A process of reforming a renewable naphtha and composition

Abstract

A process of reforming a renewable naphtha is disclosed. The process comprises hydrotreating a renewable naphtha stream with a hydrotreating hydrogen stream in the presence of a hydrotreating catalyst in a hydrotreating reactor to produce a hydrotreated naphtha stream. The hydrotreated naphtha stream is reformed with a hydrogen stream in the presence of a reforming catalyst in a reforming reactor at reforming conditions comprising an average inlet temperature of no more than about 550°C to produce a reformed naphtha stream comprising greater than about 50 wt% aromatics. A reformed naphtha composition is also disclosed. The reformed naphtha composition comprises greater than about 50 wt% aromatics and a Research Octane Number of greater than about 80.

Description

A PROCESS OF REFORMING A RENEWABLE NAPHTHA AND COMPOSITIONFIELD

[0001] The field is related to a process of reforming a renewable naphtha. Particularly, the field relates to a process of reforming a renewable naphtha produced from bio-oil.BACKGROUND

[0002] Bio-oils are obtained by thermochemical processes including liquefaction, or pyrolysis. Notably, biomass pyrolysis includes several classes of processes such as flash, fast, slow or catalytic pyrolysis. Pyrolysis is a thermal decomposition process in the absence of oxygen with thermal cracking of the feedstocks to gas, liquid and solid products. A catalyst can be added to enhance the conversion in catalytic pyrolysis. Various technologies have been deployed for large scale biomass pyrolysis. They include bubbling fluidized beds, circulating fluidizing beds, ablative pyrolysis, vacuum pyrolysis, and rotating cone pyrolysis reactors.Catalytic pyrolysis generally leads to a bio-oil having a lower oxygen content than bio-oil obtained by thermal decomposition. The selectivity between gas, liquid and solid, typically about 35 wt% gas, about 30 wt% liquid, and about 35 wt% char, is well related to the reaction temperature and vapor residence time. Lower temperature, for example, about 400°C, and longer residence time, for example, a few minutes to a few hours, obtained by slow pyrolysis, favors the production of a solid product, also called char. Very high temperatures above about 800°C used in the gasification processes favors gas production, typically more than 85 wt%. Intermediate reaction temperature, typically about 450°C to about 550°C, and short vapor residence time, typically about 10 to about 20 seconds, for the pyrolysis, favor the liquid yield: typically about 30 wt% gas, about 50 wt% liquid, and about 20 wt% char. Intermediate reaction temperature, typically about 450°C to about 550°C, and very short vapor residence time, typically about 1 to about 2 seconds, for the flash pyrolysis or fast pyrolysis, favor even more the liquid yield: typically about 10 to about 20 wt% gas, about 60 to about 75 wt% liquid, about 10 to about 20 wt% char. The highest liquid yields may be obtained by the flash pyrolysis processes, such as up to about 75 wt%.

[0003] Bio-oils can be processed to provide low-cost renewable liquid fuels; indeed, they can be used as fuel for boilers, as well as for stationary gas turbines and diesel engines. Furthermore, fast pyrolysis has been demonstrated at fairly large scales, of the order of several hundred tons per day. Nevertheless, there has not been any significant commercial uptake of this technology. The reasons may relate mostly to the poor physical and chemical properties of bio-oils in general and fast pyrolysis bio-oils in particular. For example, some of the undesirable properties of pyrolysis bio-oils may include; (1) corrosivity on account of their high water and acidic contents; (2) relatively low specific calorific value on account of the high oxygen content, which typically is about 40% or more by mass; (3) chemical instability on account of the abundance of reactive functional groups like carboxyl groups and phenolic groups that can lead to polymerization on storage and consequent phase separation; (4) relatively high viscosity and susceptibility to phase separation under high shear conditions, for instance in a nozzle; (5) incompatibility with, on account of insolubility in, conventional hydrocarbon based fuels; (6) blockage in nozzles and pipes caused by adventitious char particles, which will always be present in unfiltered bio-oil to a greater or lesser degree. All these aspects combine to render bio-oil handling, shipping storage and usage difficult and expensive.

[0004] The economic viability of bio-oil production for fuel or energy applications therefore depends on finding appropriate methods to upgrade it to a higher quality liquid fuel at a sufficiently low cost.

[0005] To meet sustainability goals and regulatory requirements for carbon intensity reductions, the transportation sector is turning to renewable fuels. One such fuel is naphtha, which is currently mostly derived from petroleum. While a majority of the renewable fuel market is targeted towards sustainable aviation fuel and renewable diesel, renewable naphtha or gasoline will also play a role in the renewable fuels space. There are already credits that exist for these renewable fuels, such as renewable identification numbers (RIN) credits. Gasoline fuels in the United States can contain about 10%. about 15% or even higher ethanol by volume, which is the biggest source of oxygenated blend stock. However, the amount of ethanol is limited in most cars due to incompatibility issues and engine problems at higher blends. And while ethanol is produced from a sustainable source such as com, the reduction in carbon intensity of ethanol blends is lower than that of other fuels, such as ones derived from biomass. Additionally, the useof ethanol in fuels competes with human consumption of corn, whereas fuels derived from biomass do not for human consumption. Nevertheless, there exists an addressable market with significant demand for renewable naphtha, including both oxygenated naphtha and deoxygenated naphtha.

[0006] Therefore, there is a need for improved processes for producing renewable naphtha.SUMMARY

[0007] A process of reforming a renewable naphtha is disclosed. The process comprises hydrotreating a renewable naphtha stream with a hydrogen stream in the presence of a hydrotreating catalyst in a hydrotreating reactor to produce a hydrotreated naphtha stream. The hydrotreated naphtha stream is reformed with a reforming hydrogen stream in the presence of a reforming catalyst in a reforming reactor at reforming conditions comprising an inlet temperature of no more than about 550°C to produce a reformed naphtha stream comprising greater than about 50 wt% aromatics. A reformed naphtha composition is also disclosed. The reformed naphtha composition comprises greater than about 50 wt% aromatics and a Research Octane Number of greater than about 80. The present disclosure envisages co-processing of a biogenic and a petroleum based material in a reformer at different percentages. The present disclosure provides refineries an opportunity to produce sustainable and valuable products while addressing market demands for green gasoline and petrochemicals.BRIEF DESCRIPTION OF THE DRAWINGS

[0008] FIG. 1 illustrates a schematic diagram of a process of reforming a renewable naphtha in accordance with an embodiment of the present disclosure.

[0009] FIG. 2 is a plot showing the relationship between C5+ liquid yield and Research Octane Number Calculated (RONC), demonstrating that high-octane reformed naphtha can be produced while maintaining high C5+ yields.

[0010] FIG. 3 is a plot illustrating the relationship between C5+ liquid yield and aromatics content in the reformed naphtha, showing that high aromatics levels are achievable without significant loss of C5+ liquid product.DEFINITIONS

[0011] As used herein the terms “reactor”, “process equipment,” “process units,” or “reactor components” shall include any and all process equipment and process units that are utilized in biomass, bio-oil, or hydrocarbon conversion processes including any upstream and / or downstream equipment from the particular unit and / or ancillaries, such as furnace tubes, associated piping, heat exchangers, heater tubes, and the like.

[0012] As used herein, the term “predominant” or “predominate” or “predominance” means greater than 50%, suitably greater than 75% and preferably greater than 90%.

[0013] As used herein, the term “carbon number” refers to the number of carbon atoms per molecule.

[0014] As used herein, “petroleum stream” or “petroleum feedstock” may refer to crude oil, crude oil refinery distillates, crude oil refinery residue, cracked products or hydrocarbons from a crude oil refinery, liquefied coal, bitumen, typically extracted from the ground or sea floor.

[0015] As used herein, the term “True Boiling Point” (TBP) means a test method for determining the boiling point of a material which corresponds to ASTM D-2892 for the production of a liquefied gas, distillate fractions, and residuum of standardized quality on which analytical data can be obtained, and the determination of yields of the above fractions by both mass and volume from which a graph of temperature versus mass % distilled is produced using fifteen theoretical plates in a column with a 5:1 reflux ratio.

[0016] As used herein, the term “T5”, “T10” or “T90” means the temperature at which 5 mass percent or 10 mass percent or 90 mass percent, as the case may be, respectively, of the sample boils using ASTM D-86 or TBP. In examples herein, the T5, T10, T90 and other distillation properties of a laboratory or pilot plant sample may at times be accurately estimated by simulated distillation, methods such as ASTM D2887, ASTM D2713, ASTM D632 or ASTM D7169, which utilize calibrated gas chromatographic analyses to simulate the boiling distribution of a sample.

[0017] As used herein, the term “vacuum gas oil” (VGO) includes hydrocarbons having an initial boiling point above approximately 343 °C (650°F), with a T10 boiling point temperature using ASTM DI 160 of approximately 370°C (698°F) and a T90 boiling point temperature using ASTM DI 160 of approximately 500°C (932°F).

[0018] As used herein, the terms “mol% H” and “mol% C” refer to the percentage of moles of hydrogen or carbon atoms, respectively, of the total moles of hydrogen or carbon atoms in oil. For example, if the bio-oil composition contains 5 moles of hydrogen atoms and 10 moles of carbon atoms and it is said that the bio-oil contains 10 mol% H of aldehydes and 20 mol % C of carboxylic acids and esters it means that 0.5 moles of hydrogen atoms in the bio-oil correspond to H atoms of molecules within an aldehyde functional group and 2 moles of carbon atoms in the bio-oil correspond to C atoms of molecules within either a carboxylic acid or ester functional group.

[0019] As used herein, the term “bioderived” or “biogenic” material means a material that comes from or is made from or obtained from plants, animals, microorganisms, algae, or biopolymers, as opposed to a petroleum material extracted from the ground.

[0020] As used herein, the term “bio-oil” refers to any liquid organic material derived from biological or biomass sources, including but not limited to pyrolysis oil, hydrothermal liquefaction oils, catalytically upgraded bio-oils, partially deoxygenated bio-oils, stabilized bio-oils, or any intermediates thereof.

[0021] As used herein, the term “renewable naphtha” refers to a hydrocarbon fraction derived from bio-oil or other biogenic, non-fossil carbon sources, the fraction typically boiling within the naphtha range and comprising hydrocarbons having from 5 to 12 carbon atoms.Renewable naphtha may be obtained by hydrotreating, hydrocracking, hydrodeoxygenation, decarboxylation, decarbonylation, stabilization, fractionation, or other upgrading of bio-oil or biomass-derived intermediates.

[0022] As used herein, the term “biogenic naphtha” refers to a naphtha-range hydrocarbon composition comprising carbon derived predominantly from biomass or other biological sources.

[0023] As used herein, the term “recycle ratio” or “recycle rate” means the ratio of the recycle flow rate to the fresh feed flow rate.

[0024] As used herein, the term “carbon number” means the number of carbon atoms in a molecule. Particular carbon numbers are often abbreviated as CX where X is the number of carbon atoms in a molecule. For instance, C8 paraffins refers to paraffins containing 8 carbon atoms.

[0025] As used herein, the term “cyclopentanes” refers to naphthene (cycloparaffin) molecules containing a cyclopentane ring and the term “cyclohexanes” refers to naphthene (cycloparaffin) molecules containing a cyclohexane ring. Cyclopentanes and cyclohexanes are sometimes abbreviated as N5 and N6 respectively. Cyclopentanes and cyclohexanes can have additional methyl groups and alkyl groups attached to the ring. For instance, a molecule such as methylcyclohexane will be denoted as a cyclohexane (N6), whereas ethylcyclopentane will be denoted as a cyclopentane (N5), despite both molecules containing 7 carbon atoms (C7).

