Process for producing diesel fuel from biorenewable feedstock with recycled sulfur

Abstract

The present invention discloses a method for removing hydrogen sulfide from a hydrotreated gas by TSA. Hydrogen sulfide is adsorbed on an adsorbent while allowing hydrogen in the hydrotreated gas to pass through the adsorbent to provide a desulfurized hydrogen stream and a sulfided adsorbent. A regenerant gas stream can be contacted with the sulfided adsorbent at a varying temperature to desorb hydrogen sulfide from the adsorbent into the regenerant gas stream. The regenerant gas stream can then be recycled to a hydroprocessing reactor for use in treating a biorenewable feed to provide hydrogen sulfide to the reactor. The desulfurized gas stream can be purified to remove impurities such as carbon oxides and recycled to the hydroprocessing reactor and / or used as the regenerant gas stream.

Description

[0001] Priority Declaration

[0002] This application claims priority to U.S. Provisional Application No. 63 / 110,754, filed on November 6, 2020, which is incorporated herein in its entirety. Technical Field

[0003] This field is the production of hydrocarbons useful as components of diesel boiling range fuels or aviation range fuels from biorenewable feedstocks such as triglycerides and free fatty acids present in materials such as plant and animal fats and oils. Background Art

[0004] As the demand for fuel increases worldwide, the production of fuels from sources other than crude oil and the blending of components from sources other than crude oil are also increasingly attracting attention. These sources are commonly referred to as biorenewable sources, including but not limited to vegetable oils such as corn oil, rapeseed oil, canola oil, soybean oil; microbial oils such as algae oil; animal fats such as inedible tallow; fish oils and various waste streams such as yellow and brown greases and sewage sludge. The common feature of these sources is that they are composed of glycerides and free fatty acids (FFA). Triglycerides and FFAs both 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.

[0005] Hydrotreating can include processes for converting hydrocarbons into more valuable products in the presence of a hydrotreating 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 in removing heteroatoms, such as sulfur, nitrogen, oxygen, and metals, from the hydrocarbon feedstock. During hydrotreating, hydrocarbons with double and triple bonds, such as olefins, can be saturated.

[0006] The production of hydrocarbon products in the diesel boiling range can be achieved by hydrotreating biorenewable feedstocks. Biorenewable feedstocks can be hydrotreated to remove metals and deoxygenate oxygenated hydrocarbons, followed by hydroisomerization to improve the cold flow properties of the product diesel. Hydroisomerization or hydrodewaxing is a hydrotreating process that increases alkyl branching on the hydrocarbon backbone in the presence of hydrogen and a hydroisomerization catalyst to improve the cold flow properties of the hydrocarbons. Hydroisomerization includes hydrodewaxing as used herein.

[0007] Hydroprocessing of biorenewable feedstocks deoxygenates oxygenated hydrocarbons, resulting in the production of H2O, CO2, and CO in the hydroprocessing effluent. Carbon dioxide can be removed from the recycle hydrogen in an amine recycle gas scrubber. However, reducing carbon monoxide concentrations requires other means, such as purging or a water-gas shift reaction that forms carbon dioxide. Carbon monoxide is toxic to hydroprocessing catalysts and must therefore be removed to avoid the accumulation of deactivating concentrations of carbon monoxide.

[0008] Biorenewable feedstocks contain fewer sulfur-containing hydrocarbons than mineral feedstocks. Consequently, relatively little hydrogen sulfide is produced during the hydroprocessing of biorenewable feedstocks. Hydroprocessing catalysts require sulfiding to ensure that the catalyst is activated.

[0009] In two-stage hydroprocessing units for biorenewable feedstocks, hydrogen sulfide produced during the hydrodemetallization and hydrodeoxygenation reactions is typically removed from the interstage hydroprocessing stream, allowing the hydroisomerization, hydroisomerization, or hydrocracking reactions to occur in a desulfurized environment. "Desulfurized" means sulfur has been removed from the environment, while "high-sulfur" means sulfur is present. In a single-stage unit, hydrogen sulfide remains in the high-sulfur environment for downstream hydroisomerization, hydroisomerization, or hydrocracking reactions.

[0010] The alkali metal hydrotreating catalysts used for hydrodeoxygenation and hydrodemetallization are sulfided to have catalytic activity. These hydrotreating reactions produce water and carbon oxides. The reducing hydrogen environment tends to remove sulfur from the hydrotreating catalyst, thereby causing deactivation. Since the biorenewable feed does not have too much sulfur content, sulfur is injected into the fresh feed in the form of dimethyl disulfide, polysulfide, disulfide oil or refinery high sulfur gas containing hydrogen sulfide to maintain catalyst activity.

[0011] Acid gas treatment systems are required to remove carbon dioxide to maintain hydrogen purity. Furthermore, the generated carbon monoxide is a catalyst poison that inhibits the activity of hydroprocessing catalysts. Carbon monoxide is converted to carbon dioxide through the water-gas shift reaction, so removing carbon dioxide through an amine solvent adsorption column also helps maintain low carbon monoxide concentrations. Traditionally, amine acid gas treatment systems are installed on the recycle gas loop, removing both carbon dioxide and hydrogen sulfide, as hydrogen sulfide is a stronger acid than carbon dioxide.

[0012] Temperature swing adsorption (TSA) is a process used in a variety of industries to remove contaminants from fluids, such as liquid and gas streams. TSA is a batch process consisting of two basic steps: adsorption and regeneration. In the adsorption step, contaminants or other impurities are removed from the fluid by adsorption onto a solid adsorbent material, and the treated stream then leaves the process with reduced contaminant levels. In the regeneration step, the adsorbed contaminants are desorbed from the solid adsorbent material by a regeneration stream, which is typically a gas stream.

[0013] It would be desirable to provide a process and apparatus for producing distillate hydrocarbons from biorenewable feedstocks that ensures adequate sulfidation of the hydroprocessing catalyst. Summary of the Invention

[0014] The method of the present disclosure removes hydrogen sulfide from the gas of hydrotreating by TSA. Hydrogen sulfide is adsorbed on the adsorbent, and the hydrogen in the hydrotreating gas is allowed to pass through the adsorbent to provide a desulfurized hydrogen stream and a sulfided adsorbent. The regenerant gas stream can be contacted with the sulfided adsorbent at a variable temperature to desorb hydrogen sulfide from the adsorbent into the regenerant gas stream. The regenerant gas stream can then be recycled to the hydrotreating reactor, for processing biorenewable feed to provide hydrogen sulfide to the reactor. Therefore, it is necessary to add little or no sulfur additive to the biorenewable raw material to ensure the sufficient sulfidation of the hydrotreating catalyst. The desulfurized gas stream can be purified to remove impurities such as carbon oxides, and recycled to the hydrotreating reactor and / or used as the regenerant gas stream. BRIEF DESCRIPTION OF THE DRAWINGS

[0015] Figure 1 is a simplified process flow diagram of the present disclosure.

[0016] Figure 2 yes Figure 1 Simplified process flow diagram of an alternative embodiment.

[0017] Figure 3 yes Figure 2 Simplified process flow diagram of an alternative embodiment.

[0018] definition

[0019] The term "communication" means operatively permitting material flow between enumerated components.

[0020] The term "downstream communication" means that at least a portion of the material flowing to the body in the downstream communication can operatively flow from the object in communication therewith.

[0021] The term "upstream communication" means that at least a portion of the material flowing from the body in the upstream communication can be operatively directed to an object in communication therewith.

[0022] 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 without undergoing a composition change due to physical fractionation or chemical conversion.

[0023] The term "indirect communication" means that a stream from an upstream component passes through a fractionation or conversion unit and enters a downstream component where it undergoes a composition change due to physical fractionation or chemical conversion.

[0024] The term "bypass" means that the object loses downstream communication with the bypassed body at least within the scope of the bypass.

[0025] The term "tower" means one or more distillation columns used to separate one or more components of different volatilities. Unless otherwise specified, each tower includes a condenser at the top of the tower for condensing a portion of the overhead stream and refluxing it back to the top of the tower, and a reboiler at the bottom of the tower for vaporizing a portion of the bottom stream and returning it to the bottom of the tower. The feed to the tower can be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the tower. The bottom temperature is the liquid bottom outlet temperature. The overhead and bottom lines refer to the net lines from any reflux or reboiler downstream to the tower. A stripping tower can omit the reboiler at the bottom of the tower and instead provide the heating requirements and separation power for the liquefied inert medium (such as steam). The stripping tower is typically fed from the top tray and removes the main product from the bottom of the tower.

[0026] As used herein, the term "component-rich stream" refers to a rich stream exiting a vessel having a greater concentration of a component than the feed to the vessel.

[0027] As used herein, the term "lean component stream" means a lean stream exiting a vessel having a lesser concentration of a component than the feed to the vessel.

[0028] As used herein, the term "boiling temperature" means the atmospheric equivalent boiling point (AEBP) calculated from the observed boiling temperature and the distillation pressure, as calculated using the formula provided in ASTM D86 or ASTM D2887.

[0029] As used herein, the term "true boiling point" (TBP) means the test method for determining the boiling point of a substance in accordance with ASTM D-2892 for producing standardized masses of liquefied gases, distillate fractions, and residues for which analytical data are available, and determining the yields of such fractions by both mass and volume, based on a plot of distillation temperature versus mass % in a column having a reflux ratio of 5:1 using fifteen theoretical plates.

