RENEWABLE NAPHTHA COMPOSITION

Description

FIELD

The field is related to a naphtha composition. Particularly, the field relates to a naphtha composition produced from bio-oil.

BACKGROUND

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 is well related to the reaction temperature and vapor residence time. Lower temperature, for example, around 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 or char coal, with typically 35 wt % gas, 30 wt % liquid, and 35 wt % char. Very high temperature of above 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 30 wt % gas, 50 wt % liquid, and 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 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 75 wt %.

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 around 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.

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.

To meet sustainability goals and government-required 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 currently contain up to 10% ethanol by volume (E10), 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 corn, the carbon intensity reduction of ethanol is lower than that of other fuels, such as ones derived from biomass. Additionally, the use of ethanol in fuels competes with human consumption of corn, whereas biomass is not for human consumption. Nevertheless, there exists an addressable market with significant demand for renewable naphtha, including both oxygenated naphtha and deoxygenated naphtha

Therefore, there is a need for improved processes for producing renewable naphtha.

SUMMARY

A renewable naphtha composition is disclosed. The renewable naphtha composition comprises about 0.1 wt % to about 15 wt % oxygen, and C4 to about C8 hydrocarbons comprising more than about 50 wt % cyclic hydrocarbons in the renewable naphtha composition. The renewable naphtha composition has a final boiling point of no more than about 420° F. The renewable naphtha composition can be used as a fuel stream or a blend stock for blending with a fuel stream. Further, the renewable naphtha composition may be deoxygenated to produce a deoxygenated naphtha. The renewable naphtha composition of the present disclosure can be used as a suitable gasoline pool blending material either as an oxygenated naphtha or deoxygenated naphtha. The renewable naphtha composition of the present disclosure is rich in cyclic hydrocarbons and has an octane number which is good for a blend stock.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGURE illustrates a schematic diagram of a process of producing a renewable naphtha composition in accordance with an embodiment of the present disclosure.

DEFINITIONS

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.

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

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

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.

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.

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.

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 D1160 of approximately 370° C. (698° F.) and a T90 boiling point temperature using ASTM D1160 of approximately 500° C. (932° F.).

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.

As used herein, the term “bioderived” or “biogenic” material means a material that comes from or made of, but not limited to, plants, animals, microorganisms, algae, or biopolymers.

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

DETAILED DESCRIPTION

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. The upgraded bio-oil 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.

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.

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, 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.

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.

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, corn, 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 products resulting 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.

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.

Referring to the FIGURE, a process 100 of producing renewable naphtha 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 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.

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.

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 about less than 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 start-up. 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.

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 is charged 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.

Liquid phase hydrotreating (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.

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.

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 or molybdenum 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, di-tert-butyl (poly)sulfide (TBPS), 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 U.S. Pat. No. 5,474,977.

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.

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 synthesis temperature 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).

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, 1° 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.

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 SiO₂/Si wafers, graphenes/graphites, or powdered or pelletized substrates commonly used as catalyst supports such as SiO₂, Al₂O₃, or TiO₂. 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, which may 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).

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.

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 a ground 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.

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

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.

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.

An aqueous molybdenum may be derived from reacting MoO₃ 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.

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.

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.

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 %.

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.), 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 liquid residence time from 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.

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 bio-oil stream is taken in line 154.

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 contact and mixing.

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

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.

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.

The upgraded bio-oil stream in line 154 is passed to a hot separator 160. In the hot separator 160, heavy oil is separated from light oil. A hot bottoms stream is taken in line 156 from the bottoms of the hot separator 160. The hot bottoms stream which contains catalyst is separated and taken in line 156 from the hot separator 160. The hot bottoms stream in line 156 comprises a majority of the catalyst, for example all the catalyst exiting from the LPH reactor 150, may be taken in the hot bottoms stream in line 156. In an aspect, the hot bottoms stream in line 156 may be characterized as a heavy oil stream comprising catalyst. Light oil is taken in a hot overhead stream in line 155 from the hot separator 160. Water is also separated in the hot separator 160 which is taken with the light oil in the hot overhead stream in line 155. The hot separator 160 may be run at a temperature of about 250° C. to about 400° C. and at a pressure of about the pressure of the reactor 150.