[0026] As used herein, the terms “cyclic compounds”, “cyclic molecules”, “cyclic species”, or “cyclic” refer to compounds with cyclic structures including but not limited to aromatics, naphthenes and phenols.DETAILED DESCRIPTION

[0027] Biocrude or bio-oil polymerization during deoxygenation or hydrotreating reactions is a major challenge when attempting to convert bio-oil to fuels. The present disclosure provides a process to upgrade a biomass-based feed such as bio-oil in the presence of a catalyst to produce an upgraded bio-oil which can be used directly or fractionated to produce renewable naphtha, particularly an oxygenated renewable naphtha. Further, the renewable naphtha can be hydrotreated to produce a deoxygenated naphtha which, in turn, may be further processed in catalytic reforming units to improve combustion quality and / or enhance stability.

[0028] Bio-oil perhaps derived from lignocellulosic biomass is a complex mixture of compounds, including oxygenates, that are obtained from the breakdown of biopolymers in biomass. Bio-oils can be derived from plants such as grasses and trees, wood chips, chaff, grains, grasses, corn, corn husks, weeds, aquatic plants, hay and other sources of lignocellulosic material, such as derived from municipal waste, food processing wastes, forestry wastes and cuttings, energy crops, or agricultural and industrial wastes (such as sugar cane bagasse, oil palm wastes, sawdust or straws). Bio-oils can also be derived from pulp and paper byproducts (recycled or not). Bio-oils are generally obtained from these biomass feeds by thermochemical liquefaction, notably pyrolysis, such as flash, fast, slow or catalytic pyrolysis. Hydrothermal liquefaction may also be utilized to generate bio-oil feeds. Several different processes which produce bio-oil can be utilized to produce biocrude feed.

[0029] Bio-oil is a highly oxygenated, polar hydrocarbon product that typically contains at least about 10 mass% oxygen, typically about 10 to 60 mass% oxygen, and more typically about 30 to about 50 mass% oxygen on a water-free basis. In general, bio-oil comprises oxygenates that may include alcohols, aldehydes, ketones, acetates, ethers, esters, organic acids and aromatic oxygenates. Oxygen is also present as free water which constitutes at least about 10 mass%, typically about 15 to about 35 mass% of the bio-oil. These properties render bio-oil immiscible with fuel grade hydrocarbons, even with aromatic hydrocarbons, which typically contain little or no oxygen.

[0030] In an aspect of the present disclosure, the biomass-based feed stream may comprise a bio-oil stream obtained by pyrolysis of a biomass feedstock.

[0031] The biomass-based feed stream in the present disclosure may further contain other oxygenates derived from biomass such as vegetable oils or animal fat derived oils. Vegetable oil or animal fat-derived oil comprises fatty matter and therefore corresponds to a natural or elaborate substance of animal or vegetable origin, mainly containing triglycerides. This essentially involves oils from renewable resources such as fats and oils from vegetable and animal resources (such as lard, tallow, fowl fat, bone fat, fish oil and fat of dairy origin), as well as the compounds and the mixtures derived therefrom, such as fatty acids or fatty acid alkyl esters. The products resulting from recycling animal fat and vegetable oils from the food processing industry can also be used, pure or in admixture with other constituent classes described above. The feeds may comprise vegetable oils from oilseed such as rape, erucic rape, soybean, jatropha, sunflower, palm, copra, palm-nut, arachidic, olive, com, cocoa butter, nut, linseed oil or oil from any other vegetable. These vegetable oils very predominantly consist of fatty acids in the form of triglycerides (generally above 97% by mass) having long alkyl chains ranging from 8 to 24 carbon number, such as butyric fatty acid, caproic, caprylic, capric, lauric, myristic, palmitic, palmitoleic, stearic, oleic, linoleic, linolenic, arachidic, gadoleic, eicosapentaenoic (EPA), behenic. erucic, docosahexaenoic (DHA) and lignoceric acids. The fatty acid salt, fatty acid alkyl ester and free fatty acid derivatives such as fatty alcohols that can be produced by hydrolysis, by fractionation or by transesterification, for example, of triglycerides or of mixtures of these oils and of their derivatives also come into the definition of the “oil of vegetable or animal origin” feed in the present disclosure. All products or mixtures of productsresulting from the thermochemical conversion of algae or products from the hydrothermal conversion of lignocellulosic biomass or algae (in the presence of a catalyst or not) or pyrolytic lignin are also feeds that can be used.

[0032] In an aspect of the present disclosure, the biomass-based feed stream or the renewable feed may comprise a solid biomass-derived material, including but not limited to lignin, lignocellulosic solids, partially depolymerized biomass, pyrolytic lignin, char, thermochemically treated biomass residues, or any other solid organic material originating from plant, algal, microbial, or animal sources. Such solid biomass materials may be introduced directly into an upgrading or hydrotreating reactor, or may be provided as a slurry, dispersion, suspension, or mixture with a liquid carrier such as bio-oil, water, or a hydrocarbon solvent. Upgrading, hydrotreating, hydrodeoxygenation, or other processing of these solid-containing feeds produces an upgraded bio-derived intermediate from which a renewable naphtha fraction can be recovered and subsequently reformed in accordance with the present disclosure.

[0033] Moreover, the feed containing bio-oil can be coprocessed with petroleum and / or coal derived hydrocarbon feedstocks. The petroleum derived hydrocarbon feed stock can be straight run vacuum distillates, vacuum distillates from a conversion process such as those from coking, from fixed bed hydroconversion or from ebullated bed or slurry hydrocracking heavy fraction hydrotreatment processes, or from solvent deasphalted oils. The feed can also be formed by mixing those various fractions in any proportions in particular deasphalted oil and vacuum distillate. They can also contain products from the fluid catalytic cracking units, such as light cycle oil (LCO) of various origins, heavy cycle oil (HCO) of various origins and any distillate fraction from fluid catalytic cracking generally having a distillation range of about 150°C to about 370°C. They may also contain aromatic extracts and paraffins obtained from the manufacture of lubricating oils. The coal derived hydrocarbon feedstock can be products from the liquefaction of coal. Aromatics fractions from coal pyrolysis or coal gasification can also be used as bio-mass based feed.

[0034] Referring to the FIG. 1, a process of reforming a renewable naphtha 100 is disclosed in an embodiment of the present disclosure. A bio-oil stream is taken in line 122 from a source, for example, a bio-oil storage drum 120. The bio-oil stream in line 122 may be passed to a mixer 140. Perhaps, the bio-oil stream in line 122 may be pumped via a pump 123 and a pumped bio-oil stream in line 124 may be passed to the mixer 140. In an aspect, a control valve 125 is provided for maintaining a required flow rate of the bio-oil stream to the mixer 140.

[0035] In accordance with the present disclosure, a non-bio derived feed stream may also be passed to the mixer and mixed with the bio-oil stream. In an embodiment of the present disclosure, a petroleum stream is the non-bio derived feed stream. The petroleum stream is taken in line 132 from a source, for example, a petroleum storage drum 130. The petroleum stream in line 132 may be passed to the mixer 140. Perhaps the petroleum stream in line 132 may be pumped via a pump 133 and a pumped petroleum stream in line 134 is passed to the mixer 140. In an aspect, a control valve 135 is provided for maintaining a required flow rate of the petroleum stream to the mixer 140. In an embodiment, a sulfur source comprising a sulfiding agent in line 131 may be added to the petroleum stream in line 132 or the bio-oil stream in line 122 and passed to the mixer 140. The control valves 125 and 135 can be used to control or adjust the proportions of the bio-oil and the petroleum stream fed to the mixer 140.

[0036] In the mixer 140, the bio-oil stream in line 124 and the petroleum stream in line 134 are mixed and kept well mixed at a ratio perhaps with an excess of the petroleum stream at the startup of the process. In an embodiment, the bio-oil stream in line 124 and the petroleum stream in line 134 are mixed in the mixer 140 at a mass ratio of the bio-oil stream and the petroleum stream of less than about 1 at the start-up to provide a mixed stream. After mixing, a mixed stream in line 142 is taken from the mixer 140. In an aspect, the mixed stream 142 comprises the bio-oil stream and the petroleum stream in a ratio of about 0:100 to about 80:20 by mass at startup. In an exemplary embodiment, the petroleum stream in line 134 is vacuum gas oil (VGO). The mixed stream in line 142 may be reacted with hydrogen in the presence of a catalyst in a reactor to produce an upgraded bio-oil stream.

[0037] In an embodiment, the mixed stream in line 142 is charged to a liquid phase hydrotreating (LPH) reactor 150. As described later in detail, a recycle stream in line 139 may also be charged to the reactor 150. Also, a hydrogen stream in line 144 may be charged to the reactor 150. In an embodiment, the hydrogen stream in line 144 may be blended or mixed with the mixed stream in line 142 and charged to the reactor 150. A catalyst stream in line 145 may also be charged to the reactor 150. In an embodiment, the catalyst stream may be blended or mixed with the mixed stream in line 142 to provide a combined stream in line 146 which ischarged to the reactor 150. In another embodiment, the catalyst stream 145 may be added to the recycle stream in line 139 to provide a combined recycle stream which is charged to the reactor 150. In the reactor 150, the petroleum stream, the bio-oil stream, the recycle stream, and the hydrogen stream may be reacted over a catalyst in a continuous liquid phase to provide an upgraded bio-oil stream comprising renewable naphtha in line 154. At least about 50 wt% of the upgraded bio-oil stream is bio-derived. Preferably, about 100 wt% of the upgraded bio-oil stream is bio-derived.

[0038] Liquid phase hydro treating (LPH) is used for upgrading the heavy hydrocarbon feedstocks to produce distillate and residuum products. The hydrotreating catalyst typically comprises a solid particulate compound of a catalytically active metal, metal sulfide, or a metal in elemental form, either alone or supported on a refractory material such as an inorganic metal oxide (e.g., alumina, silica, titania, zirconia, and mixtures thereof). Other suitable refractory materials include carbon, coal, and clays. Zeolites and non-zeolitic molecular sieves are also useful as solid supports. One advantage of using a solid particulate either alone or supported is its ability to act as a “coke getter” or adsorbent of asphaltene precursors that have a tendency to foul process equipment upon precipitation.

[0039] Catalytically active metals for use in LPH include those from Group IVB, Group VB, Group VIB, Group VIIB, or Group VIII of the Periodic Table, which are incorporated in the heavy hydrocarbon feedstock in amounts effective for catalyzing desired hydrotreating reactions to provide, for example, lower boiling hydrocarbons that may be fractionated from the LPH effluent as naphtha and / or distillate products in the substantial absence of the solid particulate. Representative metals include iron, nickel, molybdenum, vanadium, tungsten, cobalt, ruthenium, and mixtures thereof. The catalytically active metal may be present as a solid particulate in elemental form or as an organic compound or an inorganic compound such as a sulfide (e.g., iron sulfide) or other ionic compound. Metal or metal compound nanoaggregates may also be used to form the solid particulates.

[0040] In some embodiments, the metal compounds can be formed in situ, as solid particulates, from a catalyst precursor such as a metal sulfite (e.g., iron sulfite monohydrate) that decomposes or reacts in the LPH reaction zone environment, or in a pretreatment step, to form a desired, well-dispersed and catalytically active solid particulate (e.g., as iron sulfide ormolybdenum sulfide). Catalyst precursors also include oil-soluble organometallic compounds containing the catalytically active metal of interest that thermally decompose to form the solid particulate (e.g., iron sulfide or molybdenum sulfide) having catalytic activity. Such compounds are generally highly dispersible in the heavy hydrocarbon feedstock and normally convert under pretreatment or LPH reaction conditions to the solid particulate that is contained in the slurry effluent. Catalyst precursors also include oil-soluble organometallic compounds, inorganic molybdenum compounds, or chelated metal compounds containing the catalytically active metal. Molybdenum chelates including molybdenum octoate, molybdenum dithiocarbamate, and molybdenum naphthenate and molybdenum compounds such as ammonium heptamolybdate and phosphomolybdic acid thermally decompose to form the solid particulate through reaction with sulfidation components in the feed or other sulfidation additives such as dimethyl disulfide, ditert-butyl (poly)sulfide, dibenzyl disulfide, (di)allyl (di)sulfide, ammonium sulfite, dimethyl sulfite, dithiothreitol, elemental sulfur or thiourea to form, for example, molybdenum disulfide having catalytic activity. An exemplary in situ solid particulate preparation, involving pretreating, the heavy hydrocarbon feedstock and precursors of the ultimately desired metal compound, is described, for example, in US5,474,977.