[0030] As used herein, the term "T5" or "T95" means the temperature at which 5 mass percent or 95 mass percent of a sample boils, respectively, using ASTM D-86 or TBP, as appropriate.

[0031] 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 appropriate.

[0032] As used herein, the term "endpoint" (EP) means the temperature at which a sample fully boils using ASTM D2887, ASTM D-86, or TBP, as appropriate.

[0033] As used herein, the term "diesel boiling range" means that hydrocarbons boil in the range of IBP between 125°C (257°F) and 175°C (347°F), or T5 between 150°C (302°F) and 200°C (392°F), using the TBP distillation process, and "diesel cut points" include T95 between 343°C (650°F) and 399°C (750°F).

[0034] As used herein, the term "diesel conversion" means the conversion of a feed boiling above the diesel cut point to a material boiling at or below the diesel cut point in the diesel boiling range.

[0035] As used herein, the term "separator" means a vessel having one inlet and at least one overhead vapor outlet and one bottom liquid outlet, and may also have an outlet for an aqueous stream from a storage tank (boot). A flash tank is a type of separator that can be connected downstream to a separator that can operate at a higher pressure.

[0036] As used herein, the term "predominantly" or "majority" means greater than 50%, suitably greater than 75%, and preferably greater than 90%.

[0037] The term "C x " is understood to refer to molecules having the number of carbon atoms indicated by the subscript "x". Similarly, the term "C x -" refers to molecules containing less than or equal to x, and preferably x and fewer carbon atoms. The term "C x +" refers to molecules with greater than or equal to x, and preferably x and more carbon atoms. DETAILED DESCRIPTION

[0038] The present disclosure is directed to keeping hydrogen sulfide in the recycle gas loop so that less sulfur injection is required to save operating costs. The expense of sulfur addition and sulfur recovery can increase operating costs.

[0039] The present disclosure uses a TSA unit to adsorb hydrogen sulfide from a hydrotreated biorenewable gas stream. The TSA adsorbent can selectively adsorb H2S relative to CO2. The desulfurized hydrotreated gas stream can be recycled to the hydroprocessing reactor. A regenerant stream can be fed to the TSA unit to desorb hydrogen sulfide at a variable temperature to pick up hydrogen sulfide in the regenerant stream. The sulfided regenerant stream can be recycled to the hydroprocessing reactor to provide sulfur demand. Because the adsorbent preferentially adsorbs hydrogen sulfide, the regenerant stream will contain hydrogen sulfide with a significantly reduced carbon dioxide concentration relative to the hydroprocessed stream.

[0040] The present disclosure may be most applicable to single-stage biorenewable hydroprocessing units, but dual-stage biorenewable hydroprocessing units will also have applicability.

[0041] exist Figure 1 In the embodiment, a method 10 for processing a biorenewable feedstock is shown according to an exemplary embodiment. A feed line 12 delivers a feed stream of fresh biorenewable feedstock to a feed surge tank 14. The biorenewable feedstock may be blended with a mineral feed stream, but it may comprise a predominantly biorenewable feedstock. Mineral feedstock is a conventional feed derived from crude oil extracted from the ground. The biorenewable feedstock may comprise a nitrogen concentration of at least 10 wppm, typically at least 25 wppm, suitably at least 300 wppm, possibly at least 500 wppm and up to 800 wppm nitrogen. The biorenewable feedstock may comprise from 1 wppm to 1000 wppm sulfur.

[0042] Various biorenewable raw materials are applicable to method 10. The term "biorenewable raw material" is intended to include raw materials other than those obtained from crude oil. Biorenewable raw materials can include any of those raw materials comprising at least one of glycerides and free fatty acids. Most glycerides are triglycerides, but monoglycerides and diglycerides can also be present and processed. Free fatty acids can be obtained from phospholipids, which can be the source of phosphorus in the raw material. Examples of these biorenewable raw materials include, but are not limited to, linseed oil, canola oil, corn oil, soybean 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, fat in milk, fish oil, algae oil, sewage sludge, etc. Additional examples of biorenewable feedstocks include non-edible plant oils from the group consisting of Jatropha curcas (Ratanjot, Wild Castor, Jangli Erandi), Madhuca indica (Mohuwa), Pongamia pinnata (Karanji, Honge), Calophyllum inophyllum, Moringa oleifera, and Azadirachta indica (Neem). Triglycerides and FFAs of typical plant or animal fats 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.

[0043] Non-indigenous sulfur, such as dimethyl disulfide, may be added to the biorenewable feed stream from line 15. The biorenewable feed stream in feed line 12 is withdrawn from feed surge tank 14 via a feed pump and mixed with the feed hydrotreating hydrogen stream in line 16, heated by heat exchange with the combined hot hydrotreating vapor stream in line 18, and mixed with the hot liquid recycle stream in line 20 to provide a combined biorenewable feed stream in line 22. The recycle to feed ratio may be from 1:1 to 5:1. The combined biorenewable feed stream in line 22 may be heated to guard bed temperature in combined feed exchanger 24 by heat exchange with the hydrotreated stream in hydrotreating line 42 and / or in fired heater 26.

[0044] The heated combined biorenewable feed stream in combined feed line 28 is then charged to hydrotreating reactor section 25. Hydrotreating reactor section 25 may include a guard bed reactor 30 followed by a hydrotreating reactor 32, or it may omit the guard bed reactor, perhaps by installing a guard bed in hydrotreating reactor 32. In an embodiment, the combined biorenewable feed stream is charged to guard bed reactor 30 for partial hydrotreating. The guard bed temperature may be between 218°C (425°F) and 343°C (650°F), preferably not exceeding 304°C (580°F). In guard bed reactor 30, the combined biorenewable feed stream in combined feed line 28 is hydrotreated in the presence of a hydrotreating hydrogen stream comprising hydrogen sulfide and a hydrotreating catalyst to hydrodeoxygenate the combined biorenewable feed stream to provide a hydrotreated stream. The hydrodeoxygenation reactions that occur in guard bed reactor 30 include hydrodecarbonylation and hydrodecarboxylation reactions. Additionally, other hydroprocessing reactions occur in guard bed reactor 30, including olefin saturation, hydrodemetallization to remove phosphorus, hydrodesulfurization, and hydrodenitrogenation. The feed hydroprocessing hydrogen stream in line 16 comprises hydrogen sulfide, such that hydrogen sulfide is continuously supplied to guard bed reactor 30 to maintain the sulfidation of the hydroprocessing catalyst and its activity.

[0045] Guard bed and hydroprocessing reaction temperatures are kept low, less than 343°C (650°F) for typical biorenewable feedstocks and less than 304°C (580°F) for feedstocks with higher free fatty acid (FFA) concentrations, to avoid polymerization of olefins present in the FFAs.

[0046] The guard bed catalyst may comprise an alkali metal on a support. Alkali metals that can be used for the method include nickel, chromium, molybdenum and tungsten. Other alkali metals that can be used include tin, indium, germanium, lead, cobalt, gallium and zinc. Alkali metals are active in the form of sulfides. Based on fresh feed, hydrogen sulfide is provided to guard bed reactor 30 in the feed hydrotreating hydrogen stream in line 92 in a range of 50 wppm to 2000 wppm, and preferably 500 wppm to 1200 wppm in the feed hydrotreating hydrogen stream in line 16. Biorenewable raw materials can be loaded at a pressure of 1379 kPa (absolute) (200 psia) to 6895 kPa (absolute) (1000 psia). In another embodiment, the guard bed catalyst may comprise a second metal, wherein the second metal includes one or more of the following metals: tin, indium, ruthenium, rhodium, rhenium, osmium, iridium, germanium, lead, cobalt, gallium, zinc and thallium. A nickel-molybdenum-on-alumina catalyst may be a suitable catalyst in guard bed reactor 30. Multiple guard beds may be included in guard bed reactor 30, such as 2, 3, 4, or more, and a hydrogen quench from the guard bed hydrotreating hydrogen stream in line 34 may be injected at intervals or inter-bed locations to control the temperature exotherm. Hydrogen is also provided to the guard beds in guard bed reactor 30 from the hydrotreating hydrogen stream in line 92 by injecting the guard bed hydrogen stream in line 34 through an inter-bed quench. The guard bed hydrogen stream may have the same composition as the feed hydrotreating hydrogen stream in line 16, including hydrogen sulfide.

[0047] Due to the primarily exothermic reactions occurring in guard bed reactor 30, the contacted biorenewable feed stream is withdrawn from guard bed reactor 30 in contact feed line 36 at a guard outlet temperature that is higher than the guard inlet temperature. In guard bed reactor 30, most of the hydrodemetallization and hydrodeoxygenation (including hydrodecarbonylation and hydrodecarboxylation) reactions will occur along with some denitrification and desulfurization. Metals removed include alkali and alkaline earth metals and phosphorus.

[0048] The contacted biorenewable feed stream in contacting feed line 36 can be heated and charged to hydrotreating reactor 32. Hydrotreating reactor 32 can have a bed of hydrotreating catalyst to further hydrodemetallize, hydrodeoxygenate (including hydrodecarbonylation and hydrodecarboxylation), hydrodenitrogenate, and hydrodesulfurize the contacted biorenewable feed stream. The heated, contacted biorenewable feed stream can be charged to hydrotreating reactor 32 at a hydrotreating temperature that can be in the range of 343° C. (650° F.) to 427° C. (800° F.), and suitably not exceeding 400° C. (752° F.).