The hot bottoms stream in line 156 may be passed to a recycle tank 177. A recycle oil stream comprising the catalyst is taken in line 158 from the bottom of the recycle tank 177. A heavy oil stream may be taken from the recycle tank 177. A predominance of the catalyst may be in the recycle oil stream in line 158. The recycle oil stream in line 158 may be recycled to the reactor 150 perhaps through a pump 157.

The heavy oil stream in line 179 may be taken in such a way to avoid taking the bulk of the catalyst in this stream. In an aspect, the heavy oil stream in line 179 may be separated to remove a heavy oil stream lean of catalyst. Separation may include filtration, centrifuge, vacuum flashing, or wiped film evaporation to remove catalyst from a marine fuel oil stream lean of catalyst.

In an embodiment, the heavy oil stream in line 179 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 which may include the marine fuel oil. The heavy oil product stream is taken in line 137 from the catalyst separation vessel 136. A concentrated catalyst stream comprising catalyst in heavy oil is taken in line 138 from the vessel 136. The recycle oil stream in line 158 may be combined with the concentrated catalyst stream in line 138 to provide a combined recycle oil stream in line 139 which is recycled to the LPH reactor 150. In an exemplary embodiment, the heavy oil product stream in line 137 comprises marine fuel oil. In other embodiments, the heavy oil stream in line 179 is separated to remove a heavy oil product stream which may comprise a similar amount of catalyst as the recycle oil stream in line 139 and the catalyst is separated from the heavy oil product stream in one or more downstream processing steps.

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 heavy oil stream in line 179 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.

Other evaporative techniques may be used to separate the catalyst from the marine fuel oil in the catalyst separation vessel 136.

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.

The hot overhead stream comprising the light oil in line 155 may be cooled and charged to a cold separator 165. In the cold separator 165, gaseous components may be separated from the light oil. The gaseous components are separated and taken in line 164 from the cold separator 165. The cold overhead stream in line 164 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 169 from the cold separator 165. The bottoms light oil stream in line 169 comprises water that should be separated from the upgraded bio-oil stream. The cold separator 165 may be operated at a temperature of about 0 to about 75° C. and at a pressure of about the pressure of the LPH reactor 150.

In an embodiment, the bottoms light oil stream in line 169 is passed to an aqueous separator 147 for separating water from the upgraded bio-oil. Water is separated and taken in an aqueous bottoms line 148 from the aqueous separator 147. A light upgraded bio-oil stream is taken in line 159 from the aqueous separator 147 lean in water concentration. The aqueous separator 147 may be operated at a temperature of about 0 to about 75° C. and at a pressure of about 0 MPa (gauge) (0 psig) to about 1 Mpa (gauge) (150 psig).

In an embodiment, the light upgraded bio-oil stream in line 159 may be fractionated in a fractionation column 170 to separate the light upgraded bio-oil stream into one or more hydrocarbon streams. The fractionation column 170 may be operated at vacuum pressure. In an embodiment, fractionation column 170 may be operated at an overhead pressure of about 34 kPa (gauge) (5 psig) to about 173 kPa (gauge) (25 psig), and 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.).

The light upgraded bio-oil stream in line 159 may be passed to the fractionation column 170 to provide an overhead stream in line 171. The overhead stream in line 171 may be cooled and passed to a receiver 173 to further separate the overhead stream. From the receiver 173, LPG and light gases are separated in an overhead receiver stream in line 172. The liquid stream in line 174 from the receiver 173 is separated into a reflux stream in line 175 and a renewable naphtha stream in line 176. The reflux stream in line 175 is recycled back to the fractionation column 170. A side cut stream comprising jet fuel may be taken in a side line 181 from a side of the fractionation column 170. From the bottoms of the fractionation column 170, a bottom stream may be taken in line 178. A reboiling stream may be taken from the bottom stream in line 178, heated in the reboiler 183 and a reboiled stream in line 185 may be passed to the fractionation column 170. A diesel product stream may be taken in line 186 from the bottom stream of the fractionation column 170.