[0041] In another aspect, a catalyst precursor with the sulfidation component or the sulfidation additive may be provided in a line 131 and added to the petroleum stream in line 132. In another aspect, a catalyst or a catalyst precursor may be added to the feed stream in line 122 or the petroleum stream in line 132.

[0042] Alternatively, such metal sulfides or other active metal compounds can be formed ex-situ or in a separate process step through typical methods for producing metal sulfides. One such method includes hydrothermal synthesis where a molybdenum compound and sulfidation component are added to water with an additional reducing agent such as citric acid, oxalic acid, or hydrochloric acid or gaseous hydrogen. In some cases, the sulfidation component may also act as a reducing agent such as thiourea, ammonium sulfite, dimethyl sulfite, or dithiothreitol. The hydrothermal synthesis solution may be loaded into an autoclave reactor and sealed. If gaseous hydrogen is the reducing agent, the autoclave reactor can be pressurized from about 1378 kPag (200 psig) to about 10342 kPag (1500 psig) with hydrogen gas or the hydrogen gas can flow and bubble through the autoclave reactor. The autoclave reactor is then heated to a synthesistemperature of about 200°C to about 300°C under the foregoing hydrogen or inert gas pressure and held at the synthesis temperature for about 0.5 to about 16 hours. The autoclave reactor is allowed to cool to room temperature before depressurization and unloading. The solid catalyst can be collected such as by centrifugation, filtration, or drying. An example of hydrothermal metal sulfide synthesis is described in J. Espano, Phase Control in the Synthesis of Iron Sulfides, 145 J. Am. Chem. Soc. 18948-18955 (2023).

[0043] Another such method of forming metal sulfides ex situ could be a sulfiding procedure in a fixed bed reactor. Such methods involve loading a fixed bed reactor with a powdered or pelletized molybdenum compound and flowing a sulfiding gas, such as hydrogen sulfide, or a sulfiding liquid, such as oil doped with a sulfiding agent over the catalyst bed. The fixed bed reactor is heated to a sulfiding temperature of about 200°C to about 350°C, for example, under the flow of sulfiding gas and / or hydrogen gas. The reactor is either pressurized before or after heating to sulfiding temperature to a pressure of about 1378 kPag (200 psig) to about 13790 kPag (2000 psig). The reactor may be heated slowly at, for example, l°C / min, and held at selected temperature setpoints along the way to reach the final sulfiding temperature. The reactor may be held at temperature setpoints for hours to days. Once the sulfiding is complete, the reactor is cooled to room temperature and the catalyst is unloaded from the reactor in its metal sulfide form. The sulfided catalyst may be further reduced in particle size via grinding, milling, or other methods, so that it is a fine powder and highly dispersible.

[0044] Yet another method of forming metal sulfides ex situ could be a sulfiding procedure relying on chemical vapor deposition techniques. Such a method involves molybdenum compounds such as molybdenum trioxide, molybdenum dioxide, molybdenum foil, or dipotassium tetrathiomolybdate and sulfur compounds such as elemental sulfur, alkali sulfates, alkaline earth sulfates, or other metal sulfates or similar metal sulfites. A substrate is also used such as SiCE / Si wafers, graphenes / graphites, or powdered or pelletized substrates commonly used as catalyst supports such as SiCh, AI2O3, or TiCh. Using a typical tube furnace synthesis reactor, the reactants and supports are placed in the reactor tube in a specific order with the sulfur source first (furthest upstream) followed by the molybdenum source downstream followed by the substrate further downstream. All compounds mentioned above are placed in a thermal zone in the tube furnace, typically in ceramic or other thermally and chemically resistant holders, whichmay be controlled as independent zones or as one zone. The substrate may be placed outside a thermal zone, if desired. This positioning is such that a gas flow through the tube first contacts the sulfur source, followed by the molybdenum source, followed by the substrate. A gas flow could include inert gas, hydrogen, steam, and / or oxygen / air. In typical operation, a gas flow is started, and the tube furnace reactor zones are heated to a temperature that is suitable to vaporize one or more of the compounds mentioned above at ambient pressure, typically equal to or less than 1000°C. The compounds vaporize and flow downstream where they react with each other and deposit on the substrate. The synthesis may run until complete consumption of all reactants or the substrate may be moved in and out of the apparatus so that the deposition time is limited to several minutes. After synthesis completion, the resulting metal sulfide is collected by removal of the substrate holder. The metal sulfide catalyst can be used as-is or, in the case of depositions of flat substrates like silicon wafers, the catalyst powder may be optionally scraped off for use without the silicon wafer. An example of chemical vapor deposition metal sulfide synthesis is described in W. Fu, TOWARD EDGE ENGINEERING OF TWO-DIMENSIONAL LAYERED TRANSITION-METAL DICHALCOGENIDES BY CHEMICAL VAPOR DEPOSITION,” 17 (17) ACS Nano 16348-16368 (2023).

[0045] Other suitable precursors include metal oxides that may be converted to catalytically active (or more catalytically active) compounds such as metal sulfides. In a particular embodiment, a metal oxide containing mineral may be used as a precursor of a solid particulate comprising the catalytically active metal (e.g., iron sulfide) on an inorganic refractory metal oxide support (e.g., alumina). Bauxite represents a particular precursor in which conversion of iron oxide crystals contained in this mineral provides an iron sulfide catalyst as a solid particulate, where the iron sulfide after conversion is supported on the alumina that is predominantly present in the bauxite precursor.

[0046] The active metals employed in the hydroprocessing catalysts of the present disclosure as hydrogenation components are the base metals of Group VIII. i.e., iron, cobalt, and nickel. In addition to these metals, other metals may also be employed in conjunction therewith, or on their own, including the metals of Group VIB, e.g., molybdenum and tungsten. The amount of hydrogenating metal in the catalyst can vary within wide ranges. Any amount between about 0.05 wt % and about 80 wt % may be used. In an aspect, molybdenum may be provided as aground hydrotreating catalyst of particle size typically less than 60 mesh, preferably less than 100 mesh, more preferably, less than 200 mesh, and even more preferably less than 400 mesh. The hydrotreating catalyst may be sulfided in situ or ex situ using any method mentioned throughout. In an aspect, molybdenum may be provided as an organic molybdenum such as molybdenum octoate or molybdenum dithiocarbamate which because it is oil or hydrocarbon soluble may be added directly to the hydrocarbon feed separately from or with the carbon particles. The molybdenum may react with sulfur provided in the hydrocarbon feed or an additive to produce molybdenum sulfide in the reactor which is the active form of the molybdenum catalyst.

[0047] Nickel may be provided as a catalyst in the way molybdenum is added.

[0048] In another aspect, the catalyst is a nickel and molybdenum sulfide catalyst where nickel is incorporated into the molybdenum sulfide molecular structure to enhance catalytic activity but may also form separate nickel sulfide phases with their own separate catalytic activity. In syntheses mentioned throughout that involve an aqueous solution, nickel can be added by simply introducing a nickel compound to the aqueous solution before heating to final synthesis temperature. In syntheses that involve a solid and gas or a solid and liquid method, nickel compounds may be physically mixed with the molybdenum compounds. For in situ formation of the nickel and molybdenum sulfide in the LPH reactor 150, an oil-soluble nickel compound may be added directly to the feed or added from a separate line into the LPH reactor. Nickel compounds that could be used include nickel octoate, nickel nitrate hexahydrate, nickel sulfate, nickel sulfite, nickel acetate tetrahydrate, nickel citrate hydrate, nickel hydroxide, or nickel hydroxide carbonate. The molar ratio of molybdenum to nickel can range from about 1:1 to about 5:1, preferably about 2:1 to about 4:1, or preferably about 2.5:1 to about 3.5:1.

[0049] The sulfur can be provided by a solid or liquid sulfiding agent that is added via line 131 into the petroleum stream in line 132 or added into a recycle stream to the reactor or premixed into the bio-oil feed. Gaseous sulfiding agents like hydrogen sulfide can be added to the hydrogen line 144. Some preferred sulfiding agents are hydrogen sulfide, dimethyl disulfide, di-tert-butyl (poly) sulfide, dibenzyl disulfide, (di)allyl (di)sulfide, ammonium sulfite, dimethyl sulfite, dithiothreitol, elemental sulfur or thiourea.

[0050] An aqueous molybdenum may be derived from reacting MoOa with an aqueous acid or basic solution such as phosphoric acid or ammonium hydroxide, respectively. Molybdenum in aqueous or oil-soluble liquid form in a volume selected to achieve target concentration may be dropped onto carbon particles which may serve as a carrier.

[0051] Without help from other catalysts, the concentration of the molybdenum in the liquid feeds to the LPH reactor 150 may be more than 0 wppm and no more than about 2 weight % in the liquid feed, suitably no more than about 0.5 weight %in the liquid feed, and typically no more than about 2000 wppm in the liquid feed. In some cases, the concentration of molybdenum may be no less than 1000 wppm in the liquid feed, and preferably not less than 500 wppm of the feed.

[0052] In preferred embodiments where the catalyst contains both nickel and molybdenum, the concentration of the molybdenum in the liquid feed to the LPH reactor 150 is the same as specified above. The concentration of the nickel in the liquid feed to the LPH reactor 150 may be more than 0 wppm and no more than about 2 wt % in the liquid feed, suitably no more than about 0.5 weight % in the liquid feed, and typically no more than about 2000 wppm in the liquid feed. In some cases, the concentration of nickel may be no less than 500 wppm in the liquid feed, and preferably not less than 1000 wppm of the feed. By feed, the aggregate of all feed streams to the reactor is meant.

[0053] In preferred embodiments a stream containing catalyst may be recycled to the LPH reactor 150. Thus, the concentration of molybdenum in the LPH reactor 150 can be controlled at a steady state greater than the concentration of molybdenum in the liquid feed. The concentration of molybdenum in the reactor liquid is typically between 0.1 wt% and 10 wt%, preferably between 0.5 wt% and 7 wt% and more preferably between 2 wt% and 7 wt%, and even more preferably between 0.2 wt% and 3 wt%.

[0054] Conditions in the LPH reactor 150 generally include a temperature from about 315°C (600°F) to about 538°C (1000°F), or about 321°C (610°F) to about 482°C (900°F), or about 340°C (644°F) to about 470°C (878°F) or about 343°C (650°F) to about 377°C (710°F), a pressure from about 3.5 MPa (500 psig) to about 30 MPa (4351 psig), suitably 5.5 MPa (800 psig) to about 19.3 MPa (2800 psig), preferably 6.8 MPa (1000 psig) to about 13.8 MPa (2000 psig), or more preferably no more than about 10.3 MPa (1500 psig), and a reactor liquidresidence time from about 3 to about 10 hrs, or about 0.1 to about 8 hrs, preferably 2 to about 6 hrs, or 1 to about 5 hrs, or about greater than 3 hrs.

[0055] In another exemplary embodiment of the present disclosure, the LPH reactor 150 may be a continuous stirred tank reactor (CSTR). Operating conditions in the CSTR 150 may be as given above but may preferably include a temperature from about 300°C (572°F) to about 500°C (932°F), a pressure from about 6.8 MPa (1000 psig) to about 13.8 MPa (2000 psig), and a residence time of about 30 mins, to about 8 hours. From the LPH reactor 150, the upgraded biooil stream is taken in line 154.