[0049] In hydrotreating reactor 32, under hydrotreating conditions, the biorenewable feed stream of heating, contacting is contacted with hydrotreating catalyst in the presence of the reactor hydrotreating hydrogen stream from pipeline 38, so that the olefinic or unsaturated part of the n-paraffin chain in the biorenewable raw material is saturated. Hydrotreating catalyst also catalyzes hydrodeoxygenation reaction (comprising hydrodecarboxylation and hydrocarbonylation reaction) to remove oxygenate functional groups from biorenewable raw material molecules, and these oxygenate functional groups are converted into water and carbon oxides. Hydrotreating catalyst also catalyzes the desulfurization of organic sulfur and the denitrogenation of organic nitrogen in the biorenewable raw material. Basically, hydrotreating reaction removes heteroatoms from hydrocarbons and saturates the olefins in the feed stream. Hydrotreating catalyst can be provided in one, two or more beds, and adopts the inter-bed hydrogen quenching stream of the hydrogen quenching stream from the reactor hydrotreating hydrogen stream in pipeline 38.

[0050] 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 BDO 200 or BDO 300, available from UOP LLC, Des Plaines, Illinois. The hydrotreating catalyst should be in a sulfided form. The hydrogen sulfide from the reactor hydrotreating hydrogen stream in line 38 can provide sulfur for catalyst sulfidation. The hydrogen sulfide concentration in the hydrotreating reactor can be higher than that in the guard bed reactor due to the hydrogen sulfide generated in guard bed reactor 30 and transported to the hydrotreating reactor in line 36, in addition to the hydrogen sulfide provided in the reactor hydrotreating hydrogen stream in line 38. Typically, hydrotreating conditions include pressures of 700 kPa (100 psig) to 21 MPa (3000 psig).

[0051] In an embodiment, the hydroprocessing reactor 32 may include a hydroprocessing section 40 and a hydroisomerization section 44. The hydroprocessing section 40 may include one or more beds of hydroprocessing catalyst.

[0052] The hydrotreated stream produced in hydrotreating section 40 comprises a hydrocarbon fraction with a significant normal paraffin concentration. The oxygenate concentration in the hydrocarbon fraction is essentially zero, while the olefin concentration significantly reduces relative to the biorenewable feed stream of contact. The organic sulfur concentration in the hydrocarbon fraction may be no more than 500wppm, and the organic nitrogen concentration in the hydrocarbon fraction may be no more than 10wppm. Although this hydrocarbon fraction can be used as a diesel fuel, because it comprises a high concentration of normal paraffins from biorenewable raw materials, it will have poor cold flow characteristics. The hydrotreated stream can be contacted with an isomerization catalyst under isomerization conditions to at least partially convert the normal paraffins into isoparaffins, as described below.

[0053] In a two-stage configuration, the hydrotreated stream may be separated into a hydrocarbon fraction from a gaseous fraction in an enhanced thermal separator, wherein the hydrocarbon fraction is forwarded to the hydroisomerization section 44. Figure 1 In the single-stage configuration shown, the hydrocarbon fraction and the gaseous fraction are sent together to the hydroisomerization section 44.

[0054] To improve cold flow characteristics, the hydrotreated stream can be contacted with a hydroisomerization catalyst under hydroisomerization conditions to hydroisomerize the normal paraffins to branched paraffins in hydroisomerization zone 44. The hydrotreated liquid stream can be hydroisomerized over the hydroisomerization catalyst in the presence of a hydrotreating hydrogen stream provided by line 38.

[0055] The hydroisomerization of normal hydrocarbons (also known as hydrodewaxing) in the hydroisomerization section 44 may be accomplished over one or more beds of hydrodewaxing catalyst, and the hydrodewaxing may be operated in a co-current mode of operation.

[0056] In various embodiments, Figure 1 The hydrodewaxing catalyst used according to the present disclosure in the shown single-stage unit tolerates the presence of sulfur and / or nitrogen during treatment. Suitable catalysts may include ZSM-48, SAPO-11 or ZSM-23. Other suitable catalysts may include 1-dimensional 10-membered ring molecular sieves. In some other embodiments, suitable catalysts may include EU-2, EU-11 or ZBM-30. It is also noted that ZSM-23 with a silicon dioxide to aluminum oxide ratio of 20 to 1 to 40 to 1 is sometimes referred to as SSZ-32.

[0057] The molecular sieve crystals as part of the catalyst can be used together with a metal hydrogenation component. The metal hydrogenation component can be from Groups 6-12 of the periodic table based on the IUPAC system with Groups 1-18, preferably Groups 6 and 8-10. Group VIII metals are particularly advantageous for the hydrodewaxing catalysts disclosed herein. Examples of such metals include Ni, Mo, Co, W, Mn, Cu, Zn or Ru. Mixtures of hydrogenation metals such as Co / Mo, Ni / Mo and Ni / W can also be used. Based on the catalyst, the amount of one or more hydrogenation metals can be in the range of 0.1 wt % to 5 wt %. Methods for loading metals onto ZSM-48 or other molecular sieve catalysts are well known and include, for example, impregnating crystals with a metal salt of the hydrogenation component and heating. Catalysts containing hydrogenation metals can also be sulfided before use. Non-precious metal hydrogenation metals enable hydrodewaxing catalysts to be used in the presence of hydrogen sulfide and ammonia without unduly affecting activity. A non-noble metal hydrogenation metal on the hydrodewaxing catalyst may be necessary in a one-stage hydroprocessing section 25 and is useful in a two-stage hydroprocessing section 25.

[0058] Preferably, the hydrodewaxing catalyst used in the process according to the present disclosure is a catalyst having a low silica to alumina ratio. For example, for ZSM-48, the silica to alumina ratio in the molecular sieve can be less than 200:1, or less than 110:1, or less than 100:1, or less than 90:1, or less than 80:1. In preferred embodiments, the silica to alumina ratio can be from 30:1 to 200:1, from 60:1 to 110:1, or from 70:1 to 100:1.

[0059] The hydrodewaxing catalysts useful in the methods according to the present disclosure may be self-binding or include a binder. In some embodiments, the hydrodewaxing catalysts used in the methods according to the present disclosure are formulated using a low surface area binder, meaning a binder having a surface area of 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 of surface area of the binder.

[0060] Alternatively, the binder and molecular sieve particle size are selected to provide a catalyst having a desired ratio of micropore surface area to total surface area. In the hydrodewaxing catalyst used in accordance with the present disclosure, the micropore surface area corresponds to the surface area of the one-dimensional pores of the molecular sieve in the hydrodewaxing catalyst. The total surface corresponds to the micropore surface area plus the surface area. Any binder used in the catalyst will not contribute to the micropore surface area and will not significantly increase the total surface area of the catalyst. The surface area represents the remainder of the surface area of the total catalyst minus the micropore surface area. Both the binder and the molecular sieve may contribute to the value of the surface area. Preferably, the ratio of the micropore surface area to the total surface area of the hydrodewaxing catalyst will be equal to or greater than 25%, or equal to or greater than 30%, or equal to or greater than 35%, or equal to or greater than 40%.

[0061] Molecular sieve can be combined with the binder in any convenient manner. For example, starting from powders of both the molecular sieve and the binder, these powders can be combined and ground with added water to form a mixture, and then the mixture can be extruded to produce a bonded catalyst of the desired size. Extrusion aids can also be used to change the extrusion flow characteristics of the molecular sieve and binder mixture. The amount of skeleton alumina in the catalyst can be in the range of 0.1 wt % to 2.7 wt %, or 0.2 wt % to 2 wt %, or 0.3 wt % to 1 wt %.

[0062] In yet another embodiment, a binder composed of two or more metal oxides may also be used. In such an embodiment, the weight percentage of the low surface area binder is preferably greater than the weight percentage of the high surface area binder.

[0063] Alternatively, if the two metal oxides used to form the mixed metal oxide binder both have sufficiently low surface areas, the ratio of each metal oxide in the binder is less important. 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, a binder can be mixed with the molecular sieve during the formation of the molecular sieve powder (such as during spray drying). The spray-dried molecular sieve / binder powder can then be mixed with a second metal oxide binder before extrusion.

[0064] In one form 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 SiO2:Al2O3 ratio of 200:1 to 30:1, and at least one catalyst having a surface area of 100 m2. 2 / g or less of a low surface area refractory metal oxide binder. This noble metal catalyst would be more suitable for a two-stage unit where a hydroisomerization hydrogen stream deficient in hydrogen sulfide is fed to the hydroisomerization reactor.

[0065] One example of a molecular sieve suitable for use in the claimed disclosure is ZSM-48 having a SiO2:Al2O3 ratio of 70 to 110. In the embodiments below, ZSM-48 crystals will be described variously according to whether they are "as-synthesized" crystals still containing an organic template (200:1 or lower SiO2:Al2O3 ratio); calcined crystals, such as Na-type ZSM-48 crystals; or calcined and ion-exchanged crystals, such as H-type ZSM-48 crystals.

[0066] The ZSM-48 crystals after removal of the structure directing agent have a specific morphology and a molar composition according to the general formula: (n)SiO2:Al2O3, where n is 70 to 110. In further embodiments, Si may be substituted with Ge, and Al may be substituted with Ga, B, Fe, Ti, V, and Zr.

