HYDROCARBON UPGRADING PROCESS WITH CATALYST FINES

Description

FIELD

The field is related to a process for upgrading a bio-oil stream. Particularly, the field relates to a process for upgrading a bio-oil stream in the presence of a spent hydrotreating catalyst.

BACKGROUND

Hydrocarbon conversion processes typically require reactor systems, and associated conduits and piping, adapted for hydrocracking, reforming, fluidized catalytic cracking, and other similar processes.

Bio-oils are obtained by thermochemical liquefaction, notably pyrolysis, 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 a so-called 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 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 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 s), for the so-called 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 s) for the so-called 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, with 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% by mass; (3) chemical instability on account of the abundance of reactive functional groups like the carboxyl group 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.

Over the last two decades, the approach of direct hydroprocessing of bio-oil to convert it to stable oxygenates or hydrocarbons has been studied intensively. A major obstacle to the catalytic hydroprocessing of bio-oil has been its propensity to polymerize under heating above about 100° C., leading ultimately to the formation of extraneous solids or coke at temperatures above about 140° C., with consequences like reactor plugging and catalyst deactivation.

A sustainable fuel can be produced by hydrotreating a biorenewable feedstock in the presence of a hydrotreating catalyst. The biorenewable feedstock can be hydrotreated to deoxygenate, including decarboxylate and decarbonylate, the oxygenated hydrocarbons present in the biorenewable feedstock. Hydrotreating may be followed by hydroisomerization to improve cold flow properties of product diesel and jet fuel. The hydrotreating catalysts gradually lose activity through deactivation with time, and the spent catalysts are usually discarded as solid waste. Disposal of spent hydroprocessing catalysts requires compliance with stringent environmental regulations because of their hazardous nature and toxic chemicals content. If not treated or reused properly, the spent hydrotreating catalyst may cause environmental problems.

Therefore, there is a need for an improved process for bio-oil hydroprocessing that minimizes the formation of solids, provides an alternative solution for the spent hydrotreating catalyst and provides an upgrade deoxygenated oil product that can be used for producing useful fuels.

SUMMARY

The present disclosure provides a process for upgrading a bio-oil stream. The process comprises discharging spent hydrotreating catalyst fines from a hydrotreating reactor, the hydrotreating catalyst comprising a metal from Group IVB, Group VB, Group VIB, Group VIIB, and Group VIII metals on an inorganic support. A bio-oil stream is reacted with hydrogen in the presence of the spent hydrotreating catalyst fines in a bio-oil reactor to produce an upgraded bio-oil stream. The hydrotreating catalyst fines have a D90 particle size of about 1000 microns. The spent hydrotreating catalyst is separated from the upgraded bio-oil stream. The spent hydrotreating catalyst fines comprises about 5 wt % to about 25 wt % carbon. The spent hydrotreating catalyst fines can be sealed under nitrogen atmosphere and charged to biocrude upgrading unit for upgrading the bio-oil stream.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a schematic diagram of the process for upgrading a bio-oil stream in accordance with an exemplary embodiment of the present disclosure.

FIG. 2 illustrates a schematic diagram of the process for upgrading a bio-oil stream in accordance with another exemplary 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 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 hydrocarbon molecule and typically a paraffin 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 “T10” or “T90” means the temperature at which 10 mass percent or 90 mass percent, as the case may be, respectively, of the sample boils using ASTM D-86 or TBP.

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 with an aldehyde functional group and 2 moles of carbon atoms in the bio-oil correspond to C atoms of molecules with 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.

As used herein, the term “D90” indicates that 90 wt % of the particles in the sample are smaller than the dimension stated.

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 and a stable oil to produce an upgraded bio-oil. The upgraded bio-oil can be used directly as fuel oil such as marine fuel. Alternatively, the upgraded bio-oil can be used as a feedstock for an FCC unit, a hydroprocessing unit, or a reforming unit to produce an intermediate blend or fuel. The upgrading process may include various analyses such as for a content of the reactor to generate spectroscopy data to identify molecular functional groups that are responsible for bio-oil polymerization. Identification and tracking of functional group evolution as a function of catalyst or process conditions helps in targeting the groups responsible for rapid polymerization and charring providing the potential to selectively eliminate them thereby enhancing the performance of the upgrading process. As described later in detail, the process comprises converting the oxygenate groups present in the feed, for example, to control charring potential.