In accordance with the present disclosure, the renewable naphtha stream in line 176 may be analyzed online or offline using one or more of the infrared (IR) spectroscopy and NMR spectroscopy, The NMR spectroscopy determines the physical and chemical properties of atoms or molecules. Proton (¹H) 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. ¹H and ¹³C are the most widely used and their procedures are as below:

¹H Liquid State Procedure

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 scans was 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

NMR spectra of the samples were collected by employing a Bruker 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 μs 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.

31P 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 “Determination of hydroxyl groups in pyrolysis bio-oils using 31P NMR” of Olarte et al. published by the National Renewable Energy Laboratory, March 2016, available at National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications. This method utilizes a phosphorylation by 2-chloro-4,4,5,5-tetramethyl-1,3,2-dioxaphospholane (TMDP) to derivatize-OH containing groups. Results are reported in mmol of OH per gram of sample.

The oxygen content of the renewable naphtha stream in line 176 may be characterized by a band area ratio of oxygenates measured by Attenuated Total Reflectance (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 research-grade instrument, truncated and baseline corrected in GRAMS AI software, and deconvolved and plotted in OriginPro 2016.

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⁻¹ for hydroxyl groups, about 2800-2995 cm⁻¹ for hydrocarbon groups, and about 1000-1315 cm⁻¹ regions for methoxy groups. For the C═O and C═C regions which span from about 1500 cm⁻¹ to about 1800 cm⁻¹, 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 cm⁻¹ to about 1600 cm⁻¹, the alkene C═C band area in the region ranging from about 1600 cm⁻¹ to about 1700 cm⁻¹, and the C═O band area in the region ranging from about 1700 cm⁻¹ to about 1800 cm⁻¹. Depending on the complexity of the region, some spectra could be deconvoluted into 6 bands or as many as 9 bands.

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—O stretching so that O equals (C═O+C—O) integrated band areas. All other band areas identify the specific molecular vibrations that they represent.

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═O/C—O can be calculated and indicates the relative amount of C═O vs C—O bonds in the sample.

Further, the renewable naphtha stream in line 176 may be analyzed to measure oxygen concentration through a carbon, hydrogen, nitrogen, oxygen (CHNO) elemental analysis as a proxy for oxygenate concentration.

The renewable naphtha in line 176 may also be analyzed to measure the oxygen concentration using method UOP 649. This method is the preferred method for analysis of low-oxygen compounds

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.

Further, the presence of cyclic hydrocarbons such as naphthenes and aromatics in the renewable naphtha stream in line 176 may be measured by comprehensive two-dimensional gas chromatography (GC×GC).

The renewable naphtha stream in line 176 can be used as a fuel stream or a blend stock for blending with a fuel stream or both. The renewable naphtha stream in line 176 may be blended with one or both a bio-derived naphtha and a petroleum-derived naphtha. In an embodiment, the renewable naphtha stream in line 176 may comprise about 0.1 wt % to about 15 wt % oxygen, and C4 to about C8 hydrocarbons comprising more than about 50 wt % cyclic hydrocarbons in the renewable naphtha stream. In an aspect, the renewable naphtha stream in line 176 has a final boiling point of no more than about 420° F. In an embodiment, the renewable naphtha stream in line 176 has a final boiling point of about 280° F. to about 330° F., preferably about 290° F. to about 330° F.

The renewable naphtha stream in line 176 may comprise from about C4 to about C8 hydrocarbons. The renewable naphtha stream in line 176 may comprise C4-C5 hydrocarbons boiling within 300° F. The naphtha can have a boiling point higher than 300° F., there are some characteristics of the fuel that are not beneficial at higher boiling points. One of the prominent characteristics is carboxylic acids, as most of the carboxylic acids boil between 300° F. to 400° F. Presence of carboxylic acids in naphtha affect its suitability for use as gasoline blend stock, particularly for an oxygenated naphtha.