[0067] ZSM-48 crystals in as-synthesized form are prepared from a mixture having silica, alumina, an alkali, and a hexamethylammonium salt directing agent. In an embodiment, the molar ratio of structure directing agent:silica in the mixture is less than 0.05. In another embodiment, the molar ratio of structure directing agent:silica in the mixture is at least 0.01. In an embodiment, the ZSM-48 crystals in as-synthesized form have a silica:alumina molar ratio of 70 to 110. For any given preparation of ZSM-48 crystals in as-synthesized form, the molar composition will contain silica, alumina, and directing agent. It should be noted that ZSM-48 crystals in as-synthesized form may have a molar ratio that is slightly different from the molar ratio of the reactants used to prepare the reaction mixture in as-synthesized form. This result may occur due to 100% of the reactants in the reaction mixture not being completely incorporated into the crystals formed (from the reaction mixture).

[0068] ZSM-48 compositions are prepared from an aqueous reaction mixture containing silica or a silicate, alumina or a soluble aluminate, an alkali, and a directing agent. To achieve the desired crystal morphology, the reactants in the reaction mixture have the following molar ratios: SiO₂:Al₂O₃ = 70 to 110; H₂O:SiO₂ = 1 to 500; OH₃:SiO₂ = 0.1 to 0.3; and template:SiO₂ = 0.01-0.05.

[0069] The silica source is precipitated silica, commercially available from Degussa. Alumina may be in the form of a soluble salt, preferably the sodium salt, and is commercially available from US Aluminate. Other suitable aluminum sources include other aluminum salts such as chlorides, aluminum alkoxides, or hydrated aluminum oxides such as gamma alumina, pseudoboehmite, and colloidal alumina. The base used to dissolve the metal oxide may be any alkali metal hydroxide, preferably sodium or potassium hydroxide, ammonium hydroxide, diquaternary ammonium hydroxide, or the like. The directing agent is a hexamethylammonium salt such as hexamethylammonium dichloride or hexamethylammonium hydroxide. The anion (other than chloride) may be other anions such as hydroxide, nitrate, sulfate, or other halides. Hexamethylammonium dichloride is N,N,N,N',N',N'-hexamethyl-1,6-hexanediammonium dichloride.

[0070] In an embodiment, the crystals obtained from a synthesis according to the present disclosure have a morphology that is free of fibrous morphology. Fibrous morphology is undesirable because such crystal morphology inhibits the catalytic hydrodewaxing activity of ZSM-48. In another embodiment, the crystals obtained from a synthesis according to the present disclosure have a morphology that contains a low percentage of needle-like morphology. The amount of needle-like morphology present in the ZSM-48 crystals can be 10% or less. Small amounts of needle-like crystals are preferred for some applications because needle-like crystals are believed to reduce the activity of ZSM-48 for some types of reactions. In order to obtain the desired morphology in high purity, the ratios of silica:alumina, alkali:silica and directing agent:silica in the reaction mixture according to an embodiment of the present disclosure should be adopted. Additionally, if a composition free of natronite and / or free of needle-like morphology is desired, the preferred ranges should be used.

[0071] As-synthesized ZSM-48 crystals should be at least partially dried before use or further processing. Drying can be accomplished by heating at a temperature of 100°C to 400°C. The pressure can be atmospheric or subatmospheric. If drying is performed under partial vacuum, the temperature can be below atmospheric pressure.

[0072] The catalyst is typically bonded to a binder or matrix material before use. The binder withstands the desired operating temperature and is wear-resistant. The binder can be catalytically active or inactive and includes other zeolites, other inorganic materials such as clays and metal oxides such as alumina, silica, titania, zirconia, and silica-alumina. Clays can be kaolin, bentonite, and montmorillonite and are commercially available. They can be blended with other materials such as silicates. Other porous matrix materials besides silica-alumina include 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 can be in the form of a co-gel. The range of the bonded ZSM-48 framework alumina will be 0.1% to 2.7% framework alumina.

[0073] The high-purity ZSM-48 crystals prepared according to the above embodiment have a relatively low silica:alumina ratio. This lower silica:alumina ratio means that the catalyst of the present invention is more acidic. Despite this increased acidity, they have excellent activity and selectivity and excellent yields. From the perspective of the health effects of the crystalline form, they also have environmental benefits, and small crystal size is also beneficial to catalyst activity.

[0074] For catalysts according to the present disclosure in combination with ZSM-23, any suitable method for producing ZSM-23 with a low SiO2:Al2O3 ratio can be used. US5,332,566 provides an example of a synthesis method suitable for producing ZSM-23 with a low SiO2:Al2O3 ratio. For example, a directing agent suitable for preparing ZSM-23 can be formed by methylating iminobispropylamine with an excess of iodomethane. Methylation is achieved by adding iodomethane dropwise to iminobispropylamine solvated in anhydrous ethanol. The mixture is heated to a reflux temperature of 77°C for 18 hours. The resulting solid product is filtered and washed with anhydrous ethanol.

[0075] The directing agent prepared by the above method can then be mixed with colloidal silica sol (30% SiO2), an alumina source, a source of alkali cations (such as Na or K), and deionized water to form a hydrogel. The alumina source can be any convenient source, such as sulfated aluminum oxide or sodium aluminate. The solution is then heated to a crystallization temperature, such as 170°C, and the resulting ZSM-23 crystals are dried. The ZSM-23 crystals can then be combined with a low surface area binder to form a catalyst according to the present disclosure.

[0076] Hydroisomerization conditions typically include a temperature of 150° C. (302° F.) to 450° C. (842° F.) and a pressure of 1724 kPa (absolute) (250 psia) to 13.8 MPa (absolute) (2000 psia). In another embodiment, the hydroisomerization conditions include a temperature of 300° C. (572° F.) to 360° C. (680° F.) and a pressure of 3102 kPa (absolute) (450 psia) to 6895 kPa (absolute) (1000 psia).

[0077] The hydrotreated stream in the hydrotreating line 46 from the isomerization section 44 is a stream rich in branched alkanes, preferably comprising greater than 50% by mass of branched alkanes relative to the total alkanes content. It is envisioned that the hydroisomerization effluent may contain a total alkanes content of 70%, 80%, or 90% by mass of branched alkanes. Only a minimal degree of branching is required to improve the cold flow characteristics of the hydrotreated hot liquid stream to meet the specifications. The hydroisomerization conditions are selected to avoid undesirable cracking so that the primary product in the hydroisomerization stream in the hydrotreating line 46 is mono-branched alkanes.

[0078] The hydrotreated stream comprises, in addition to hydrocarbons, hydrogen, hydrogen sulfide, and carbon oxides. The hydrotreated stream in hydrotreating line 46 may first flow to hydrotreating effluent heat exchanger 48 to heat the cold hydrotreated liquid stream in cold hydrotreating liquid line 50 and cool the hydrotreated stream. As previously described, the cooled hydrotreated stream in hydrotreating line 46 may then be heat exchanged with the combined biorenewable feed stream in combined feed effluent exchanger 24 to cool the hydrotreated stream in hydrotreating line 46 and heat the combined biorenewable feed stream in line 22. The cooled hydrotreated stream in hydrotreating line 46 may then be further cooled in steam generator 52 to produce steam.

[0079] The primarily cooled hydrotreated stream is separated into a hydrotreated liquid stream comprising distillate range hydrocarbons and a hydrotreated gas stream comprising hydrogen, carbon oxides, and hydrogen sulfide.The separation into more than one hydrotreated liquid stream and more than one hydrotreated gas stream can be performed in various ways.

[0080] The hydrotreated stream can be separated in hot separator 54 to provide a hot hydrocarbon-containing hydrotreated gas stream in hot overhead line 56 and a hot hydrocarbon-containing hydrotreated liquid stream in hot bottoms line 58. Hot separator 54 can be in downstream communication with hydrotreating reactor 32. Hot separator 54 operates at a temperature of 177° C. (350° F.) to 371° C. (700° F.), and preferably operates at a temperature of 232° C. (450° F.) to 315° C. (600° F.). Taking into account the pressure drop through the intervening equipment, hot separator 54 can operate at a slightly lower pressure than hydrotreating reactor 32. Hot separator 54 can operate at a pressure between 3.4 MPa (gauge) (493 psig) and 20.4 MPa (gauge) (2959 psig). The temperature of the hot hydrotreated vapor stream in hot overhead line 56 can be the operating temperature of hot separator 54.

[0081] The hot liquid stream in hot bottoms line 58 can be pumped and split into two streams: a process liquid stream in process line 60 taken from the hot liquid stream in hot bottoms line 58, and a hot recycle liquid stream in recycle line 20 also taken from the hot hydrotreated liquid stream in hot bottoms line 58. The hot recycle liquid stream in recycle line 20 can be combined with the biorenewable feed stream in line 12, as previously described.

[0082] The process liquid stream taken from the hot liquid stream in process line 60 can be combined with the hot hydrotreated vapor stream in hot overhead line 56 to provide a combined hot hydrotreated vapor stream in line 18 and cooled by heat exchange with the biorenewable feed stream in line 12 in hot vapor combined feed heat exchanger 19. The cooled combined hot hydrotreated vapor stream in line 18 can be further cooled and fed to cold separator 62. The cooled combined hot hydrotreated vapor stream is separated in cold separator 62 into a cold hydrotreated vapor stream in cold overhead line 64, which contains hydrogen sulfide, carbon oxides, and hydrogen. The hot hydrotreated liquid stream in the combined hot hydrotreated vapor stream in line 18 absorbs the hydrotreated liquid material in the vapor to draw it into the cold hydrotreated liquid stream. An aqueous stream can be withdrawn from a storage tank in cold separator 62. The cold hydrotreated liquid stream leaves the cold separator in cold bottoms line 66. The cold hydrotreated liquid stream comprises distillate range hydrocarbons and is heated by heat exchange with the stripper bottoms stream in stripper bottoms line 74 in stripper bottoms exchanger 65 and the hydrotreated stream in hydrotreating effluent exchanger 48 and is fed to recovery section 75 which begins at and is represented by stripping column 70.