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 by products (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 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 feeds 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.

FIG. 1 shows an exemplary embodiment of the process 100 for upgrading a bio-oil stream. 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 bio-derived and/or 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. In another embodiment, a plastic pyrolysis oil and/or a tire pyrolysis oil is the non-bio derived feed stream. In an aspect, a stable oil stream is taken in line 132 from a source, for example, a storage drum 130. The stable oil stream in line 132 may be passed to the mixer 140. Perhaps the stable oil stream in line 132 may be pumped via a pump 133 and a pumped stable oil 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 stable oil stream to the mixer 140. In an embodiment, a sulfur source comprising a sulfiding agent in line 131 may be added to the stable oil 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. The stable oil stream in line 132 may be a petroleum stream, a bio-derived stream, and/or produced from renewables.

In the mixer 140, the bio-oil stream in line 124 and the stable oil stream in line 134 are mixed and kept well mixed at a ratio perhaps with an excess of the stable oil stream at the startup of the process. In an embodiment, the bio-oil stream in line 124 and the stable oil stream in line 134 are mixed in the mixer 140 at a mass ratio of the bio-oil stream and the stable oil 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 stable oil stream in a ratio of about 0:100 to about 80:20 by mass at start-up. In an exemplary embodiment, the stable oil 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 hydrotreating catalyst in a bioreactor to produce an upgraded bio-oil stream.

In an embodiment, the mixed stream in line 142 is passed to a bio-oil reactor 150 such as a liquid phase hydrotreating (LPH) reactor. As described later in detail, a recycle stream in line 139 may also be passed to the bio-oil reactor 150. A hydrogen stream in line 144 may also be passed to the bio-oil reactor 150. In an embodiment, the hydrogen stream in line 144 may be blended or mixed with the mixed stream in line 142 and passed to the bio-oil reactor 150. A catalyst stream in line 224 may also be passed to the bio-oil reactor 150.

Applicants found that a spent hydrotreating catalyst can be used to upgrade a bio-oil stream in the bioreactor. The spent hydrotreating catalyst may not need pretreatment for upgrading the bio-oil stream in the bio-reactor. The spent hydrotreating catalyst may be fed directly to the bioreactor or may be stored and a stored spent hydrotreating catalyst may be passed to the bioreactor. The spent hydrotreating catalyst may be grounded to fines and spent hydrotreating catalyst fines can be fed to the bioreactor. The spent hydrotreating catalyst can be discharged from a hydrotreating reactor 210 in an exemplary embodiment as shown in FIG. 1.

The hydrotreating reactor 210 may comprise a hydrotreating catalyst. In the hydrotreating reactor 210, a hydrocarbon stream in line 202 may be contacted with a hydrotreating catalyst in the hydrotreating catalyst bed 211 in the presence of hydrogen at hydrotreating conditions to saturate the olefinic or unsaturated portions of the n-paraffinic chains in the biorenewable feedstock. The hydrocarbon stream in line 202 may comprise a biorenewable feedstock. The hydrotreating catalyst also may catalyze hydrodeoxygenation reactions to remove oxygenate functional groups from the hydrocarbon molecules in the biorenewable feedstock which are converted to water and carbon oxides. The hydrotreating catalyst also catalyzes removal of heteroatoms from the hydrocarbons in the feed stream. Prominent heteroatoms removal chemistry includes hydrodenitrogenation of organic nitrogen and hydrodesulfurization of organic sulfur in the feedstock whether biorenewable or petroleum feedstock. The hydrotreating catalyst may be provided in one, two or more beds 211 in the hydrotreating reactor 210.

The hydrotreating catalyst may comprise a metal from Group IVB, Group VB, Group VIB, Group VIIB, and Group VIII metals on an inorganic support such as alumina, preferably Group VIB, or Group VIIB metals. The hydrotreating catalyst may comprise nickel, nickel and molybdenum, nickel and tungsten, cobalt and tungsten, or cobalt and molybdenum dispersed on a high surface area support such as alumina or unsupported as a bulk mixed metal sulfide. 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 BDO 200 or BDO 300 or BDO 400 available from UOP LLC in Des Plaines, Illinois.