For producing an oxygenated naphtha, the LPH reactor 150 is operated at conditions to produce a stable oil. The stable oil comprises a significantly smaller fraction of reactive functional groups than the bio-oil feed, enabling the final product oil to be stable. In accordance with the present disclosure, the renewable naphtha stream in line 176 may comprise from about 0 to about 15 wt % oxygen, preferably from about 4 to about 13 wt % oxygen, and more preferably from about 0.2 to about 5 wt % oxygen.

In an embodiment, the renewable naphtha stream in line 176 may comprise a carbon mole % of at least about 0.25 mol % of one or more groups selected from aldehyde, ester, carboxylic acid, and ketone of the total carbon.

The renewable naphtha of the present disclosure comprises an oxygen content which is below the detection limit for standard procedures. The renewable naphtha stream in line 176 may comprise one or more oxygenates which are allowed in fuel or a blend stock. In an aspect, renewable naphtha stream in line 176 may comprise at least one oxygenate selected from ketones, aldehydes, esters, and carboxylic acids. In an embodiment, the renewable naphtha stream in line 176 may comprise at least about 0.5 wt % oxygenate comprising a ketone, an aldehyde, an ester, or a carboxylic acid. In another embodiment, the renewable naphtha stream in line 176 may comprise at least one oxygenate from about 0.5 wt % to about 12 wt %.

The renewable naphtha of the present disclosure has a very low carboxylic acid number which may approach to about 0.0 mg KOH/g. However, the renewable naphtha of the present disclosure may comprise some carboxylic acids detected by phosphorus NMR. In an aspect, the renewable naphtha stream in line 176 may be characterized by a carboxylic acid number of no more than about 1 mg KOH/g. In an embodiment, the renewable naphtha stream in line 176 may comprise a carbon mole % of less than about 0.2 wt % carboxylic acid of the total carbon in the renewable naphtha stream.

There is very little tolerance for acid number in gasoline, so these compounds might be present at higher oxygen contents in the product oil. Additionally, as the compounds in the naphtha range get more oxygenated, they get more polar, which may affect its miscibility with other fuel. The renewable naphtha of the present disclosure is soluble/miscible with one or both of a bio-derived naphtha and a petroleum-derived naphtha. In an embodiment, the renewable naphtha stream in line 176 may comprise from about 0.5 wt % to about 7 wt % oxygenate.

The renewable naphtha stream in line 176 comprises a significant amount of naphthenes and/or cyclic compounds. In an embodiment, the renewable naphtha stream in line 176 may comprise a weight ratio of the cyclic hydrocarbons to non-cyclic hydrocarbons of about 1.2:1 to about 15.5:1. In another embodiment, the renewable naphtha stream in line 176 may comprise a weight ratio of mononaphthenes to n-paraffins of about 1:1 to about 7:1. In yet another embodiment, the renewable naphtha stream in line 176 may comprise a weight ratio of mononaphthenes to isoparaffins of about 1.5:1 to about 20:1. The renewable naphtha stream in line 176 may comprise at least about or more than about 30 wt % mononaphthenes. The renewable naphtha stream in line 176 may comprise from about 10 wt % to about 30 wt % C6-C8 phenolics.

Further, the renewable naphtha of the present disclosure may comprise one or more alcohols including both aliphatic and aromatic alcohols. In an embodiment, the renewable naphtha stream in line 176 may comprise aliphatic alcohol in an amount from about 0.5 mmole oxygen per gram to about 5 mmole oxygen per gram. In another embodiment, the renewable naphtha stream in line 176 may comprise less than about 0.2 mmole aromatic alcohol per gram.

The renewable naphtha of the present disclosure may be characterized by a Reid vapor pressure of less than about 8.5 psi. The Reid vapor pressure of a fuel may vary depending upon the fuel location. The renewable naphtha of the present disclosure has an octane number in the mid 70's range which is good for blending. The renewable naphtha of the present disclosure has a very low benzene content which is lower than the specification of 1 wt %.