[0083] In the stripper 70, vapor components (such as hydrogen sulfide) are stripped from the hydrotreated liquid stream by contact with a stripping gas (such as steam) fed to the bottom of the stripper 70 via line 71. The vapor components separate and rise into an overhead line 72, which can be condensed to produce a naphtha and liquefied petroleum gas (LPG) stream in an overhead liquid stream 76, while leaving light gases in a net overhead stream 78. The stripped distillate stream exits the stripper in a stripper bottom line 74. The stripped distillate stream can be dried and recovered as a diesel product or sent to further product recovery. Further fractionation of the stripped distillate stream in the stripper bottom line 74 can produce a kerosene / jet range stream and a diesel range stream.

[0084] The cold hydrotreated vapor stream in the cold separator overhead line 64 comprises 100 to 10,000 ppmv of hydrogen sulfide, 1 to 10 mol% carbon dioxide, 0.5 to 5 mol% carbon monoxide, 3 to 15 mol% light hydrocarbons, water at a relative humidity of 30 to 100%, and the balance hydrogen. Typically, this cold hydrotreated vapor stream is fed to an acid gas adsorption column, which contacts the cold hydrotreated vapor stream with an amine solvent to scrub the cold hydrotreated vapor stream of acid gases. This purified cold hydrotreated vapor stream can then be recycled to the hydroprocessing section 25, and in particular to the guard bed reactor 30 and / or the hydroprocessing reactor 32, to provide hydrogen demand. Carbon dioxide is an acid gas that is desirably removed from the cold hydroprocessed vapor stream before recycling it to the hydroprocessing section 25, and in particular to the guard bed reactor 30 and / or the hydroprocessing reactor 32. Carbon dioxide can accumulate in the system and must be removed. Additionally, carbon monoxide is controlled by converting it to carbon dioxide in the water-gas shift reaction in the hydroprocessing section 25, and particularly in the guard bed reactor 30 and / or the hydroprocessing reactor 32. The carbon dioxide concentration must be controlled to avoid pushing the water-gas shift equilibrium too far toward carbon monoxide, which is not easily removed from the system.

[0085] Another acid gas (hydrogen sulfide) is desirably retained in the cold hydrotreating vapor stream, which is recycled to the hydrotreating section 25, and in particular to the guard bed 30 and / or hydrotreating reactor 32. Hydrogen sulfide helps to replenish the sulfur stripped from the hydrogenation metal on the hydrotreating catalyst. Sulfur is necessary to keep the hydrogenation metal sulfurized and therefore active. Typically, before any portion of the entire cold hydrotreating gas stream is recycled to the hydrotreating section 25, and in particular to the guard bed reactor 30 and / or hydrotreating reactor 32, the entire cold hydrotreating gas stream is washed with a solvent to remove the acid gases. A portion of the cold hydrotreated gas stream in cold overhead line 64 may be withdrawn in return line 68 and bypass a purification unit such as acid gas adsorption column 100 and recycled, along with all of its hydrogen sulfide and carbon oxides, in a supplemental make-up hydrogen stream in line 86 to hydrotreating section 25 and, in particular, to guard bed reactor 30 and / or hydrotreating reactor 32.

[0086] To achieve the bypass, the cold hydrotreated gas stream in cold overhead line 64 is divided into a return gas stream in return line 68 and a recycle gas stream in recycle line 82. The recycle gas stream and the return stream each have the same composition because these streams are taken as aliquots of the cold hydrotreated gas stream in line 64. The recycle gas stream can be flow controlled by a control valve on line 82. The return gas stream can bypass further purification over differential pressure control by a control valve on line 68. A supplemental make-up hydrogen stream in line 86 can be added to the return gas stream in line 68 to provide a recycle hydrogen stream in line 88. The recycle hydrogen stream is compressed in compressor 90 to provide a hydrotreated hydrogen stream in line 92, which is recycled to hydrotreating section 25, and in particular, to guard bed reactor 30 and / or hydrotreating reactor 32. The supplemental make-up hydrogen stream in line 86 has a higher hydrogen concentration than the return gas stream to increase the hydrogen concentration of the hydroprocessed hydrogen stream that is recycled to the hydroprocessing section 25, and in particular to the guard bed reactor 30 and / or the hydroprocessing reactor 32. All of the return gas stream in line 68 is recycled to the hydroprocessing section 25, and in particular to the guard bed 30 and / or the hydroprocessing reactor 32.

[0087] The hydrotreated hydrogen stream in line 92 includes the cold hydrotreated gas stream in line 64 and at least a portion of the recycle gas stream in line 82. The hydrotreated hydrogen stream in line 92 will contain from 50 wppm sulfur to 2000 wppm sulfur, and specifically from at least 50 wppm hydrogen sulfide to 2000 wppm hydrogen sulfide. The hydrotreated hydrogen stream in line 92 will contain from 100 wppm sulfur to 1500 wppm sulfur, and specifically from at least 100 wppm to 1500 wppm hydrogen sulfide. The hydrotreated hydrogen stream in line 92 will contain from at least 400 wppm to 1000 wppm sulfur, and specifically from 400 wppm to 1000 wppm hydrogen sulfide.

[0088] The recycle stream in line 82 may comprise from 1 wt% to 50 wt%, and preferably from 5 wt% to 25 wt%, of the cold hydrotreated gas stream in line 64. In one aspect, the purge stream may be from 5 wt% to 15 wt% of the cold hydrotreated gas stream in line 64. The balance of the cold hydrotreated gas stream may be the return gas stream in line 68. The amount of the recycle gas stream may be selected to ensure that the concentration of carbon monoxide in the hydrotreated hydrogen stream is less than 2 wt% or less than 1 wt%.

[0089] The recycle gas stream in the recycle gas line 82 can be desulfurized by contacting it with a solid medium to adsorb hydrogen sulfide from the recycle gas stream. The contacting of the recycle gas with the solid medium can be performed in the TSA unit 80. The TSA unit 80 can include several vessels, but is shown with two adsorption vessels 200 and 202. Each vessel 200 and 202 contains an adsorbent bed that selectively adsorbs hydrogen sulfide relative to carbon oxides and hydrogen. The TSA unit 80 is shown with the first vessel 200 in adsorption mode and the second vessel 202 in desorption mode. However, other vessel arrangements and operations can be used.

[0090] The recycle gas stream in recycle gas line 82 is fed to the first adsorption vessel 200 when in adsorption mode via an open control valve thereon. Hydrogen sulfide in the recycle gas stream is preferentially adsorbed onto the adsorbent, while unadsorbed hydrogen, carbon oxides, and hydrocarbons pass through the adsorbent bed. In adsorption mode, the adsorbent becomes a sulfided solid medium, and the recycle gas becomes a sweetened gas stream. The recycle gas stream is fed to the first adsorption vessel 200 at a temperature of preferably 20°C to 80°C, preferably 30°C to 60°C, and a pressure of 20 barg to 100 barg, suitably 35 barg to 70 barg, and preferably 50 barg to 65 barg, although other gas temperatures and pressures are possible. The sweetened gas stream exits the adsorption vessel 200 via a discharge line 212 depleted in sulfur and rich in carbon oxides. During the cycle, the adsorbent in the second vessel 202 becomes sulfided, causing it to become loaded with hydrogen sulfide, and the second vessel must be swung into desorption mode and regenerated before breakthrough occurs.

[0091] The second adsorption vessel 202 was previously in adsorption mode. However, the adsorbent in the second adsorption vessel 202 has reached its maximum hydrogen sulfide capacity and will allow hydrogen sulfide breakthrough if not regenerated. Therefore, a regeneration gas stream deficient in hydrogen sulfide and carbon oxides can be used to regenerate the second adsorption vessel 202. A regeneration gas stream in line 204, taken from the compressed makeup gas stream in line 122, can be heated and passed through the second adsorption vessel 202, possibly countercurrent to the flow direction of the recycle gas when in adsorption mode, to swing the second adsorption vessel into desorption mode. The regeneration gas stream can be heated to a temperature of 200° C. to 280° C., preferably 220° C. to 260° C., and a pressure of 20 barg to 100 barg, suitably 35 barg to 70 barg, and preferably 50 barg to 65 barg. The regeneration agent stream desorbs hydrogen sulfide from the sulfided solid medium in the second adsorption vessel to provide a sulfided regeneration agent gas stream and a desulfurized solid medium. A sulfided regenerant stream exits the second adsorption vessel 202 in a sulfided regenerant line 206 and may be fed to a supplemental make-up gas stream in a make-up gas line 86 for recycle to the hydroprocessing section 25. The flow rate of the regenerant may be from 10% to 80% by weight of the flow rate of the recycle gas through the adsorption vessels 200, 202.

[0092] After the hydrogen sulfide is desorbed into the regenerant stream, the second adsorption vessel 202 can be swung back to the adsorption mode. After the adsorbent in the first adsorption vessel 200 is sulfided, the first adsorption vessel 200 can be swung back to the desorption mode. The first adsorption vessel 200 and the second adsorption vessel 202 can cycle between the adsorption and desorption modes. Other arrangements can be used.