Conventional hydrotreating catalysts may be used. Suitable conventional hydrotreating catalysts may include those which are comprised of at least one Group VIII metal preferably iron, cobalt and nickel, more preferably cobalt and/or nickel, and at least one Group VI metal, preferably molybdenum and tungsten, on a high surface area support material, preferably alumina, or left unsupported as a bulk mixed metal oxide or sulfide. Other suitable catalysts include zeolitic catalysts, as well as noble metal catalysts where the noble metal is selected from palladium and platinum. It is within the scope of the processes herein that more than one type of catalyst be used in the same reaction vessel. The Group VIII metal may typically be present in an amount ranging from about 0 to about 55 weight percent, preferably from about 1 to about 50 weight percent, or more preferably 2 to 47 weight percent. The Group VI metal may typically be present in an amount ranging from about 0 to about 60 weight percent, and preferably from about 1 to about 50 weight percent, or more preferably 2 to 47 weight percent.

The hydrotreated effluent stream in line 212 is taken from the hydrotreating reactor 210 for further processing. The spent hydrotreating catalyst can be discharged from the hydrotreating catalyst bed 211 in a spent hydrotreating catalyst stream in line 214. The spent hydrotreating catalyst stream in line 214 may be passed to a spent catalyst hold-up vessel 220. In the hold-up vessel 220, the spent hydrotreating catalyst may be stored under inert atmosphere such as nitrogen.

The spent hydrotreating catalyst may comprise coke deposits accumulated in the hydrotreating reaction. We have found that the coke deposits on the spent hydrotreating catalyst does not inhibit the activity of the pyoil hydrotreating reactions. The spent hydrotreating catalyst may comprise about 5 wt % to about 25 wt % carbon, suitably about 6 wt % to about 20 wt % carbon and preferably about 7 wt % to about 15 wt % carbon and most preferably about 8 wt % to about 12 wt % carbon.

In an embodiment, the spent hydrotreating catalyst stream in line 214 may be preliminarily passed to a grinding vessel 215 to grind the spent catalyst stream in line 214 and provide a ground spent hydrotreating catalyst. The grinding vessel 215 may be selected from ball mill or grinding mill. The spent hydrotreating catalyst in the spent catalyst line 222 may comprise catalyst fines exhibiting a D90 particle size of about 1000 microns, or about 900 microns, or about 800 microns, or about 700 microns or about 600 microns, or about 500 microns, or about 400 microns, or about 300 microns, or about 200 microns, or about 100 microns, or about 50 microns. In an exemplary embodiment, the spent hydrotreating catalyst in the spent catalyst line 222 may be ground to provide catalyst fines having D90 particle size of about 500 microns, suitably about 400 microns, more suitably about 300 microns, preferably about 200 microns, about 150 microns, more preferably about 100 microns, even more preferably about 50 microns, still more preferably about 40 microns, yet more preferably about 30 microns, and most preferably about 20 microns. A ground spent hydrotreating catalyst stream is taken in line 216 and passed to the spent catalyst hold-up vessel 220.

In an aspect, the D90 particle size of the hydrotreating catalyst particles before or after grinding may be determined by a method analogous to the established ASTM D4513-22. The ASTM D4513-22 method focuses on determining the particle size distribution through a systematic sieving process. In this approach, the catalyst particles are subjected to a series of sieving stages, wherein each stage involves passing the catalyst through a pre-designated series of mesh sieves. The sieving stages may include, but are not limited to, within the range from about 18 mesh (1000 microns) to about 1250 mesh (10 microns), differing from the standard ASTM D4513-22 sieves, to provide enhanced resolution and granularity in the resulting particle size data. The process involves shaking or vibrating the sieves to ensure optimal separation of particle sizes, followed by the precise measurement of the weight of particles retained on each sieve.

In an exemplary embodiment, the catalyst fines may be defined as catalyst particles having a D90 particle size of about 1000 microns (18 mesh) or less.