[0056] In an aspect, the LPH reactor 150 may be selected from a bubble column reactor, a slurry reactor, and an ebullated bed reactor to facilitate contact and mixing of gases with liquid or slurry materials. Other types of reactors may be used to facilitate the contact and the mixing. The catalyst in the LPH reactor may be free flowing in the reactor without fixation in a bed.

[0057] In another aspect, the LPH reactor 150 may be a once-through reactor for processing the streams to produce the upgraded bio-oil stream.

[0058] Under hydrotreating conditions, the catalyst in the LPH reactor 150 may hydrodeoxygenate the bio-oil in the mixed stream in line 142. In an aspect, the catalyst in the LPH reactor 150 may hydrodeoxygenate carbonyl compounds more selectively than other oxygenates such as phenolics and alcohols. The LPH reactor 150 can be run at different severities resulting in different amounts of oxygen in the stabilized product.

[0059] The composition of the material inside the LPH reactor 150 such as the reaction mixture may be characterized by a band area ratio of oxygenates measured by ATR-IR spectroscopy. In an exemplary embodiment, the composition of the reaction mixture inside the LPH reactor 150 should comprise a ratio of oxygenates of one or more of a (C-O) / C ratio from about 0 to about 0.7 or preferably from about 0 to about 0.5, or more preferably from about 0 to about 0.4; a (C=O) / C ratio from about 0 to about 0.5 or preferably from about 0 to about 0.4 or more preferably from about 0 to about 0.3; an OH / C ratio from about 0 to 2.5, or preferably from about 0 to about 1.5, or more preferably from about 0 to about 1; and an O / C ratio from about 0 to 1.7; or preferably from about 0 to about 1 or more preferably from about 0 to about 0.6.

[0060] The upgraded bio-oil stream in line 154 is passed to a hot separator 155. In the hot separator 155, heavy oil is separated from light oil. A heavy oil stream is taken in line 158 fromthe bottoms of the hot separator 155. The heavy oil stream which contains catalyst is separated and taken in line 158 from the hot separator 155. The heavy oil stream in line 158 comprises a majority of the catalyst, for example all the catalyst exiting from the LPH reactor 150, may be taken in the hot bottoms line 158. Light oil is taken in a hot overhead stream in line 156 from the hot separator 155. Water is also separated in the hot separator 155 which is taken with the light oil in the hot overhead stream in line 156. The hot separator 155 may be run at a temperature of about 250°C to about 450°C and at a pressure of about the pressure of the reactor 150.

[0061] The hydrotreating conditions of the LPH reactor 150 for the liquid phase hydrotreating of the bio-oil stream are selectively chosen and the hydrotreating conditions of the LPH reactor 150 can be adjusted to allow for less oxygen conversion along with less hydrogen consumption.

[0062] The hot overhead stream comprising the light oil in line 156 may be cooled in a cooler 149 and charged to a cold separator 157. In the cold separator 157, gaseous components may be separated from the light oil. The gaseous components are separated and taken in line 161 from the cold separator 157. The cold overhead stream in line 161 may be purified to obtain a hydrogen stream which may be recycled to the LPH reactor 150. A bottoms light oil stream comprising the upgraded bio-oil stream and aqueous components is taken in line 162 from the cold separator 165. Water is separated and taken in line 159 from the boot of the cold separator 157. The cold separator 157 may be operated at a temperature of about 0 to about 75°C and at a pressure of about the same pressure as the LPH reactor 150.

[0063] In an embodiment, the light upgraded bio-oil stream in line 162 and the heavy oil stream in line 158 may be fractionated in a fractionation column to produce renewable naphtha.

[0064] The light upgraded bio-oil stream in line 162 and the heavy oil stream in line 158 may be passed to a stripping column 170. As shown, a suitable stripping media in line 177 is also passed to the stripping column 170. A stripping media which is an inert gas or vapor such as steam from a stripping media line 177 may be used to strip light gases from the light upgraded bio-oil stream and the heavy oil stream. An overhead stream in line 171 comprising the light gases is discharged from the overhead of the stripping column 170. The overhead stream in line 171 may be cooled and condensed in a cooler condenser 179 and passed to an overhead receiver 169 where the gases are separated from the liquid. An off-gas stream in line 172 comprising thelight gases may be discharged from the overhead receiver 169. An overhead liquid stream in line 173 may be discharged from the bottom of the overhead receiver 169. Water may be separated and collected in line 189 from the boot of the overhead receiver 169. A reflux stream in line 174 is taken from the total overhead liquid stream in line 173. The reflux stream in line 174 may be recycled to the stripping column 170. Remaining overhead liquid may be taken in a net overhead liquid line 175. A renewable naphtha stream may be recovered from the net overhead liquid stream in line 175.

[0065] In accordance with the present disclosure, the net overhead liquid stream in line 175 comprises light naphtha. The light naphtha may predominantly comprise cyclic compounds. The net overhead liquid stream in line 175 may comprise a biogenic light naphtha. The light naphtha stream may have a T10 boiling point of between about 20°C (68°F) and about 40°C (104°F) and a final boiling point of no more than about 93°C (200°F) to about 104°C (220°F).

[0066] A bottom stream may be discharged in line 176 from the bottom of the stripping column 170. The bottom stream in line 176 may be fed to a fractionation column 180. The fractionation column 180 provides an overhead gaseous stream of naphtha in an overhead line 181. The fractionation overhead stream may be passed through a cooler condenser 187 where it is cooled and condensed before feeding into the overhead receiver 163. A sour water stream may be collected from a boot of the overhead receiver 163 in line 168. A fractionator overhead liquid stream in line 165 may be discharged from the bottom of the overhead receiver 163. A reflux stream may be taken in line 167 from the fractionator overhead liquid stream in line 165. An overhead product stream may be taken in line 166 from the fractionator overhead liquid stream in line 165.

[0067] In accordance with the present disclosure, the overhead product stream in line 166 comprises medium naphtha. The medium naphtha may predominantly comprise cyclic compounds. The overhead product stream in line 166 may comprise a biogenic medium naphtha. The medium naphtha may have a T10 boiling point of approximately 85°C (185°F) and a final boiling point of about 149°C (300°F) to about 216°C (420°F).

[0068] The fractionation column 180 may be operated with a bottoms temperature of about 500°C (932°F) to about 750°C (1382°F) or about 500°C (932°F) to about 600°C (1112°F), and an overhead pressure of about 34 kPa (gauge) (5 psig) to about 173 kPa (gauge) (25 psig). Thetemperature in the overhead receiver 163 may range from about 38 °C (100 °F) to about 66 °C (150°F) and the pressure is essentially the same as in the overhead of the fractionation column 180.

[0069] A renewable kerosene stream in line 182 may be produced from a side of the fractionation column 180. The kerosene stream taken in the side line 182 may be stripped in a kerosene stripper column to drive off lower boiling materials which may be returned back to the fractionation column 180. A jet fuel product stream discharged be taken from the bottom of the kerosene stripper column. The jet fuel product stream meets jet fuel specifications per ASTM D86 and may be a green jet fuel stream taken from a bottom of the kerosene stripper column.

[0070] A bottom heavy stream in line 183 is discharged from the bottom of the fractionation column 180. The bottom stream in line 183 may comprise catalyst particles and may be directly recycled back to the reactor 150, or catalyst particles may be recovered or concentrated by other means and may be recycled back to the reactor 150, or catalyst particles may be recovered or concentrated by other means and may be recycled back to the reactor 150. A reboiling stream in line 184 may be taken from the bottom stream in line 183 which may be reboiled in a reboiler 185 and recycled back to the fractionation column 180. The remaining bottom stream may be taken in line 186. In an aspect, the bottom stream in line 186 may be separated to remove a heavy oil stream lean of catalyst. Separation may include filtration, centrifuge, vacuum flashing, wiped film evaporation or other means to remove catalyst from a heavy oil stream lean of catalyst.

[0071] In an embodiment, the bottom stream in line 186 may be passed to a catalyst separation vessel 136 for separating catalyst that may be present. In exemplary embodiment, the catalyst separation vessel 136 may be selected from a filtration vessel, a centrifuge, a vacuum distillation column, a wiped film evaporator, a gravity settler, or a combination thereof. In the catalyst separation vessel 136, the catalyst is separated to produce a heavy oil product stream. The heavy oil product stream is discharged in line 137 from the catalyst separation vessel 136. A recycle oil stream comprising catalyst in heavy oil is discharged in line 138 from the vessel 136. The recycle oil stream in line 138 may be recycled to the LPH reactor 150. The recycle oil stream in line 138 may be pumped by a pump 157 to the LPH reactor 150.

[0072] A wiped film evaporator (WFE) uses a hinged blade with minimal clearance from the internal surface to agitate the flowing catalyst containing stream to effect separation of catalyst from heavy oil. In the catalyst separation vessel 136 comprising a WFE, the bottom stream in line 186 enters tangentially above a heated internal tube and is distributed evenly over an inner circumference of the tube by the rotating blade perhaps at vacuum. Catalyst particles spiral down the wall while bow waves developed by rotor blades generate highly turbulent flow and optimum heat flux. The heavy oil evaporates rapidly and vapors can flow either co-currently or counter-currently against the catalyst particles. In a simple WFE design, heavy oil may be condensed in a condenser located outside but as close to the evaporator as possible.

[0073] Other evaporative techniques may be used to separate the catalyst from the heavy oil product stream in the catalyst separation vessel 136.

[0074] In accordance with an embodiment of the present disclosure, the net overhead liquid stream comprising light naphtha in line 175 and the overhead product stream comprising medium naphtha in line 166 may be hydrotreated to produce a hydrotreated naphtha stream. Hydro treating effectively removes the majority of residual oxygenates from the light naphtha and the medium naphtha.

[0075] In accordance with the present disclosure, the net overhead liquid stream comprising light naphtha in line 175 and the overhead product stream comprising medium naphtha in line 166 may be analyzed online or offline using one or more of the infrared (IR) spectroscopy and nuclear magnetic resonance (NMR) spectroscopy, The NMR spectroscopy determines the physical and chemical properties of atoms or molecules. Proton (JH) NMR is one of the most widely used NMR methods. Different nuclei can also be detected by NMR spectroscopy,1H (proton),13C (carbon 13),15N (nitrogen 15),19F (fluorine 19), among many more. H and13C are the most widely used and their procedures are as below:1H Liquid State Procedure

[0076] NMR spectra of the samples were collected by employing a Bruker Avance Spectrometer operating at a frequency of 500.1317 for 1H experiments. The samples were prepared by dissolving 2-3 drops of bio-oil in 0.6 mL of chloroform-d with a trace quantity of tetramethylsilane being added as an internal reference. Quantitative results were obtained using a 90° pulse with 10 ms length and 10 seconds of delay between acquisitions. The number of scanswas 128. Processing included baseline correction and the use of 1 Hz exponential line broadening before Fourier transformation. The spectra were further integrated by regions corresponding to the following lumped functional groups: 0.5- 1.5 ppm alkanes, 1.5-3 ppm aliphatics alpha to heteroatom or unsaturation, 3-4.4 ppm alcohols, methylene-dibenzene, 4.4-6 ppm olefins, methoxys, carbohydrates, 6-7.18 ppm (hetero) aromatics, furans, 7.18-8.5 ppm (hetero) aromatics, 8.5-10.1 ppm aldehydes.13C Liquid State Procedure

[0077] NMR spectra of the samples were collected by employing a Broker Avance Spectrometer operating at a frequency of 125.7715 for 13C experiments. The samples were prepared using a 50:50 (v / v) mixture of chloroform-d and bio-oil analyte. Additionally, a trace quantity of tetramethylsilane was added as an internal reference and chromium acetylacetonate was used as a relaxation agent. Quantitative results were obtained using an inverse-gated pulse sequence, and all 13C spectra were acquired by using 11.3 ps pulses and 10 seconds of delay between acquisitions. The number of scans was 2048. Processing included baseline correction and the use of 3 Hz exponential line broadening before Fourier transformation. The spectra were further integrated by regions corresponding to the following lumped functional groups: 0-27 ppm short aliphatics; 27-54 ppm long and branch aliphatics; 54-94 ppm alcohols, ethers, phenyl methoxy groups, carbohydrates; 94-167 ppm aromatics, olefins, heteroaromatics, furans; 167-186 ppm esters, carboxylic acids; 186-225 ppm ketones, aldehydes. From this integrated signal a mol% of carbon is calculated. The integrated signal in each region corresponds to moles of carbon atoms directly bound to the oxygen atoms in the particular functional group and does not count the carbon in the rest of the molecule.