In an embodiment, the renewable naphtha stream in line 176 may be characterized by a benzene content of about 1 wt %, preferably less than about 1 wt %, and more preferably about 0.5 wt %.

EXAMPLES

A 2 L stirred tank reactor pilot plant was operated under several different testing regimes to continuously upgrade bio-oil. In total, seven tests were performed. Bio-oil used in these tests was thermal pyrolysis oil from one of two suppliers (A or B) produced from softwood (SW) or hardwood (HW). In a feed tank, the pyrolysis oil and a molybdenum compound, like Mo octoate, were blended together and fed to the reactor. A stream of sulfiding material (TBPS or H2S) 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. After reaction, the product stream went through hot separators, cold separators, and an oil-water separator to finally provide a light oil product stream (equivalent to stream 159 in FIG. 1), a heavy oil product stream, and an aqueous stream. In all runs, the heavy oil product stream was recycled back into the reactor to provide a source of recycled, activated catalyst and deoxygenated oil. For the study, a total of seven experiments were performed and seven naphtha compositions with different oxygen contents were produced. The operating conditions and the parameters of the four experiments are in Table 1 below:

TABLE 1
Experiment	1	2	3	4	5	6	7
Catalyst	Suspended	Mo	Mo	Mo	Aqueous	Aqueous	Aqueous
	Mo and Mo	octoate	octoate	octoate	Ni/Mo/P	Ni/Mo/P	Ni/Mo/P
	octoate
Bio-oil	A, SW	A, SW	A, SW	A, SW	B, SW	B, SW	B, HW
Sulfiding	TBPS	TBPS	TBPS	TBPS	H2S	H2S	H2S
Agent
Temperature	721	717	721	736	727	744	756
(° F.)
Pressure	1300	1301	1299	1300	1296	1299	1300
(psig)
Gas:Oil	14632	13551	14942	14371	15194	15042	7387
(scfb)
Residence	6.3	4.3	4.5	4.3	7.8	7.8	5.2
Time (hr)
Oxygen	4.3	9.0	12.4	13.0	10.3	7.9	9.6
Content in
light oil
(stream 159)
(wt %)

Light oil products (stream 159) from experiments 1 through 7 were analyzed by comprehensive two-dimensional gas chromatography (GC×GC). Two-dimensional gas chromatography (GC×GC) was employed to characterize the chemical composition of the naphtha samples using two distinct analytical methods: Method A (original approach) and Method B (updated approach). The primary difference between these methods lies in the refinement of peak assignments. In Method A, certain oxygenated compounds were incorrectly classified within the mono-aromatic region, leading to elevated mono-aromatic values. Method B incorporated improved peak identification through the combined use of mass spectrometry and injections of known standards, enabling more accurate differentiation of compound classes. This enhancement allowed Method B to correctly assign oxygenated species such as alcohols, ethers, and ketones, to a newly defined group labeled “Other Oxygenates.” As a result, Method B provided a more precise quantification of individual chemical groups across the GC×GC chromatogram, reducing misclassification and improving overall compositional accuracy.

Table 2 shows the GC×GC results for components containing 4 to 8 carbons, normalized to 100% to simulate the composition of the naphtha component of the light oil (stream 159).

TABLE 2
Two-dimensional gas chromatography (GC × GC)