The hydrotreating catalyst in the hydrotreating reactor 210 can be sulfided in situ in the hydrotreating reactor or pre-sulfided to form metal sulfides which in turn are used as a catalyst for hydrotreating. The hydrotreating catalyst in the hydrotreating reactor 210 may be received in an oxidized or partially oxidized form. Sulfidation may be conducted under a variety of sulfidation conditions such as through contact of the catalyst composition with a sulfiding agent such as sulfur-containing stream or feedstream, or a gaseous mixture of hydrogen sulfide or hydrogen or both. The sulfidation of the catalyst composition may be performed at elevated temperatures. The materials resulting from the sulfiding step are referred to as metal sulfides which can be used as hydrotreating catalysts. The sulfiding step can take place ex situ at a location remote from the hydrotreating step. The sulfiding step may take place in situ in the bio-oil reactor 150.

A ground spent hydrotreating catalyst is taken in a spent catalyst line 222 from the hold-up vessel 220. The ground spent hydrotreating catalyst in the spent catalyst line 222 is charged to the bio-oil reactor 150 for upgrading the bio-oil stream. In an aspect, the ground spent hydrotreating catalyst in the spent catalyst line 222 may comprise a sulfided hydrotreating catalyst. In an aspect, the ground spent hydrotreating catalyst in the spent catalyst line 222 may comprise an oxidized or partially oxidized hydrotreating catalyst. In an exemplary embodiment, the ground spent hydrotreating catalyst in the spent catalyst line 222 may comprise about 5 wt % to about 25 wt % coke which is accumulated during the time the hydrotreating catalyst is in service in the hydrotreating reactor 210. In an exemplary embodiment, the ground spent hydrotreating catalyst in the spent catalyst line 222 may comprise no more than about 15 wt % coke, or preferably no more than about 10 wt % coke, or even more preferably no more than about 7 wt % coke. The coke is accumulated during the time the hydrotreating catalyst is in service in the hydrotreating reactor 210 and after a partial or complete coke burn of the reactor that may partially or fully oxidize the hydrotreating catalyst.

In an embodiment, the ground spent hydrotreating catalyst in the spent catalyst line 222 may be blended or mixed with the mixed stream in line 142 to provide a combined stream in line 223 which is passed to the bio-oil reactor 150. In an alternate embodiment, the ground spent hydrotreating catalyst in the spent catalyst line 222 may be fed directly to the bio-oil reactor 150. The ground spent hydrotreating catalyst in line 222 may be combined with the mixed stream in line 142 to provide a hydrotreating charge stream in line 223 which may be charged to the bio-oil reactor 150. In another embodiment, the ground spent hydrotreating catalyst in line 222 may be added to the recycle stream in line 139 to provide a combined recycle stream which is passed to the bio-oil reactor 150 through a pump 157. In an aspect, a fresh hydrotreating catalyst stream in line 224 may be taken from a catalyst inventory and passed to the bio-oil reactor 150 in the hydrotreating charge line 223. In an embodiment, the fresh hydrotreating catalyst stream in line 224 may be combined with the hydrotreating charge stream in line 223 to provide a combined hydrotreating charge stream in line 226 which is passed to the bio-oil reactor 150. The fresh hydrotreating catalyst stream in line 224 may be optionally used to assist the upgrading of the bio-oil stream in the presence of the ground spent hydrotreating catalyst. The fresh hydrotreating catalyst may comprise no more than about 5 wt % carbon, and preferably no carbon. In the bio-oil reactor 150, the stable oil stream, the bio-oil stream, the recycle stream, and the hydrogen stream may be reacted over the spent hydrotreating catalyst in a continuous liquid phase to provide an upgraded bio-oil stream. The upgraded bio-oil stream may be discharged in line 154 from the bio-oil reactor 150.

The upgraded bio-oil stream in line 154 may be charged to an FCC unit, a hydroprocessing unit, or a reforming unit to produce an intermediate blend or a fuel stream as described later in detail. Or a fuel oil stream may be taken from the upgraded bio-oil stream in line 154. In an aspect, a portion of the upgraded bio-oil stream in line 154 may be taken and charged to the FCC unit, the hydroprocessing unit, or the reforming unit to produce the intermediate blend or the fuel stream. Another portion of the upgraded bio-oil stream in line 154 may be taken as a fuel oil stream.