[0093] Suitable adsorbent materials include natural and synthetic zeolites, activated carbon, silica gel, and alumina. Preferred adsorbents are 13X or 5A molecular sieves. Preferred adsorbents are 13X molecular sieves in which 50% to 95% of the sodium ions are exchanged with zinc ions. Preferred adsorbents may be in the form of beads or pellets in which the clay binder comprises 10% to 20% by weight of the particles. Particle sizes may range from 1 mm to 3 mm. Other possible adsorbents may include X, Y, or beta zeolites exchanged with transition metal ions of silver, copper, zinc, iron, cobalt, or nickel.

[0094] Preferred adsorbents can remove greater than 90 wt%, suitably greater than 95 wt%, and preferably greater than 99 wt% of the hydrogen sulfide in the recycle gas stream, while adsorbing no more than 50 wt%, suitably no more than 40 wt%, and preferably no more than 30 wt% of the carbon dioxide in the recycle gas stream. Preferred adsorbents can remove no more than 3 wt%, and preferably no more than 2 wt% of the hydrogen, methane, or ethane in the recycle gas stream. Preferred adsorbents can remove no more than 40 wt%, and preferably no more than 35 wt% of the C3 hydrocarbons in the recycle gas stream. Preferred adsorbents can remove greater than 90 wt%, 95 wt%, or 99 wt% of the water in the recycle gas stream. A dryer upstream of the TSA unit 80 can be used.

[0095] The sweetened gas stream in line 212 can be recycled, along with any carbon oxides thereof, to the hydrotreating reactor section 25, and in particular to the guard bed reactor 30 and / or the hydrotreating reactor 32. However, the sweetened gas stream in line 212 includes impurities, such as carbon oxides and hydrocarbons, that should be removed from the sweetened gas stream. Carbon monoxide can deactivate the hydrodewaxing catalyst and is converted to carbon dioxide via the water-gas shift reaction in the hydrotreating reactor 32. Therefore, the carbon dioxide must be removed to facilitate the conversion of the carbon monoxide to carbon dioxide via the water-gas shift reaction.

[0096] The sweet gas stream in line 212 can be purified in the purification unit 105 to increase the hydrogen concentration of the purge gas stream. In an embodiment, the purification unit 105 can contact the purge gas stream with an adsorbent stream to adsorb impurities such as acid gases (including carbon dioxide) from the sweet gas stream to provide an adsorbed purified gas stream. The purification unit 105 can include an adsorption tower 100 that adsorbs acid gases from the sweet gas stream. The sweet gas stream in line 212 can pass through a tray or packed adsorption tower 100, where the sweet gas stream is washed with the adsorbent stream added via line 102.

[0097] The adsorbent stream can be an aqueous alkaline solution that adsorbs acid gases, including carbon dioxide, by extracting the acid gases into solution. Preferred adsorbent liquids include Selexol (available from Universal Oil Products of Des Plaines, Illinois) and amines such as alkanolamines, including diethanolamine (DEA), monoethanolamine (MEA), methyldiethanolamine (MDEA), diisopropanolamine (DIPA), and diglycolamine (DGA). Other adsorbent liquids may be used in place of or in addition to the preferred amine adsorbent liquids. The lean adsorbent stream is contacted countercurrently with the sweetened gas stream and adsorbs acid gas contaminants, such as carbon dioxide.

[0098] The resulting adsorbed purified gas stream is withdrawn from the top outlet of the adsorption column 100 in adsorber overhead line 104, and a rich adsorbent stream is withdrawn from the bottom of the adsorption column 100 at the bottom outlet in adsorber bottom line 108. The spent adsorbent stream from the bottom of the column can be regenerated in adsorbent line 102 and recycled back to the adsorbent column 100. The adsorbed purified gas stream in adsorber overhead line 104 comprises 1 to 3 mol% carbon monoxide, 0.5 to 2 mol% methane, and 1 to 5 mol% ethane, and a hydrogen concentration of 85 to 94 mol%.

[0099] The adsorption column 100 can be operated with a gas inlet temperature between 38° C. (100° F.) and 66° C. (150° F.) and a column overhead pressure of 3 MPa (gauge) (435 psig) to 5.5 MPa (800 psig). The temperature of the sweetened gas stream fed to the adsorption column 100 can be between 20° C. (68° F.) and 80° C. (176° F.), and the temperature of the adsorbent stream in the adsorbent line 102 can be between 20° C. (68° F.) and 70° C. (158° F.).

[0100] The adsorbed purified gas stream in line 104 may be recycled to the hydroprocessing section 25, and in particular to the guard bed 30 and / or the hydroprocessing reactor 32. In embodiments, the adsorbed purified gas stream in adsorber overhead line 104 may be fed to a make-up hydrogen stream in line 120 to supplement the make-up hydrogen stream, thereby providing a make-up hydrogen stream in line 86. The adsorbed purified gas stream may be added to the make-up hydrogen stream in line 120 to increase the hydrogen concentration of the adsorbed purified gas stream in overhead line 104. The return gas stream in line 68, possibly along with the sulfided regenerant stream in line 206, may be added to the make-up hydrogen stream in line 86 to provide a recycle hydrogen stream in line 88, which is compressed by compressor 90 to provide a hydrotreated hydrogen stream in line 92 that is recycled to the hydroprocessing section 25, and in particular to the guard bed 30 and / or the hydroprocessing reactor 32. In this embodiment, the hydrotreated hydrogen stream concentration may have a hydrogen concentration of at least greater than 85 wt % with accumulation of carbon monoxide not exceeding 0.5 mol % to 2.5 mol %. Make-up gas is provided from line 122 , which may be compressed in a make-up gas compressor 121 .

[0101] The make-up hydrogen stream in line 120 may be provided from the make-up gas header in line 122 and undergo one or two compression stages before it is supplemented with the contacted purified gas stream in line 104 to provide the make-up gas stream in line 86. The make-up gas stream in line 86 may then be mixed with the return gas stream in line 68 to provide the recycle hydrogen stream in line 88 and compressed in a recycle gas compressor to provide the hydrotreated hydrogen stream in line 92. In one aspect, the make-up hydrogen stream in line 120 is mixed with the contacted purified gas stream in line 104 and the return gas stream in line 68, which gas streams may include the sulfided regenerant stream in line 206.

[0102] The hydrotreating hydrogen stream can be provided in three branches: a feed hydrotreating hydrogen stream in line 16, a guard bed hydrotreating hydrogen stream in line 34, and a reactor hydrotreating hydrogen stream in line 38. The compressed hydrotreating hydrogen stream in line 92 supplies hydrogen to the hydrotreating hydrogen stream in hydrotreating hydrogen line 16, the guard bed hydrogen stream in guard bed hydrogen line 34, and the reactor hydrogen stream in reactor hydrogen line 38. The hydrotreating hydrogen stream comprises at least 60 wt. % hydrogen, suitably at least 80 wt. % hydrogen, more suitably at least 92 wt. % hydrogen, preferably at least 94 wt. % hydrogen, and less than 1 mole % carbon monoxide and hydrogen sulfide, as previously described, to maintain sulfidation of the hydrotreating catalyst in guard bed reactor 30 and hydrotreating reactor 32 in hydrotreating reactor section 25. The hydrogen sulfide in the recycle gas stream that is recycled to the reactor allows for reduction or elimination of any sulfur added to the biorenewable feed stream 12 in line 15. Additionally, reducing the flow rate to the adsorption tower 100 reduces the capacity and adsorption rate to the adsorption tower, thereby reducing operating and investment costs.

[0103] A greater proportion of the recycle gas stream in line 82 relative to the return gas stream in line 68 results in a greater proportion of supplemental make-up gas that must be mixed with the return gas and recycled to the hydroprocessing section 25, and in particular to the guard bed reactor 30 and / or the hydroprocessing reactor 32. However, the use of a solid medium in the TSA unit 80 to transfer hydrogen sulfide from the recycle gas stream to the regenerant gas stream to enable the selective removal of carbon dioxide from the recycle gas stream increases the hydrogen purity of the adsorbed purified gas stream, which enables the reduction or elimination of sulfur injection without increasing the carbon oxide concentration in the gas loop.

[0104] exist Figure 1 In an alternative embodiment, the gas purification unit 105 may be Figure 2 The solid medium purification unit shown. Figure 1 The same configuration Figure 2 The elements in will have Figure 1 With the same reference numerals as in Figure 1 The corresponding components in different configurations Figure 2 Elements in the same figure have the same reference numerals but are indicated by a prime ('). Figure 2 The configuration and operation of the embodiment of Figure 1 The differences are as follows.

[0105] exist Figure 2 In an alternative embodiment, purification unit 105 includes a solid media purification unit 110. The sweetened gas stream in TSA discharge line 212 can be conveyed to solid media purification unit 110 for further purification by contact with a solid media to remove impurities from the sweetened gas stream, thereby providing a contacted purified gas stream in line 118. The solid media purification unit 110 that utilizes a solid media to remove impurities can be a pressure swing adsorption unit, a temperature swing adsorption unit, or a membrane unit.