Experiment	1	2	3	4	5	6	7

Oxygen Content (wt %)	4.3	9.0	12.4	13.0	10.3	7.9	9.6
GC × GC Method	A	A	B	A	B	B	B
n-paraffins	24.1	9.6	5.6	3.9	7.9	6.5	7.0
Isoparaffins	15.7	9.1	3.9	2.2	2.3	2.3	3.4
Mononaphthenes	28.6	33.0	32.3	22.9	40.9	38.8	39.6
Polynaphthenes	0	0	0.1	0	0.1	0.1	0.1
Monoaromatics	12.4	28.4	9.6	49.2	12.4	11.2	9.3
Diaromatics	0	0	0	0	0	0	0
3+ Ring Aromatics	0	0	0	0	0	0	0
C6-C8 Phenolics	19.2	19.9	20.0	21.7	14.3	15.6	15.4
Other Oxygenates	0	0	28.4	0	22.1	25.6	25.2
Total non-Cyclics	39.9	18.7	19.3	6.1	32.3	34.5	35.6
Total Cyclics	60.1	81.3	80.7	93.9	67.7	65.5	64.4
Ratio Cyclics/non-cyclics	1.5	4.3	4.2	15.4	2.1	1.9	1.8
Ratio Naphthenes/n-paraffins	1.2	3.4	5.8	5.9	5.2	6.0	5.7
Ratio Naphthenes/Isoparaffins	1.8	3.6	8.3	10.4	17.8	16.9	11.6

Further, each of the four light oil compositions of experiments 1 to 4 were fractionated by distillation into several distillation cuts. The naphtha portion, equivalent to stream 176 in FIG. 1, consisted of two distillation fractions (cuts). The first naphtha cut had a final boing point of 185° F., while the second cut had an initial boiling point of 185° F. and a final boiling point of 300° F. The first cut was defined as light naphtha and the second cut was defined as medium naphtha. The four compositions of both the light naphtha and the medium naphtha were analyzed by acid number titration, by ¹³C NMR for oxygenate content and by phosphorous NMR for alcohol content. Results of the analysis are as below in Tables 3 and 4.

TABLE 3
13C NMR

Cut

Light Naphtha

Medium Naphtha

Chemical shift

Experiment

	range (ppm)	1	2	3	4	1	2	3	4

Oxygen Content in		4.3	9.0	12.4	13.0	4.3	9.0	12.4	13.0
light oil (stream
159) (wt %)
Oxygen content		3.0	7.5	12.5	15.0	2.6	9.2	14.8	16.4
in naphtha
fractionated cut
Carboxylic		0.48	0	0	0	3	0	3.5	0
acid number
(mg KOH/g)
Carboxylic acid		0.015	0	0	0	0.05	0	0.06	0
concentration
(mmols/g)
Ketones, aldehydes	186-225	0.56	2.47	4.02	6.02	0.35	1.73	3.26	4.47
(mol % of carbon)
Esters, carboxylic	167-186	0.12	0.04	0.13	0.35	0.15	0.32	1.44	1.56
acids (mol %
of carbon)
Aromatics, olefins,	94-167	12.7	9.2	10.9	10.6	4.9	6.4	5.4	18.4
furans (mol %
of carbon)
Alcohols, methoxy,	54-94	2.04	3.70	4.38	6.37	0.93	7.15	5.01	9.44
ethers (mol %
of carbon)

TABLE 4
Phosphorous NMR

Cut

Light Naphtha

Medium Naphtha

Experiment

	1	2	3	4	1	2	3	4

Oxygen Content	4.3	9.0	12.4	13.0	4.3	9.0	12.4	13.0
in light oil
(stream 159)
(wt %)
Oxygen content	3.0	7.5	12.5	15.0	2.6	9.2	14.8	16.4
in naphtha
fractionated
cut
Aliphatic alcohol	1.08	2.14	0.99	3.68	0.553	3.7	1.85	4.52
mmol O/g
Aromatic alcohol	0.00	0.00	0.00	0.00	0.14	0.00	0.00	0.00
mmol O/g

The naphtha composition of the present disclosure has high cyclics content and very high C5 content. The ratio of naphthenes to paraffins and isoparaffins is higher than typical naphtha. The aromatic alcohol content is very low, so the biogenic naphtha can be used as gasoline right out of fractionation without much additional processing required.