[0078] 3 IP NMR is utilized to determine the total amount of aromatic vs aliphatic -OH groups (i.e. alcohol or phenol). This is done according to the laboratory analytical procedure in M. Olarte, DETERMINATION OF HYDROXYL GROUPS IN PYROLYSIS BIO-OILS USING 3 IP NMR, National Renewable Energy Laboratory (2016) at www.nfel.gov / publications. This method utilizes a phosphorylation by 2-chloro-4,4,5,5-tetramethyl-l,3,2-dioxaphospholane (TMDP) to derivatize -OH containing groups. Results are reported in mmol of OH per gram of sample.

[0079] The oxygen content of the net overhead liquid stream comprising light naphtha in line 175 may be characterized by a band area ratio of oxygenates measured by Attenuated TotalReflectance (ATR) infrared (IR) spectroscopy. ATR-IR is a sampling technique in which the sample is placed in intimate contact with a crystal having a high index of refraction. The IR light is brought in from the bottom and reflected from the surface of the crystal. Samples were placed as-is onto a diamond crystal for ATR IR spectrum collection (64 scans, 2 cm-1 resolution). The IR spectra may be collected on a Nicolet is 50 FTIR spectrometer or an equivalent researchgrade instrument, truncated and baseline corrected in GRAMS Al software, and deconvolved and plotted in OriginPro 2016.

[0080] For integration and deconvolution of the spectra, two approaches may be taken. Simple integration of spectral regions may be performed for different functional groups. The integration areas for various functional groups are measured. In accordance with the present disclosure, the following are roughly the integration areas for each functional group: about 3100-3695 cm'1for hydroxyl groups, about 2800-2995 cm'1for hydrocarbon groups, and about 1000-1315 cm'1regions for methoxy groups. For the C=O and C=C regions which span from about 1500 cm'1to about 1800 cm1, the spectra may be deconvolved by first baseline correcting the region, then fitting multiple peaks using the Origin Pro software. Spectra may not be normalized before deconvolution since there is no internal standard, thus, only area ratios may be used for sample comparison. The aromatic C=C band area is typically from the deconvolved bands in the region ranging from about 1500 cm1to about 1600 cm1, the alkene C=C band area in the region ranging from about 1600 cm'1to about 1700 cm1, and the C=O band area in the region ranging from about 1700 cm'1to about 1800 cm1. Depending on the complexity of the region, some spectra could be deconvolved into 6 bands or as many as 9 bands.

[0081] Total carbon “C” value may also be calculated. The total carbon “C” value is equal to the sum of the integrated regions of CHx stretching and C=C stretching so that C equals (CHx + C=C) integrated band areas. Similarly, the total oxygen “O” value is equal to the sum of the integrated regions of C=O and C-0 stretching so that O equals (C=O + C-O) integrated band areas. All other band areas identify the specific molecular vibrations that they represent.

[0082] Based on the band area values of these functional groups, a band area ratio value is also calculated for various functional groups. Band area ratio is a unitless parameter which remains the same for all measuring instruments. For instance, a band area ratio of C=0 / C-0 can be calculated and indicates the relative amount of C=O vs C-0 bonds in the sample.

[0083] Further, the net overhead liquid stream comprising light naphtha in line 175 may be analyzed to measure oxygen concentration through a carbon, hydrogen, nitrogen, oxygen (CHNO) elemental analysis as a proxy for oxygenate concentration.

[0084] Acid number is a suitable method for measuring carboxylic acid content. Briefly, acid number is obtained via typical potentiometric titration using a solution of tetra-n-butylammonium hydroxide and isopropanol as the titrant. A standard method of benzoic acid and N,N-dimethylformamide is run every 3 hours to ensure results. The sample is weighed and added to a beaker. The N,N-dimethylformamide solution is added to the beaker (internal standard) and the mixture is stirred under nitrogen for 5 mins before titration.

[0085] Further, the presence of cyclic hydrocarbons such as naphthenes and aromatics in the net overhead liquid stream comprising light naphtha in line 175 may be measured by comprehensive two-dimensional gas chromatography (GCxGC).

[0086] The light naphtha stream in line 175 comprises at least about 50 wt% cyclic compounds. The light naphtha stream in line 175 may be characterized by a research octane number (RON) of greater than about 70, preferably greater than about 72, and more preferably greater than about 74, and yet more preferably greater than about 80. The light naphtha stream in line 175 can serve multiple versatile applications. In fuel applications, the light naphtha stream can be blended into gasoline, allowing it to partially replace conventional petroleum-derived fuels. The light naphtha stream can be reformed into BTX molecules or high-octane gasoline or can be used as a feedstock for various other processes.

[0087] Various methods or tests may be employed to analyze the light naphtha stream in line 175 for measuring the concentration of various groups and the characteristics of the light naphtha stream. In an aspect, the light naphtha stream in line 175 may be analyzed using spectroscopy such as nuclear magnetic resonance (NMR) spectroscopy and attenuated total reflection-infrared (ATR-IR) spectroscopy. Other tests may include two-dimensional gas chromatography (GCxGC), PIONA VUV method (gas chromatography (GC) technique), ASTM UOP744 method, and ASTM UOP880 method. Further tests may include an acid number test and a carbon-hydrogen-nitrogen-oxygen (CHNO) elemental analysis for example ASTM D5291 CHN, and ASTM UOP649 Oxygen. Acid number test may include TAN (total acid number) and CAN (carboxylic acid number).

[0088] In an aspect, the light naphtha stream in line 175 comprises less than about 0.1 wt% oxygen as measured by ASTM UOP649. The light naphtha stream in line 175 may comprise at least about 50 wt% of the hydrocarbons with 5 to 7 carbon atoms being cyclic as measured by PIONA VUV method. Further, the light naphtha stream in line 175 may comprise a final boiling point of no more than about 105°C (220°F), preferably no more than about 94°C (200°F), and more preferably no more than about 85°C (185°F).

[0089] In an embodiment, the light naphtha stream in line 175 may comprise C4 to C7 paraffins having a greater proportion of C4 to C7 normal paraffins than C4 to C7 isoparaffins as measured by PIONA VUV method.

[0090] In an exemplary embodiment, the light naphtha stream in line 175 may exhibit hydrocarbons with 4 to 7 carbon atoms with a cyclopentane to cyclohexane weight ratio of about 3:2 to about 3:1 as measured by PIONA VUV method.

[0091] Acid number of the light naphtha stream in line 175 may be measured based on the method as per C. Dence, Determination of Carboxyl Groups, Methods in Lignin Chemistry, Springer Series in Wood Science. Heidelberg, 458-464 (1992). https: / / doi.org / 10.1007 / 978-3-642-74065-7. The details of the acid number test are as below:Materials:

[0092] 0.05N tetra-n-butylammonium hydroxide solution (TnBAH): Prepared by diluting 50.0 mL of LON TnBAH (Aldrich, SAP# 1014519, lOOmL) solution to 1.00 L in isopropanol. Components were mixed thoroughly before transferring the solution to a Dosimat bottle. The LON TnBAH solution was blanketed with nitrogen and stored in the refrigerator.

[0093] Benzoic Acid: p-Hydroxybenzoic Acid, was stored in a desiccator when not in use.

[0094] Hydrochloric Acid additive solution: 2 mL of concentrated HC1 was added to 100 mL of deionized water and mixed thoroughly. 4mL of this solution was added to ~140mL of dimethylformamide (DMF) for titration of samples.Standardization of the Titrant:

[0095] 0.15-0.20g of dried benzoic acid was added into a titration beaker and the weight was recorded to the nearest 0. Img. 120mL of DMF was added and titrate with the TnBAH solution. The standardization was done in duplicate. Normality was calculated to 3 significant figures as per the formula:g Benzoic acidN = - - - (mL titrant) (0.12212)

[0096] Standardization was repeated every 3 hours when using this procedure.Titration of Samples:

[0097] Prior to the first sample analysis, 0.05-0.08g of p-hydroxybenzoic acid was weighed into a titration beaker. 140mL of DMF and 4mL of the HC1 additive solution were added. The resultant solution was titrated through the 3rd inflection. This was the blank used to calculate the HC1 correction and can be used as a QC for the Phenolic Hydroxyl titrations.

[0098] 0.3-0.4g of lignin and 0.05-0.08g of p-hydroxybenzoic acid were weighed into a titration beaker. 140mL of DMF and 4mL of the HC1 additive solution were added. Beaker was blanketed with nitrogen and stirred for 5 minutes before titration. Titration was performed with 0.05N TnBAH to the 3rd inflection.Calculations:

[0099] The theoretical titer of the internal standard used was calculated in the blank or sample titration:gpHBAa mL) “ 0.13812 (N)HC1 interference was calculated from the blankc (mL) = [(measured volume to reach 2nd inflection of blank) - (measured 1st inflection)] - (a (mL, calculated above)), then[(y) - (x) - (c) - (a)]NmEq carboxyl / g sample = - w[(z) - (y) - (a)]NmEq phenolic hydroxyls / g sample = - wwhere,x = mL at first inflection point;y = mL at second inflection point;z = mL at third inflection point.[000100] The foregoing method may be used to measure acid number typically without use of the p-hydroxybenzoic acid internal standard for expedience. However, use of the internal standard is typically recommended[000101] In an aspect, the carboxylic acid number of the light naphtha stream in line 175 may be zero.[000102] The medium naphtha stream in line 166 may be analyzed using various methods or tests as earlier described for measuring the concentration of various groups and the characteristics of the medium naphtha stream. The medium naphtha stream in line 166 can serve multiple versatile applications. In fuel applications, the medium naphtha stream in line 166 can be blended into gasoline, allowing it to partially replace conventional petroleum-derived fuels. The medium naphtha stream in line 166 can be reformed into BTX molecules or high-octane gasoline or can be used as a feedstock for various processes including a reforming unit, and a naphtha to ethane and propane process.[000103] In an aspect, the medium naphtha stream in line 166 comprises less than about 0.1 wt% oxygen as measured by ASTM UOP649. The medium naphtha stream in line 166 may comprise at least about 60 wt% of the hydrocarbons with 6 to 10 carbon atoms being cyclic as measured by PIONA VUV method. Further, the medium naphtha stream in line 166 may comprise a final boiling point of no more than about 216°C (420°F), preferably no more than about 177°C (350°F), and more preferably no more than about 149°C (300°F)[000104] In an embodiment, the medium naphtha stream in line 166 may comprise C7 to C9 paraffins having a greater proportion of C7 to C9 isoparaffins than C7 to C9 normal paraffins as measured by PIONA VUV method.[000105] In an embodiment, the medium naphtha stream in line 166 may comprise cyclic hydrocarbons comprising naphthenes with 6 to 10 carbon atoms. In an exemplary embodiment, the medium naphtha stream in line 166 may comprise more than about 90 wt% of the C6 to CIO naphthenes being C7-C8 naphthenes as measured by PIONA VUV method.[000106] In an embodiment, the medium naphtha stream in line 166 may comprise a weight ratio of hydrocarbons with 4 to 8 carbon atoms to hydrocarbons with 9 and more carbon atoms of about 5:1 to about 15:1.[000107] The acid number of the medium naphtha stream in line 166 may be measured based on the method as earlier described. In an aspect, the carboxylic acid number of the medium naphtha stream in line 166 may be zero.[000108] In an embodiment, the net overhead liquid stream comprising light naphtha in line 175 and the overhead product stream comprising medium naphtha in line 166 may be combined to provide a mixed naphtha stream in line 212. The mixed naphtha stream may have a T10 boiling point of between about 20°C (68°F) and about 40°C (104°F) and a final boiling point of about 149°C (300°F) to about 216°C (420°F). The naphtha stream can be hydrotreated to deoxygenate to make it suitable for use as a feed or for naphtha reforming. The mixed naphtha stream in line 212 can be fed directly to a hydrotreating reactor or can be stored and or transported for hydrotreating elsewhere. In an aspect, the mixed naphtha stream in line 212 may be a renewable naphtha stream. A hydro treating hydrogen stream in line 214 may be combined with the mixed naphtha stream in line 212 to provide a hydrotreating charge stream in line 216. The hydrotreating charge stream in line 216 is charged to a hydrotreating reactor 220.[000109] In the hydrotreating reactor 220, the hydrotreating charge stream in line 216 is contacted with a hydrotreating catalyst in the presence of hydrogen at hydrotreating conditions to catalyze deoxygenation reactions including hydrodeoxygenation reactions, decarboxylation and decarbonylation reactions, to remove oxygenate functional groups from the hydrocarbon molecules in the hydrotreating charge stream which are converted to water and carbon oxides.[000110] The hydrotreating catalyst may be provided in one, two or more beds. In an exemplary embodiment, two hydrotreating catalyst beds 220a and 220b are shown in FIG. 1. However, the hydrotreating reactor 220 may include more than two catalyst beds or a single hydrotreating catalyst bed.[000111] The hydrotreating catalyst may comprise nickel, molybdenum, tungsten, nickel and molybdenum, nickel and tungsten, or cobalt and molybdenum dispersed on a high surface area support such as alumina. Such catalysts may be sulfided either prior to loading in the reactor or after loading in the reactor by exposure to a sulfiding feed or sulfiding gas. Other catalysts include one or more noble metals dispersed on a high surface area support. Non-limiting examples of noble metals include platinum and / or palladium dispersed on an alumina support such as gamma-alumina. Suitable hydrotreating catalysts include, but are not limited to BDO-200, BDO-300 or BDO-400 available from UOP LLC in Des Plaines, Illinois.[000112] The hydrotreating reaction temperature may range from between about 300°C (572°F) and about 427°C (800°F) and preferably between about 349°C (690°F) and about 400°C(752°F). Generally, hydrotreating conditions include a pressure of about 700 kPa (100 psig) to about 21 MPa (3000 psig) or about 2750 kPa (400 psig) to about 21 MPa (3000 psig) and a liquid hourly space velocity of about 0.5 hr1to about 2 hr1.[000113] In some embodiments an additional naphtha feedstock such as a straight run fossilfuel naphtha may be co-processed with the mixed naphtha stream in the hydro treating reactor 220. In the exemplary embodiment as shown in FIG. 1, a secondary naphtha feedstock in line 213 may be is combined with the mixed naphtha stream in line 212 and taken in the hydrotreating naphtha charge line 216. In exemplary embodiments, the bio-oil derived mixed naphtha stream in line 212 may be co-processed with the secondary naphtha feedstock at a level of at least about 1 wt% bio-oil derived naphtha, or at least about 3% or about 5% or about 10%.[000114] In an alternate embodiment, the net overhead liquid stream comprising light naphtha in line 175 and the overhead product stream comprising medium naphtha in line 166 may be hydrotreated in separate hydrotreating reactors or in separate hydrotreating catalyst beds. The hydrotreated effluent from the two hydrotreating reactors or hydrotreating catalyst beds may be combined.[000115] A hydrotreated naphtha stream is discharged from the bottom of the hydrotreating reactor 220 in line 222. The hydrotreated naphtha stream in line 222 may be characterized as a combined naphtha steam comprising both light naphtha and medium naphtha. Oxygenate concentration in the hydrotreated naphtha stream in line 222 is essentially nil. In an aspect, the combined naphtha steam in line 222 may comprise both biogenic light naphtha and biogenic medium naphtha.[000116] Various methods or tests may be employed to analyze the hydrotreated naphtha stream for the concentration of various groups and the characteristics. In an aspect, the hydrotreated naphtha may be analyzed using spectroscopy such as nuclear magnetic resonance (NMR) spectroscopy and attenuated total reflection-infrared (ATR-IR) spectroscopy. Other tests may include two-dimensional gas chromatography (GCxGC), PIONA VUV method (gas chromatography (GC) technique), ASTM UOP744 method, and ASTM UOP880 method.Further tests may include an acid number test and carbon-hydrogen-nitrogen-oxygen (CHNO) elemental analysis for example ASTM D5291 CHN, and ASTM UOP649 Oxygen. Acid number test may include TAN (total acid number) and CAN (carboxylic acid number).[000117] In an aspect, the hydrotreated naphtha stream in line 222 comprises less than about 0.1 wt% oxygen as measured by ASTM UOP649. The hydrotreated naphtha stream in line 222 may comprise more than about 50 wt% of the hydrocarbons with 5 to 10 carbon atoms being cyclic as measured by the PIONA VUV or U880 method. Further, the hydrotreated naphtha stream in line 222 may comprise a final boiling point of no more than about 216°C (420°F), preferably no more than about 177°C (350°F), and more preferably no more than about 149°C (300°F).[000118] The hydrotreated naphtha stream in line 222 may comprise C5 to C9 paraffins. In an embodiment, the hydrotreated naphtha stream in line 222 may comprise a greater proportion of C5 to C9 normal paraffins than C5 to C9 isoparaffins as measured by the PIONA VUV or U880 method.[000119] In accordance with the present disclosure, the hydrotreated naphtha stream in line 222 may predominantly comprise cyclic compounds. The hydrotreated naphtha stream in line 222 can serve multiple versatile applications. In fuel applications, the hydrotreated naphtha can be blended into gasoline, allowing it to partially replace conventional petroleum-derived fuels. The hydrotreated naphtha stream can be reformed into BTX molecules or high-octane gasoline in a naphtha reformer using a process such as CCR Platforming or can be used as a feedstock for other processes.[000120] In an embodiment, the naphthenes of hydrotreated naphtha stream in line 222 may comprise a greater concentration of cyclopentanes than cyclohexanes. The cyclopentanes produced herein may include a ring of five carbon atoms with one or more alkyl groups attached to the ring. So, the cyclopentanes may include hydrocarbons with more than five carbon atoms. Further, the cyclohexanes produced herein may include a ring of six carbon atoms with one or more alkyl groups attached to the ring. So, the cyclohexanes may include hydrocarbons with more than six carbon atoms. In an exemplary embodiment, the hydrotreated naphtha stream in line 222 may comprise a weight ratio of cyclopentanes to cyclohexanes of about 0.6:1 to about 4:1 or about 2:1 to about 3:1 in the hydrocarbons with 5 to 9 carbon atoms as measured by the U880 GC method. Further, for C6 hydrocarbons, the hydrotreated naphtha stream in line 222 may comprise a higher concentration of cyclohexanes than cyclopentanes.[000121] In an embodiment, the hydrotreated naphtha stream in line 222 may comprise less than about 9 wt% aromatics as measured by PION A VUV or U880 method.[000122] In an embodiment, the hydrotreated naphtha stream in line 222 may exhibit a weight ratio of naphthenes to paraffins of about 2:1 to about 3.5:1 as measured by PIONA VUV or U880 method particularly in the hydrocarbons with 6 to 9 carbon atoms. In another embodiment, the hydrotreated naphtha stream in line 222 may exhibit a weight ratio of naphthenes to isoparaffins of about 3:1 to about 4.5:1 as measured by PIONA VUV or U880 method. In an aspect, the hydrotreated naphtha stream in line 222 may exhibit a weight ratio of naphthenes to total paraffins of about 2:5to about 4:5 in hydrocarbons with 5 to 9 carbon atoms range.[000123] In an aspect, the hydrotreated naphtha stream in line 222 may comprise a weight ratio of hydrocarbons with 5 to 8 carbon atoms to hydrocarbons with 9 and more carbon atoms of about 10:1 to about 20:1 as measured by PIONA VUV method.[000124] In an embodiment, the hydrotreated naphtha stream in line 222 may be characterized by a carboxylic acid number of less than about 0.1 mg KOH / g, preferably zero.[000125] In another embodiment, the hydrotreated naphtha stream in line 222 may be characterized by a relative density of about 0.65 to about 0.9 g / ml.[000126] The hydro treating of the mixed naphtha stream in line 212 in the hydro treating reactor 220 may remove oxygen from the renewable naphtha stream in the mixed naphtha stream to produce oxygen-containing byproducts. The oxygen-containing byproducts may be taken in the hydrotreated naphtha stream in line 222. In an aspect, a predominance of oxygen removed from the renewable naphtha stream is converted to water in the hydrotreating reactor 220. The oxygen-containing byproducts may comprise carbon monoxide and carbon dioxide. In an embodiment, the oxygen-containing byproducts may comprise carbon monoxide and carbon dioxide in an amount of less than about 50 wt%.[000127] In accordance with the present disclosure, the hydrotreated naphtha stream in line 222 is an excellent reforming feed. The hydrotreated naphtha stream may be reformed in a reforming reactor by charging it to a reforming catalyst to produce a reformed naphtha. The hydrotreated naphtha stream in line 222 may be coprocessed with a petroleum-derived material such as petroleum-derived naphtha in the reforming reactor. In the reforming reactor, the metal function on the reforming catalyst dehydrogenates and / or aromatizes the feed, while the acid functionperforms isomerization and cyclization reactions. The reforming step produces a highly aromatic product that may be used in the gasoline blending pool or may be fed to an aromatics complex to produce petrochemicals such as xylenes.[000128] As shown in FIG. 1, the hydrotreated naphtha stream in line 222 is charged to a reforming reactor 230. In an aspect, a petroleum-derived material such as petroleum-derived naphtha or even a paraffinic renewable naphtha stream maybe charged to the reforming reactor 230 and co-processed with the hydrotreated naphtha stream in line 222. In an embodiment, a coprocess stream of petroleum-derived naphtha or paraffinic renewable naphtha in line 224 may be mixed with the hydrotreated naphtha stream in line 222 and charged therewith in a reforming charge stream in line 226 to the reforming reactor 230.[000129] In the reforming reactor 230 the reforming charge stream in line 226 is contacted with a reforming catalyst to effect conversion of the hydrotreated naphtha to a higher-octane reformate product. Effective reforming operating conditions of the reforming reactor 230 may include temperatures which are lower than in a typical reformer while still achieving high aromaticity or octane number. In an aspect, the reforming reactor 230 may be operated at an inlet temperature of no more than about 550°C (1022°F), suitably an inlet temperature of about 454°C (850°F) to about 538° C (1000°F) in terms of a weighted average inlet temperature (WAIT). WAIT is calculated as the sum of the products of (the weight fraction of catalyst in each reactor relative to the total catalyst weight in all the reactors) by (the inlet temperature to the respective reactor). A liquid hourly space velocity in the range of from about 1.5 to about 15.0 hr1and preferably in the range of from about 1.5 to about 5 hr1may be used. In an embodiment, the reforming reactor 230 may be operated at a liquid hourly space velocity of greater than about 1.5 hr-1. A reforming hydrogen stream in line 224 may be fed to the reforming reactor 230. The quantity of reforming hydrogen may be present in amounts of from about 0.5 to about 20 moles of hydrogen per mole of hydrotreated naphtha, and preferably from about 4 to about 12 moles of hydrogen per mole of hydrotreated naphtha. The reforming reactor 230 may utilize any suitable type of catalyst regeneration process such as a continuous catalytic regeneration (CCR) or a semi-regeneration (SR). The reforming zone reactor effluent, or reformate, is generally passed through a separation zone where it can be fractionated to remove lighter weight components from heavier weight liquid components of the reformate and where the recycle gas, which isreused in the reforming zone can be easily separated. Since normal reforming operations produce excess amounts of gaseous hydrogen, a certain amount of the recycled gas is generally removed from the reforming system to maintain a given operating pressure. The pressure in the reforming reactor 230 may range from about 68 kPa (gauge) (10 psig) to about 10342 kPa (gauge) (1,500 psig).[000130] The operational parameters, including temperature, pressure, and flow rates of the feed for the reforming reactor 230 may be configured based on an existing kinetic model, which guided optimal conditions for the reforming of the hydrotreated naphtha. Under optimal conditions, and because the hydrotreated naphtha comprises a high concentration of cyclic hydrocarbons, the reformed naphtha product could be produced relatively easily, particularly at a lower temperature. The highly cyclic reforming feed enables operating the reforming reactor 230 at a lower temperature such as a WAIT of no more than about 550°C (1022°F), suitably a WAIT of about 454°C (850°F) to about 538° C (1000T).[000131] In an embodiment, the reforming reactor 230 may be a semi-regenerative-type reforming reactor. In a semi-regenerative reforming process, the catalyst is employed for reforming over an extended period of time. When the catalyst has become deactivated, the reforming operation is stopped and the total amount of catalyst in the reforming unit is regenerated in situ. The reforming charge stream in line 226 and a reforming hydrogen stream in line 224 may be charged to the semi-regenerative reforming reactor 230. The semi-regenerative reforming reactor 230 may be operated at a WAIT of no more than about 550°C (1022°F). suitably of about 454°C (850°F) to about 538° C (1000°F), pressure of about 344 kPa (gauge) (50 psig) to about 3103 kPa (450 psig). and a WHSV of greater than about 1.5 hr-1, or from about 2 hr-1to about 10 hr-1. In an aspect, the semi-regenerative reforming reactor 230 may comprise more than one reactor or stages comprising the reforming catalyst so that a lead reactor may be run to provide a reformate stream and hydrogen-containing gas while the catalyst in the other reactors is being regenerated. Fired heaters may be installed between the reactors to reheat the process stream up to the correct temperature for the next stage. Effluent from the last reactor may cooled by exchanging heat with the hydrotreated naphtha stream in line 222 for maximum heat recovery. Gases may be separated from the effluent of the last reactor to provide a hydrogencontaining gas. The hydrogen-containing gas produced during the regeneration operation can berecycled in line 224. Liquid and gas products may be separated from the effluent from the last reactor. The separated gas may comprise hydrogen which can be compressed and recycled to the reactor in line 224. The liquid stream comprises high-octane reformate which may be taken as the reformed naphtha stream in line 232 from the semi-regenerative reforming reactor 230.[000132] In another embodiment, the reforming reactor 230 may be a continuous catalytic regeneration (CCR) reforming reactor. In CCR process, continuous catalyst regeneration is used where catalyst is continuously removed from the reactor, regenerated in a controlled environment, and then transferred back to the reactor. With continuous regeneration, coke laydown is not excessive because the coke is continuously burned off and the catalyst is reconditioned to its original performance. The product stream of the CCR reactor 230 is a premium-quality gasoline blending component because of the high-octane value of the aromatics. Alternatively, the aromatics-rich product stream can be fed to a petrochemical complex where valuable aromatic products such as benzene, toluene, and xylene (BTX) can be recovered.[000133] The reforming charge stream in line 226 and a reforming hydrogen stream in line 224 may be charged to the CCR reactor 230. In an aspect, the catalytic reforming reactor 230 may be operated at an WAIT of no more than about 550°C (1022°F), suitably of about 454°C (850°F) to about 538°C (1000T), a liquid hourly space velocity in the range of from about 1.5 to about 15.0 hr1and preferably in the range of from about 1.5 to about 5 hr1. In an embodiment, the catalytic reforming reactor 230 may be operated at a liquid hourly space velocity of greater than about 1.5 hr-1. The CCR reactor 230 may comprise more than one reactor or stages.