[0106] exist Figure 2 In the embodiment of the present invention, the solid media purification unit 110 is a pressure swing adsorption (PSA) unit 112. In the PSA unit 110, the sweetened gas stream in line 212 can be fed to the PSA unit 110 where hydrogen passes through the adsorbent in the plurality of beds 114 while larger impurity molecules (such as carbon monoxide, carbon dioxide, hydrogen sulfide, and hydrocarbons) are adsorbed onto the adsorbent in the beds.

[0107] The exemplary PSA unit 110 operates on the following principles: selectively adsorbing hydrocarbons and impurities (such as carbon dioxide, carbon monoxide, hydrogen sulfide and / or nitrogen) onto an adsorbent at a relatively high pressure (such as 1,920 kPa to 5,520 kPa gauge) to form a contacted purified gas feed stream 118, and desorbing the hydrocarbons and impurities from the adsorbent at a relatively low pressure (such as 7 kPa to 840 kPa gauge) to regenerate the adsorbent and form a feed stream 116 rich in tail gas impurities containing hydrocarbons and / or other impurities (such as carbon oxides and hydrogen sulfide).

[0108] In an exemplary embodiment, the PSA unit 110 includes a plurality of fixed adsorbent beds 114 containing a solid medium as an adsorbent. Each adsorbent bed 114 comprises layers of different adsorbent materials, wherein one or more lower layers are filled with a relatively weak adsorbent material having a relatively low affinity for adsorbing gaseous hydrocarbons, and one or more upper layers are filled with a relatively strong adsorbent material having a relatively high affinity for adsorbing gaseous hydrocarbons and impurities. For example, the lower layers may contain a weak adsorbent material such as activated alumina and / or silica gel, while the middle layers may contain a medium-strength adsorbent material such as activated carbon, and the upper layers may contain a strong adsorbent material such as a zeolite and / or molecular sieve material.

[0109] In an exemplary embodiment, a plurality of fixed bed adsorption units are operated in a staggered order to operate in conjunction with each other to constantly feed the sweet gas stream in line 212' and produce a contacted purified gas stream in line 118 and an impurity-rich tail gas stream in line 116. In an exemplary embodiment, the PSA unit 110 is operated after a five-step pressure swing cycle comprising an adsorption step, a co-current decompression step, a countercurrent decompression step, a purge step, and a repressurization step. The adsorbent beds 114 can be connected in series to a cycle between pressures. During the adsorption step, the sweet gas stream in line 212' enters the lower portion of the fixed bed adsorption unit at a relatively high pressure, and as the feed gas rises in the unit, hydrocarbons and impurities (e.g., carbon monoxide and / or hydrogen sulfide) are adsorbed in the layers of the adsorbent material according to their respective adsorption selectivities to form a contacted purified gas stream in line 118. The co-current decompression, counter-current decompression and purge steps respectively reduce the pressure in the fixed bed adsorption unit and purge the unit with high purity gas from the contacted purified gas stream in pipeline 118 or the co-current decompression step to remove hydrocarbons and impurities and regenerate the adsorbent material. The flow to each adsorbent bed 114 is periodically terminated, and the pressure in the terminated bed is reduced in stages to release the void space gas and then purge. A purge pressure of 7 kPa (1 psia) to 840 kPa (120 psia) can be used to desorb hydrogen from the adsorbent. Decompression or purge desorbs the adsorbed impurities from the adsorbent in the bed and transfers them to the stream rich in tail gas impurities in pipeline 116. In preparation for the next adsorption step, the re-pressurization step uses the feed gas from the sweetened gas stream in pipeline 212' or the contacted purified gas stream in pipeline 118 to increase the pressure in the fixed bed adsorption unit. Other pressure swing adsorption configurations can be used.

[0110] An impurity-rich stream rich in carbon oxides and light hydrocarbons exits the PSA unit 112 in tail gas line 116. The tail gas impurity-rich stream in line 116 can be fed, along with a cold hydrotreated liquid stream in line 66', to the stripper column 70 of the product recovery section 75 to recover light hydrocarbons, typically in the stripper overhead line 72. From 70 mole percent to 94 mole percent of the hydrogen fed to the PSA unit 112 can be recovered in a contacted purified gas stream in line 118 at a purity between 90 mole percent and 99.9 mole percent.

[0111] A stream deficient in hydrogen sulfide and carbon oxides, such as the make-up hydrogen stream in line 204, can be used to regenerate the TSA unit 80. The purified gas stream contacted in line 118 can be added to the make-up hydrogen stream 120 to supplement the make-up hydrogen stream delivered to the hydroprocessing section 25, and in particular, to the guard bed reactor 30 and / or the hydroprocessing reactor 32. The purified gas stream contacted in line 118 can have at least 98 mol% hydrogen, suitably at least 99 mol% hydrogen, and preferably at least 99.9 mol% hydrogen at 3.5 MPa (500 psia) to 5.5 MPa (800 psia). In one aspect, the purified gas stream contacted in line 118 can have a composition and pressure similar to that of the make-up hydrogen stream in line 120.

[0112] exist Figure 2 In an alternative embodiment, the purification unit 105" may be a unit comprising Figure 3 The solid medium purification unit 110 of the membrane unit 130 shown has Figure 1 or Figure 2 The same configuration Figure 3 The elements in will have Figure 1 or Figure 2 With the same reference numerals as in Figure 1 or Figure 2 The corresponding components in different configurations Figure 3 The elements in the same figure will have the same reference numerals, but will be represented by double primes (''). Figure 3 The configuration and operation of the embodiment of Figure 2 The differences are as follows.

[0113] exist Figure 3 In the method 10", the solid medium purification unit 110" utilizes a membrane unit 130 as a solid medium to remove impurities from the sweetened gas stream in the pipeline 212", such as Figure 3 As shown. The pressure of the sweet gas stream in line 212" can be reduced to 4.8 MPa (700 psig) to 11.4 MPa (1650 psig), suitably 4.9 MPa (710 psig) to 5.2 MPa (760 psig). The depressurized sweet gas stream can be cooled in cooler 132 to a temperature between 32°C (90°F) and 60°C (140°F) to provide a depressurized, cooled purge gas stream that may contain some liquid, which is removed in membrane separator 134 in liquid line 136. The dry, depressurized, cooled purge gas stream in membrane separator overhead line 138 can then be heated in heater 140 to a temperature of 43°C (110°F) to 82°C (180°F) to provide a heated, dry, cooled membrane feed stream that is fed to membrane unit 130 in membrane feed line 133.

[0114] Membrane unit 130 utilizes a permeable solid medium including membrane 146 to achieve separation. In membrane unit 130, the membrane feed stream in line 133 contacts one side of membrane 146, which allows hydrogen to preferentially diffuse through the membrane relative to impurities including carbon dioxide, carbon monoxide, and hydrocarbons. Permeate contacting purified stream 118″ is removed from the opposite side of membrane 146, the membrane containing a higher concentration of hydrogen than in the sweep gas stream and a lower concentration of impurities than in the sweep gas stream. The retentate stream resides on one side of membrane 146 and has a higher concentration of impurities, carbon monoxide, carbon dioxide, and light hydrocarbons than in the sweet gas stream, and a lower concentration of hydrogen than in the sweet gas stream in line 212″. From membrane unit 130, the hydrogen concentration in the permeate contacting the purified stream in permeate line 118″ can be at least 90 mole percent and suitably at least 94 mole percent, preferably at least 95 mole percent, and most preferably at least 96 mole percent, with the carbon monoxide and carbon dioxide concentrations each being less than 1 mole percent.

[0115] The pressure and temperature of the impurity-rich stream in the retentate line 116" can be substantially the same as the pressure and temperature of the membrane feed stream in line 133. The pressure of the permeate in contact with the purified gas stream in the permeate line 118" can be between 35 kPa (5 psig) and 3.1 MPa (450 psig), which can be less than half the pressure of the membrane feed stream in line 133. The temperature of the permeate feed stream will be the same as the membrane feed stream in line 133. The membranes 146 can be installed as multiple tubes into the membrane unit 130 with or without a supporting backing. The membrane feed stream in line 133 can be fed into the interior of the tubes, with the permeate diffusing out of the periphery of the tubes.

[0116] The impurity-rich stream in retentate line 116" may be fed to stripper 70 of recovery section 75 along with the cold hydrotreated liquid stream in line 66". Alternatively, the impurity-rich stream may be forwarded to a fuel gas header, possibly after undergoing adsorption to remove acid gases, such as in a process similar to Figure 1 The permeate that contacts the purified gas stream in permeate line 118" has sufficient hydrogen purity to supplement the make-up hydrogen stream in line 122 and may be at a pressure capable of mixing with the make-up gas in line 122.

[0117] Membrane 146 can include a highly selective membrane available from UOP LLC. In one aspect, the membrane can include a hollow fiber membrane or a spiral wound membrane. The membrane can comprise polyimide, cellulose acetate, cellulose triacetate, polysulfone, polyethersulfone, polyamide, polyphenylene oxide, polyetheretherketone, or combinations thereof, which are suitable for separating hydrogen from larger impurities.

[0118] The solid media purification unit 110 for purifying the sulfided recycle gas stream may be, for example, Figure 1 A TSA as described above, but having an adsorbent that selectively adsorbs carbon dioxide.

[0119] The foregoing disclosure enables the hydroprocessing of biorenewable feedstocks while retaining sulfur in the recycle gas to omit or eliminate the injection of sulfur into the feed to the hydroprocessing reactor section 25 to maintain hydroprocessing catalyst activity.

