flue gas stream comprising sulfur oxides.An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising sending the hydrocarbonaceous gas stream to a thermal oxidation unit. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, wherein the hydrocarbonaceous gas stream comprises a second portion of the sponge off-gas stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, wherein the sponge oil stream comprises one or more of a fractionation tower bottoms naphtha stream and a bottoms stream comprising diesel. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising splitting the hydrotreated gas stream into a recycle gas stream and a purge gas stream; recovering hydrogen from the purge gas stream to provide a hydrogen-rich gas stream and a tail gas stream; and sending the tail gas stream to a sponge absorber for contacting the sponge oil stream. An embodiment of the present invention is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, comprising a bio-renewable feedstock in the feedstock.An embodiment of the present invention is one, any, or all of the preceding embodiments of this paragraph, including through the first embodiment of this paragraph, further comprising contacting at least a portion of the off-gas stream with a caustic stream for a period in the range of 2 milliseconds to 2 seconds to selectively remove sulfur from at least a portion of the off-gas stream.

[0105] A second embodiment of the present disclosure is a process for hydrotreating a feedstock, the process including: hydrotreating a feed stream comprising a biorenewable feedstock in the presence of a hydrotreating hydrogen stream, hydrogen sulfide, and a hydrotreating catalyst to provide a hydrotreated stream; separating the hydrotreated stream into a hydrotreated liquid stream and a hydrotreated gas stream; stripping the hydrotreated liquid stream to provide a stripper off-gas stream; contacting at least a portion of the stripper off-gas stream with a caustic stream to provide a sulfur-lean gas stream and a sulfur-rich spent caustic stream; combusting sulfur in the sulfur-rich spent caustic stream to provide a flue gas stream comprising sulfur oxides; and treating the flue gas stream with a scrubbing reagent to produce salts and provide a treated gas stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the second embodiment of this paragraph, wherein contacting at least a portion of the stripper off-gas stream with a caustic stream includes selectively removing sulfur from at least a portion of the off-gas stream.An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the second embodiment of this paragraph, wherein contacting at least a portion of the stripper off-gas stream with a caustic stream includes contacting at least a portion of the stripper off-gas stream with a sponge oil stream in a sponge absorber to provide a sponge off-gas stream and an LPG hydrocarbon-rich sponge oil stream, dividing the sponge off-gas stream into a first portion and a second portion of the sponge off-gas stream, and contacting the first portion of the sponge off-gas stream with the caustic stream. An embodiment of the present disclosure is one, any, or all of the preceding embodiments of this paragraph, including through the second embodiment of this paragraph, further including combusting a second portion of the sponge off-gas stream with sulfur in the sulfur-rich spent caustic stream to provide a flue gas stream.

[0106] A third embodiment of the present disclosure is an apparatus for hydrotreating a feedstock, the apparatus comprising: a biorenewable hydrotreating reactor for hydrotreating a biorenewable feedstock; a purification unit including a solid media; a stripper column in downstream fluid communication with the purification unit; a sponge absorber column in downstream fluid communication with the purification unit and the stripper column; a caustic scrubber column in fluid communication with the sponge absorber column via an overhead line; and a thermal oxidation unit in downstream fluid communication with the caustic scrubber column via a spent caustic stream.

[0107] Without further elaboration, it is believed that, using the preceding description, one skilled in the art can utilize the present disclosure to its fullest extent and easily ascertain the essential characteristics of the present disclosure, and can make various changes and modifications to the present disclosure to adapt it to various uses and conditions, without departing from the spirit and scope of the present disclosure. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

[0108] Above, all temperatures are listed in degrees Celsius and all parts and percentages are by weight unless otherwise stated.

Claims

1. 1. A process for hydrotreating a feedstock, comprising: hydrotreating a feed stream comprising a feedstock in the presence of a hydrotreating hydrogen stream and a hydrotreating catalyst to provide a hydrotreated stream; separating the hydrotreated stream into a hydrotreated liquid stream and a hydrotreated gas stream; stripping the hydrotreated liquid stream to provide a stripper off-gas stream; contacting at least a portion of the stripper off-gas stream with a caustic stream to provide a sulfur-lean gas stream and a sulfur-rich spent caustic stream; contacting at least a portion of the stripper off-gas stream with a caustic stream comprises selectively removing a greater proportion of hydrogen sulfide than carbon dioxide from the stripper off-gas stream; process.

2. 1. A process for hydrotreating a feedstock, comprising: hydrotreating a feed stream comprising a biorenewable feedstock in the presence of a hydrotreated hydrogen stream, and hydrogen sulfide, and a hydrotreating catalyst to provide a hydrotreated stream; separating the hydrotreated stream into a hydrotreated liquid stream and a hydrotreated gas stream; stripping the hydrotreated liquid stream to provide a stripper off-gas stream; contacting at least a portion of the stripper off-gas stream with a caustic stream to provide a sulfur-lean gas stream and a sulfur-rich spent caustic stream; combusting sulfur in the sulfur-rich spent caustic stream to provide a flue gas stream comprising sulfur oxides; treating the flue gas stream with a scrubbing reagent to produce salts and provide a treated gas stream.

3. 1. An apparatus for hydrotreating a feedstock, comprising: a biorenewable hydrotreating reactor for hydrotreating a biorenewable feedstock; a purification unit including a solid medium; a stripper column in downstream fluid communication with the purification unit; a sponge absorption column in downstream fluid communication with said purification unit and said stripper column; a caustic scrubber column in fluid communication with the sponge absorber column via an overhead line; a thermal oxidation unit in downstream fluid communication with the caustic scrubber column via a spent caustic stream.

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