As shown in Table 3, the quantities of aromatics, olefins, and furans (corresponding to the chemical shift range of 94 to 167 ppm) were quantified. The results indicate that the light naphtha samples and all but one of the medium naphtha samples exhibit consistent carbon mole percentages within this range for their respective boiling point fractions. These findings corroborate the data presented in Table 2, where GC×GC Method B reports lower mono-aromatic values compared to Method A. This difference arises because oxygenated compounds within the mono-aromatic region were misclassified as mono-aromatics in Method A. With improved peak assignment in Method B, the mono-aromatic values are lower and more uniform, as further supported by the near-constant aromatic peak distribution observed in the 13C NMR analysis summarized in Table 3.

Light and medium naphtha fractions were also evaluated for research octane number (RON) in accordance with ASTM D2699. In Experiment 1, the light naphtha exhibited a RON of 72.9, while the corresponding medium naphtha measured 68.4. In Experiment 2, the light naphtha fraction demonstrated a RON of 75.2, and the medium naphtha fraction measured 71.7. These results confirm that the tested naphtha streams possess sufficiently high octane values for the intended fuel applications or blending.

SPECIFIC EMBODIMENTS

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.

A first embodiment of the invention is a renewable naphtha composition, the renewable naphtha composition comprising about 0.1 wt % to about 15 wt % oxygen, a final boiling point of no more than about 420° F., and C4 to about C8 hydrocarbons comprising more than about 50 wt % cyclic hydrocarbons in the renewable naphtha composition. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises from about 4 wt % to about 13 wt % oxygen. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises a carbon mole % of at least about 0.25 mol % of one or more groups selected from aldehyde, ester, carboxylic acid, and ketone of the total carbon. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises a carbon mole % of less than about 0.2 wt % carboxylic acid of the total carbon. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises aliphatic alcohol in an amount from about 0.5 mmole oxygen per gram to about 5 mmole oxygen per gram. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises less than about 0.2 mmole aromatic alcohol per gram. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises a weight ratio of the cyclic hydrocarbons to non-cyclic hydrocarbons of about 1.21 to about 15.51. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises a weight ratio of mononaphthenes to n-paraffins of about 11 to about 71. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises a weight ratio of mononaphthenes to isoparaffins of about 1.51 to about 201. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises more than about 30 wt % mononaphthenes. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises from about 10 wt % to about 30 wt % C6-C8 phenolics. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition comprises less than about 1 wt % benzene. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition is characterized by a carboxylic acid number of no more than about 1 mg KOH/g. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the renewable naphtha composition is a blend stock for blending with one or both of a bio-derived fuel stream and a petroleum-derived fuel stream.

A second embodiment of the invention is a renewable naphtha composition, the renewable naphtha composition comprising about 0.1 wt % to about 15 wt % oxygen, a final boiling point of no more than about 420° F., a carbon mole % of less than about 0.2 wt % carboxylic acid of the total carbon, and C4 to about C8 hydrocarbons comprising more than about 50 wt % cyclic hydrocarbons in the renewable naphtha composition. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph 5, wherein the renewable naphtha composition comprises about 4 wt % to about 13 wt % oxygen. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph 5, wherein the renewable naphtha composition comprises a weight ratio of the cyclic hydrocarbons to non-cyclic hydrocarbons of about 1.21 to about 15.51. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the renewable naphtha composition comprises a weight ratio of mononaphthenes to n-paraffins of about 11 to about 71. An embodiment of the invention is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the renewable naphtha composition comprises a weight ratio of mononaphthenes to isoparaffins of about 1.51 to about 201.

A third embodiment of the invention is a process of producing renewable naphtha, comprising reacting a bio-oil stream with hydrogen in the presence of a catalyst in a reactor to produce an upgraded bio-oil stream; and fractionating the upgraded bio-oil stream to produce a renewable naphtha stream, the renewable naphtha stream comprises about 0.1 wt % to about 15 wt % oxygen, a final boiling point of no more than about 420° F. and about C4 to about C8 hydrocarbons comprising more than about 50 wt % cyclic hydrocarbons in the renewable naphtha stream.

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.

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