[0120] Example

[0121] We simulated the operation of a TSA unit to illustrate the present disclosure by running a feed containing several species over an adsorbent bed for the purpose of selectively adsorbing hydrogen sulfide and leaving carbon dioxide in the outlet stream. The feed had the species shown in the table. The adsorbent was a ZnX adsorbent purchased from UOP LLC, Des Plaines. The gas stream was fed to the adsorbent bed at a temperature of 35°C and a pressure of 52 barg. The adsorbed gas stream exited the adsorbent bed, and the percentages of species removed are shown in the table.

[0122] surface

[0123]

[0124]

[0125] To ensure that the adsorbent could be regenerated, a portion of the adsorbent gas stream was heated to 250°C and a pressure of 52 barg and fed back countercurrently through the adsorbent bed. By removing all hydrogen sulfide adsorbed to the bed, only 25% by volume of the adsorbent gas was required to regenerate the adsorbent bed.

[0126] Specific implementation plan

[0127] While the following is described in conjunction with specific embodiments, it should be understood that this description is intended to illustrate and not to limit the scope of the foregoing description and the appended claims.

[0128] A first embodiment of the present invention is a method for hydroprocessing a biorenewable feedstock, the method comprising hydroprocessing a feed stream comprising a biorenewable feedstock in the presence of a hydroprocessing hydrogen stream and hydrogen sulfide and a hydroprocessing catalyst to hydrodeoxygenate the feed stream to provide a hydroprocessed stream; separating the hydroprocessed stream into a hydroprocessed liquid stream and a hydroprocessed gas stream comprising hydrogen, carbon dioxide, and hydrogen sulfide; withdrawing a recycle gas stream from the hydroprocessed gas stream; contacting the recycle gas stream with a solid medium to remove hydrogen sulfide from the recycle gas stream, thereby providing a sweetened gas stream and a sulfided solid medium; contacting the sulfided solid medium with a regenerant stream to provide a sulfided regenerant stream and a sweetened solid medium; and recycling the sulfided regenerant stream to the hydroprocessing step. Embodiments of the present invention are one, any, or all of the preceding embodiments in this paragraph through the first embodiment in this paragraph, wherein the solid medium is an adsorbent comprising a 13X molecular sieve exchanged with zinc ions. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the first embodiment in this paragraph, further comprising recycling the sweetened gas stream to the hydrotreating step. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the first embodiment in this paragraph, further comprising purifying the sweetened gas stream to remove impurities from the sweetened gas stream to provide a purified gas stream. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the first embodiment in this paragraph, further comprising contacting the sweetened gas stream with an adsorbent stream to adsorb acid gases from the sweetened gas stream. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the first embodiment in this paragraph, further comprising contacting the sweetened gas stream with a solid medium to remove impurities from the sweetened gas stream. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the first embodiment in this paragraph, further comprising recycling the purified gas stream to the hydrotreating step. Embodiments of the invention are one, any, or all of the preceding embodiments in this paragraph through the first embodiment in this paragraph, further comprising mixing the purified gas stream with a hydrogen stream. Embodiments of the invention are one, any, or all of the preceding embodiments in this paragraph through the first embodiment in this paragraph, further comprising using a make-up hydrogen stream as a regenerant stream. Embodiments of the invention are one, any, or all of the preceding embodiments in this paragraph through the first embodiment in this paragraph, further comprising removing a return gas stream from the hydrotreated gas stream and returning the return gas stream to the hydrotreating step.Embodiments of the invention are one, any or all of prior embodiments in this paragraph through the first embodiment in this paragraph further comprising splitting the hydrotreated gas stream into a recycle gas stream and a return gas stream. Embodiments of the invention are one, any or all of prior embodiments in this paragraph through the first embodiment in this paragraph wherein the hydrotreating step further comprises contacting the feed stream in a guard bed reactor in the presence of hydrogen and hydrogen sulfide to saturate the olefins and remove metals to produce the contacted feed stream.

[0129] A second embodiment of the present invention is a method for hydrotreating a biorenewable feedstock, the method comprising hydrotreating a feed stream comprising a biorenewable feedstock in the presence of a hydrotreating hydrogen stream and hydrogen sulfide and a hydrotreating catalyst to hydrodeoxygenate the feed stream to provide a hydrotreated stream; separating the hydrotreated stream into a hydrotreated liquid stream and a hydrotreated gas stream comprising hydrogen, carbon dioxide, and hydrogen sulfide; removing a recycle gas stream from the hydrotreated gas stream; contacting the recycle gas stream with a solid medium to remove hydrogen sulfide from the recycle gas stream, thereby providing a sweetened gas stream and a sulfided solid medium; contacting the sulfided solid medium with a regenerant stream to provide a sulfided regenerant stream and a sweetened solid medium; purifying the sweetened gas stream to remove impurities from the sweetened gas stream, thereby providing a purified gas stream. An embodiment of the present invention is one, any, or all of the previous embodiments in this paragraph through the second embodiment in this paragraph, further comprising recycling the sulfided regenerant stream to the hydrotreating step. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the second embodiment in this paragraph, further comprising removing a regenerant stream from the make-up hydrogen stream. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the second embodiment in this paragraph, wherein the purification step comprises contacting the sweetened gas stream with an adsorbent stream to adsorb acid gases from the sweetened gas stream to provide a purified gas stream. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the second embodiment in this paragraph, wherein the purification step comprises contacting the sweetened gas stream with a solid medium to remove impurities from the sweetened gas stream to provide a purified gas stream. An embodiment of the present invention is one, any one, or all of the previous embodiments in this paragraph through the second embodiment in this paragraph, further comprising recycling the purified gas stream to the hydrotreating step.

[0130] A third embodiment of the present invention is a method for hydrotreating a biorenewable feedstock, which includes hydrotreating a feed stream comprising a biorenewable feedstock in the presence of a hydrotreating hydrogen stream and hydrogen sulfide and a hydrotreating catalyst to hydrodeoxygenate the feed stream to provide a hydrotreated stream; separating the hydrotreated stream into a hydrotreated liquid stream and a hydrotreated gas stream comprising hydrogen, carbon dioxide and hydrogen sulfide; withdrawing a recycle gas stream from the hydrotreated gas stream; contacting the recycle gas stream with a solid medium to remove hydrogen sulfide from the recycle gas stream, thereby providing a sweetened gas stream and a sulfided solid medium; contacting the sulfided solid medium with a regenerant stream to provide a sulfided regenerant stream and a sweetened solid medium; purifying the sweetened gas stream to remove carbon dioxide from the sweetened gas stream, thereby providing a purified gas stream; and recycling the sulfided regenerant stream to the hydrotreating step. An embodiment of the present invention is one, any one or all of the previous embodiments in this paragraph through the third embodiment in this paragraph, wherein the purification step comprises contacting the sweetened gas stream with an adsorbent stream to adsorb acid gases from the sweetened gas stream to provide a purified gas stream. An embodiment of the present invention is one, any one or all of the previous embodiments in this paragraph through the third embodiment in this paragraph, further comprising recycling a portion of the purified gas stream to the hydrotreating step. Although not further described in detail, it is believed that one skilled in the art can utilize the present disclosure to the greatest extent possible by using the foregoing description and can readily ascertain the basic features of the present disclosure without departing from the spirit and scope of the present invention, and can make various changes and modifications to the present disclosure and adapt it to various uses and conditions. Therefore, the foregoing preferred specific embodiments should be understood as merely illustrative and not limiting in any way the remainder of the disclosure, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

[0131] In the foregoing, all temperatures are set forth in degrees Celsius and all parts and percentages are by weight unless otherwise indicated.

Claims

1. A method for hydroprocessing a biorenewable feedstock, the method comprising: hydrotreating a feed stream comprising a biorenewable feedstock in the presence of a hydrotreating hydrogen stream and hydrogen sulfide and a hydrotreating catalyst to hydrodeoxygenate the feed stream to provide a hydrotreated stream; separating the hydrotreated stream into a hydrotreated liquid stream and a hydrotreated gas stream comprising hydrogen, carbon dioxide, and hydrogen sulfide; withdrawing a recycle gas stream from the hydrotreated gas stream; contacting the recycle gas stream with a solid medium to remove hydrogen sulfide from the recycle gas stream, thereby providing a sweetened gas stream and a sulfided solid medium; contacting the sulfided solid medium with a regenerant stream to provide a sulfided regenerant stream and a desulfurized solid medium; and recycling the sulfided regeneration agent stream to the hydrotreating step, The solid medium is an adsorbent comprising 13X molecular sieves exchanged with zinc ions.

2. The process of claim 1 further comprising recycling the sweetened gas stream to the hydrotreating step.

3. The method of claim 1, further comprising purifying the sweetened gas stream to remove impurities from the sweetened gas stream, thereby providing a purified gas stream.

4. The method of claim 2, further comprising contacting the sweet gas stream with an adsorbent stream to adsorb acid gases from the sweet gas stream.

5. The method of claim 2, further comprising contacting the sweetened gas stream with a solid medium to remove impurities from the sweetened gas stream.

6. The process of claim 3, further comprising recycling the purified gas stream to the hydrotreating step.

7. The method of claim 3, further comprising mixing the purified gas stream with a hydrogen stream.

8. The method of claim 3, further comprising withdrawing the purified gas stream from a make-up hydrogen stream.

9. The process of claim 1 further comprising withdrawing a return gas stream from the hydrotreated gas stream and returning the return gas stream to the hydrotreating step.

Images