[000134] The CCR reactor 230 includes a regenerator where coke on the catalyst is burned off and the catalyst may go through a reconditioning step. A regenerated catalyst is sent back to the first reactor.[000135] Typical reactions in the reforming reactor 230 may include dehydrogenation, isomerization and hydrocracking. The dehydrogenation reactions typically will be the dehydroisomerization of alkylcyclopentanes to aromatics, the dehydrogenation of paraffins to olefins, the dehydrogenation of cyclohexanes to aromatics and the dehydrocyclization of acyclic paraffins and acyclic olefins to aromatics. The isomerization reactions include isomerization of n-paraffins to isoparaffins, the hydroisomerization of olefins to isoparaffins, and theisomerization of substituted aromatics. The hydrocracking reactions include the hydrocracking of paraffins. The aromatization of the n-paraffins to aromatics is generally considered to be highly desirable because of the high-octane rating of the resulting aromatic product. In this application, the hydrogen generated by the reactions is also a highly desired product, for it is recycled to at least the hydrotreating reactor 220 or the reforming reactor in line 224 or both. The liquid stream comprises high-octane reformate which may be taken as the reformed naphtha stream in line 232 from the CCR reactor 230.[000136] The catalysts which can be used in the reforming reactor 230 may include refractory inorganic oxide carriers containing one or more reactive metallic components thereon. Inorganic refractory oxides which can be used as carriers for reforming catalysts include alumina, the crystalline aluminosilicates such as the faujasites or mordenite, or combinations of alumina and the crystalline aluminosilicates. Metallic components which are generally recognized in the art as being favorable catalytic components for reforming operations generally include Group VIII and IV metals. Rhenium, tin and lead have also been shown to have catalytic properties when used with platinum. Reforming catalysts may also contain combined halogen as one of the catalytic components. The halogens which can be used include fluorine, chlorine, bromine, iodine or mixtures thereof[000137] In an aspect, the hydrogen produced from the catalytic reforming reactor 230 may be characterized as green hydrogen.[000138] In accordance with the present disclosure, the reformed naphtha stream in line 232 comprises one or both of greater than about 50 wt% aromatics and exhibiting a Research Octane Number of greater than about 80 or greater than about 95. The reformed naphtha stream in line 232 may be used as material in the gasoline blending pool and / or in an aromatics complex to produce chemicals such as para-xylene.[000139] In an embodiment, the reformed naphtha stream in line 232 may comprise greater than about 85 wt% hydrocarbons comprising 5 to 9 carbon atoms. Of the hydrocarbons comprising 5 to 9 carbon atoms, 60 wt% may be aromatics.[000140] In an aspect, the reformed naphtha stream in line 232 may be characterized by a Research Octane Number of about 80 to about 104, or about 95 to about 104.[000141] We have found the reforming process is capable of producing naphtha with RON values greater than about 95 while maintaining exceptionally high C5+ yields, in some cases greater than about 90 wt%. Such performance contrasts with conventional catalytic reforming of petroleum-derived naphtha, in which increasing octane number typically corresponds to a substantial reduction in C5+ liquid yield due to enhanced cracking severity.[000142] The disclosed process can achieve high aromatics contents, for example from about 59 wt% to about 67 wt%, while still retaining a large fraction of the C5+ product. This combination of high aromatics production, elevated RON, and high C5+ yield is unexpected in traditional petroleum reforming systems, where increased aromatization generally correlates with reduced liquid yield. Without being limited by theory, it is believed that the cyclic-rich, biogenic nature of the renewable naphtha feed enables more efficient aromatization with reduced cracking losses, providing improved yield-octane performance relative to conventional reforming processes.[000143] In conventional catalytic reforming, increasing severity to produce higher aromatics and higher RON typically results in substantial loss of C5+ liquid yield due to cracking and dealkylation reactions. By contrast, the reforming process of the present disclosure is able to simultaneously achieve high aromatics content, high RON, and high C5+ liquid yield. It is believed that the cyclic -rich and biogenic nature of the renewable naphtha feed, combined with the selected reforming conditions, enables efficient dehydrogenation and cyclization pathways while minimizing hydrocracking. As a result, reformed naphtha compositions produced according to the present disclosure can exhibit aromatics contents of about 59 to about 67 wt%. RONs greater than about 95, and C5+ liquid yields greater than about 85 wt%, an unexpected combination of properties relative to conventional petroleum reforming systems.[000144] In accordance with the present disclosure, the biogenic origin of the carbon in the renewable naphtha, such as, the mixed naphtha stream in line 212, and in the resulting reformed naphtha stream in line 232 may be confirmed, if desired, using radiocarbon-based analytical methods. For example, the biogenic carbon content of a naphtha-range product may be determined by ASTM D6866 or other equivalent radiocarbon analysis techniques that distinguish contemporary biological carbon from fossil-derived carbon. Such methods provide a quantitativemeasure of modem carbon and may be used to characterize biogenic naphtha compositions produced according to the present disclosure.[000145] Because the renewable naphtha originates from biomass-derived intermediates such as bio-oil. the reformed naphtha produced according to the present disclosure retains a measurable level of modem carbon characteristic of biogenic materials. Measurement of the biogenic carbon fraction provides an analytical means to distinguish the disclosed biogenic naphtha compositions from petroleum-derived reformates, which exhibit negligible radiocarbon levels. In an exemplary embodiment, the renewable naphtha stream may comprise a biogenic carbon content of greater than about 0.1 percent modern carbon as determined by a radiocarbon-based analytical method.[000146] In accordance with the present disclosure, the renewable naphtha stream may be processed alone or may be blended or co-processed with one or more petroleum-derived naphtha streams prior to hydrotreating or reforming. Any mixture of renewable and petroleum naphtha may be introduced into the reforming reactor, and the reformate produced therefrom will contain a corresponding mixture of biogenic and fossil-derived carbon. In an exemplary embodiment, the renewable naphtha stream in line 212 may be combined or coprocessed with a petroleum-derived stream in line 213 and the mixed renewable naphtha stream in the hydrotreating charge line 216 may be hydrotreated in the hydrotreating reactor 222 to produce the hydrotreated naphtha stream in line 222. In an aspect, the mixed renewable naphtha stream in the hydrotreating charge line 216 may comprise at least about 0.1 wt% of the renewable naphtha stream. The hydrotreated naphtha stream in line 222 may be combined or coprocessed with a petroleum-derived stream in line 224 and the reformer charge stream in line 226 reformed in the reforming reactor 230 as earlier described to produce the reformed naphtha stream. In another aspect, the reformed naphtha stream in line 232 may comprise at least about 0.1 wt% of the renewable naphtha stream.[000147] Because the renewable naphtha contains carbon originating from biomass, any reformate produced from a blend of renewable and petroleum naphtha will retain a measurable biogenic carbon fraction. Even when the renewable naphtha constitutes a minority of the total feed, the resulting reformate maintains a non-zero level of modem biological carbon attributable to the renewable component.[000148] In some embodiments, the renewable naphtha or its precursor streams may be blended or co-processed with petroleum-derived streams prior to hydrotreating, hydrodeoxygenation, stabilization, or other upgrading steps. Any such co-processing results in upgraded naphtha streams that retain a measurable, non-zero biogenic carbon content.EXAMPLES[000149] A 2L stirred tank reactor pilot plant was operated under several different testing regimes to continuously upgrade bio-oil. Bio-oil used in these tests was fast thermal pyrolysis oil from produced from softwood. In a feed tank, the bio-oil and a molybdenum compound like Mo octoate were blended together and fed to the reactor. A stream of sulfiding material was added either to the feed tank or co-fed to the reactor. A hydrogen gas stream was added into the bio-oil feed stream upstream of the reactor. The reactor operated similarly to a liquid phasehydro treating (LPH) reactor, equivalent to 150 in the FIG. 1. Conditions for the LPH reactor were approximately 700-2500 psig outlet pressure, a calculated liquid residence time of 3-10 hours, 10.000-20,000 standard cubic feet of hydrogen flow per barrel of feed and 680-760°F operating temperature. After reaction, the product stream, equivalent to stream 154 in FIG. 1, went through hot separators, cold separators, and an oil-water separator to finally provide a light oil product stream, a heavy oil product stream, and an aqueous stream. The heavy oil product stream was recycled back into the reactor to provide a source of recycled, activated catalyst and deoxygenated oil.[000150] A light oil product stream was collected following separations in a hot and cold separator. The light oil product stream had relative density of 0.88 g / cm3, oxygen content of 8.56% (by ASTM UOP649), nitrogen content of 2643 wppm by ASTM D4629, total carboxylic acid number 82.6 mg KOH / g, and a phenolic acid number of 92.7 mg KOH / g. The light oil stream was contacted with a nickel-molybdenum based hydrodeoxygenation / hydrotreating catalyst BDO-400, available from Honeywell UOP in Des Plaines, IL. The second stage hydro treating was done in a fixed bed hydro treating reactor in the presence of hydrogen for >500 hours. Conditions for hydrotreating were 1800 psig outlet pressure, 1.0 hr1liquid hour space velocity, 10,000 standard cubic feet of hydrogen flow per barrel of feed and 690-700°F operating temperature. The hydrotreated product, comprising the combined naphtha, was fractionated intoseveral fractions, including a fraction corresponding to light naphtha and a fraction corresponding to medium naphtha. The operating conditions of the LPH reactor 150 and the hydrotreating reactor 220 were as below in Table 1:Table 1[000151] Three different full range naphtha compositions were generated, referred to here as Compositions A, B, and C, by compositing samples over three different sets of conditions in reactors 150 and 220. Each composition was fractionated into light (nominally 86-185°F) and medium (nominally 185-300°F) naphtha. For Composition A, the light naphtha, the medium naphtha, and the combined naphtha were analyzed by ASTM UOP880 method in Tables 2, 3, and 4, respectively. For Compositions B and C, the medium naphtha was analyzed in Tables 6 and 7, respectively. Additionally, the hydrotreated light and medium naphtha properties of Composition A are displayed in Table 5.Table 2: Light Naphtha (86 - 185°F), composition ATable 3: Medium Naphtha (185 - 300°F), Composition ATable 4: Combined Hydrotreated Naphtha, Composition A* P = paraffins; I = Isoparaffins; O = Olefins; Cy5 = Cyclopentanes; Cy6 = Cyclohexanes; N = Naphthenes; and A = AromaticsTable 5. Properties of Light and Medium Naphtha, Composition A* n.d. = not detectedTable 6, Medium Naphtha (185 - 300°F), Composition BTable 7, Medium Naphtha (185 - 300°F), Composition C[000152] As evident from Tables 2-7, the hydrotreated naphtha had high cyclics content and very low oxygen content making it an excellent reforming feed.[000153] The hydrotreated naphtha may be reformed in a reforming reactor. For this, we simulated reforming the combined hydrotreated naphtha with Composition A both in a continuous catalytic regeneration (CCR) reactor, , or a semi-regeneration (SR) reactor using catalysts commercially available from Honeywell UOP. The CCR reactor simulated was a four-reactor system. The reforming conditions for the catalytic reforming reactor were 2.0 hr1LHSV, 3.0 H2:HC, and 50 psig. The naphtha may be reformed in a CCR reactor at different temperatures, with higher temperatures resulting in different RON (research octane number), P7 conversion (C7 paraffin conversion), C5+ yield and aromatics yield. Four examples are given below for performance of a CCR reactor. The SR reactor simulated was a three-reactor system. For the SR reactor, the reforming conditions simulated were 1.5 hr1LHSV, 5.0 H2:HC, and 200 psig. All the reforming reactors were simulated at a WAIT of below 1000°F, indicating low severity operation, and yet allowing high octane and aromatics yields to be obtained. The reformed naphtha streams from the CCR reforming reactor and the SR reforming reactor are given below in Table 8:Table 8. Properties of the high-octane reformate from Composition A[000154] As evident from the results in Table 8, the reformed naphtha can achieve high RON or aromaticity at relatively low inlet temperature. This is also notable about the octane number lift and the increase in aromatics content relative to the numbers in Tables 2 and 3. The reformed naphtha can be used as a high-octane gasoline fuel or blendstock. Some of the CCR data presented in Table 8 can also be viewed in FIG. 2 and FIG. 3.[000155] FIG. 2 illustrates the relationship between C5+ liquid yield and Research Octane Number Calculated (RONC) for reformed naphtha products generated from renewable naphthafeeds according to the Example in the present disclosure. As shown, the reforming process is capable of producing naphtha with RON values greater than about 95 while maintaining exceptionally high C5+ yields, in some cases greater than about 90 wt%.[000156] FIG. 3 presents the relationship between C5+ liquid yield and aromatics content for the same reformate products. These data demonstrate that the disclosed process can achieve high aromatics contents, for example from about 59 wt% to about 67 wt%, while still retaining a large fraction of the C5+ product.SPECIFIC EMBODIMENTS[000157] While the following is described in conjunction with specific embodiments, it will be understood that this description is intended to illustrate and not limit the scope of the preceding description and the appended claims.[000158] A first embodiment of the disclosure is a process of reforming a renewable naphtha, comprising reforming a renewable naphtha stream in the presence of a reforming catalyst in a reforming reactor at reforming conditions comprising an inlet temperature of no more than about 550°C to produce a reformed naphtha stream comprising greater than about 50 wt% aromatics. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, further comprising hydrotreating the renewable naphtha stream with a hydrotreating hydrogen stream in the presence of a hydrotreating catalyst in a hydrotreating reactor to produce a hydrotreated naphtha stream; and reforming the hydrotreated naphtha stream to produce the reformed naphtha stream. An embodiment of the disclosure is one. any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrotreating step removes oxygen from the renewable naphtha stream to produce oxygen-containing byproducts, and wherein a predominance of oxygen removed from the renewable naphtha stream is converted to water in the hydrotreating step. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein theoxygen-containing byproducts comprises carbon monoxide and carbon dioxide in an amount of less than about 50 wt%. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha stream comprises more than about 50 wt% of the hydrocarbons with 5 to 10 carbon atoms being cyclic. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha stream comprises at least about 50 wt% of the hydrocarbons with 5 to 7 carbon atoms being cyclic. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha stream comprises at least about 60 wt% of the hydrocarbons with 6 to 10 carbon atoms being cyclic. An embodiment of the disclosure is one, any or all of priorembodiments in this paragraph up through the first embodiment in this paragraph, wherein the cyclic hydrocarbons in the renewable naphtha stream comprise a greater concentration of cyclopentanes than cyclohexanes. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha stream comprises a weight ratio of cyclopentanes to cyclohexanes of about 0.61 to about 41 in the hydrocarbons with 5 to 9 carbon atoms. An embodiment of the disclosure is one. any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha stream comprises a biogenic carbon content of greater than about 0.1 percent modern carbon as determined by a radiocarbon-based analytical method. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising reacting a bio-oil stream with hydrogen in the presence of a catalyst in a liquid phase reactor to produce an upgraded bio-oil stream; fractionating the upgraded bio-oil stream to produce the renewable naphtha stream. The process in claim 1 further comprising mixing the renewable naphtha stream with a petroleum-derived stream to provide a mixed renewable naphtha stream; and reforming the mixed renewable naphtha stream to produce the reformed naphtha stream. The process in claim 10 further comprising hydrotreating the mixed renewable naphtha stream with a hydrotreating hydrogen stream in the presence of a hydrotreating catalyst in a hydrotreating reactor to produce a hydrotreated naphtha stream before the reforming step.[000159] A second embodiment of the disclosure is a process of reforming a renewable naphtha comprising reforming a renewable naphtha stream in the presence of a reforming catalyst in a reforming reactor at reforming conditions comprising a WAIT of no more than about 550°C (1022°F) to produce a reformed naphtha stream having one or both of (i) greater than about 50 wt% aromatics, and (ii) a Research Octane Number of greater than about 95. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the renewable naphtha stream comprises more than about 50 wt% of the hydrocarbons with 5 to 10 carbon atoms being cyclic. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the renewable naphtha stream comprises a weight ratio of cyclopentanes to cyclohexanes of about 0.61 to about 41.[000160] A third embodiment of the disclosure is a composition provided from upgrading a biomass-derived feedstock, the biogenic naphtha composition having greater than about 0.1 percent modern carbon and a Research Octane Number of greater than about 94. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph comprising greater than about 85 wt% hydrocarbons having 5 to 9 carbon atoms. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the reformed naphtha is produced with a C5+ liquid yield greater than about 84 wt%. An embodiment of the disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the biogenic naphtha comprises greater than about 50 wt% aromatics.[000161] Without further elaboration, it is believed that using the preceding description that one skilled in the art can utilize the present disclosure to its fullest extent and easily ascertain the essential characteristics of this disclosure, without departing from the spirit and scope thereof, to make various changes and modifications of the disclosure and to adapt it to various usages and conditions. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limiting the remainder of the disclosure in any way whatsoever, and that it is intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.[000162] In the foregoing, all temperatures are set forth in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated.

Claims

CLAIMS1. A process of reforming a renewable naphtha, comprising reforming a renewable naphtha stream in the presence of a reforming catalyst in a reforming reactor at reforming conditions comprising an inlet temperature of no more than about 550°C to produce a reformed naphtha stream comprising greater than about 50 wt% aromatics.

2. The process of claim 1, further comprising:hydrotreating said renewable naphtha stream with a hydrotreating hydrogen stream in the presence of a hydrotreating catalyst in a hydrotreating reactor to produce a hydrotreated naphtha stream; andreforming said hydrotreated naphtha stream to produce said reformed naphtha stream.

3. The process of claim 2, wherein said hydrotreating step removes oxygen from said renewable naphtha stream to produce oxygen-containing byproducts, and wherein a predominance of oxygen removed from said renewable naphtha stream is converted to water in said hydrotreating step.

4. The process of claim 3, wherein said oxygen-containing byproducts comprises carbon monoxide and carbon dioxide in an amount of less than about 50 wt%.

5. The process of claim 1, wherein said renewable naphtha stream comprises more than about 50 wt% of the hydrocarbons with 5 to 10 carbon atoms being cyclic.

6. The process of claim 1, wherein said renewable naphtha stream comprises at least about 50 wt% of the hydrocarbons with 5 to 7 carbon atoms being cyclic.

7. The process of claim 1, wherein said renewable naphtha stream comprises at least about 60 wt% of the hydrocarbons with 6 to 10 carbon atoms being cyclic.

8. The process of claim 5, wherein said renewable naphtha stream comprises a weight ratio of cyclopentanes to cyclohexanes of about 0.6:1 to about 4:1 in the hydrocarbons with 5 to 9 carbon atoms.

9. A process of reforming a renewable naphtha comprising reforming a renewable naphtha stream in the presence of a reforming catalyst in a reforming reactor at reforming conditions comprising a WAIT of no more than about 550°C (1022°F) toproduce a reformed naphtha stream having one or both of: (i) greater than about 50 wt% aromatics, and (ii) a Research Octane Number of greater than about 95.

10. A biogenic naphtha composition provided from upgrading a biomass-derived feedstock, said biogenic naphtha composition having greater than about 0.1 percent modern carbon and a Research Octane Number of greater than about 94.

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