In an exemplary embodiment, the upgraded bio-oil stream in line 154 may be separated into a light upgraded bio-oil stream in line 159 and a heavy upgraded bio-oil stream in line 179.

Liquid phase hydrotreating (LPH) is used for upgrading the heavy hydrocarbon feedstocks to produce distillate 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 fines in sulfided form. Metal or metal compound nanoaggregates may also be used to form the solid particulates.

In another aspect, a sulfidation component or the sulfidation additive may be provided in a line 131 and added to the stable oil stream in line 132. In another aspect, a catalyst may be added to the feed stream in line 122 or the stable oil stream in line 132.

The active metals employed in the hydrotreating catalysts of the present disclosure as hydrogenation components are the base metals of Group VIII, such as iron, cobalt, and nickel. In addition to these metals, other promoters may also be employed in conjunction therewith, including the metals of Group VIB, such as 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, metal may be provided in the ground spent hydrotreating catalyst exhibiting D90 particle size typically of about 500 microns or about 400 microns, suitably about 200 microns, preferably about 100 microns, more preferably about 60 microns, and even more preferably about 40 microns. The hydrotreating catalyst may be in a sulfided form.

With or without out help from other catalysts, such as the fresh catalyst stream in line 224, the concentration of the active metal in the bio-oil reactor may be in the range of about 0.01 wt % to about 7 wt %, preferably about 0.01 wt % to about 5 wt %, or more preferably about or of a reaction mixture in the bio-oil reactor 150.

Conditions in the bio-oil 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 bio-oil reactor 150 may be a continuous stirred tank reactor (CSTR). Operating conditions in the bio-oil reactor 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 bio-oil reactor 150, the upgraded bio-oil stream is taken in line 154.

In an aspect, the bio-oil reactor 150 may be selected from a bubble column reactor, a slurry reactor, or 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.

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

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 the 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 the hydrotreating 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 hydrotreating catalyst. For example, all the hydrotreating catalyst exiting from the bio-oil 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 the hydrotreating 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 200° C. to about 400° C. and at a pressure of about the pressure of the bio-oil reactor 150.

The hot bottoms stream in line 156 may be recycled to the bio-oil reactor 150. The hot bottoms stream in line 156 may be passed to a tank 177. A recycle oil stream comprising the hydrotreating catalyst is taken in line 158 from the bottom of the tank 177. A heavy oil stream in line 179 may be taken from a side of the recycle tank 177. A majority of the catalyst may be in the recycle oil stream in line 158. A concentrated catalyst stream in line 138 may be combined with the recycle oil stream in line 158 to provide a combined recycle oil stream in line 139 which may be recycled to the bio-oil reactor 150 through the pump 157. A control valve 162 may be provided on the line 139 to regulate the flow of the recycle oil stream and the hydrotreating catalyst in line 139 to the bio-oil reactor 150. It is anticipated that the combined recycle oil stream in line 139 gradually but ultimately replace the flow rate of stable oil in line 132 to the bio-oil reactor 150, so that stable oil stream to the bio-oil reactor 150 is only supplied by recycle oil stream in line 139.

In an embodiment, the heavy oil stream in line 179 is 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, an electrostatic precipitator, or a combination thereof. In the catalyst separation vessel 136, the catalyst is separated from the heavy oil. A heavy oil product stream is taken in line 137 from the catalyst separation vessel 136. The concentrated catalyst stream comprising catalyst in heavy oil is taken in line 138 from the vessel 136. The heavy oil product stream in line 137 may be taken as a fuel oil product stream.

In an aspect, the heavy oil product stream in line 137 may be analyzed using, for example, infrared (IR) spectroscopy and nuclear magnetic resonance (NMR) spectroscopy to measure its composition. 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 may be 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 may be 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 may be 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 may be collected by employing a Bruker Avance Spectrometer operating at a frequency of 125.7715 for 13C experiments. The samples may be prepared using a 50:50 (v/v) mixture of chloroform-d and bio-oil analyte. Additionally, a trace quantity of tetramethylsilane may be added as an internal reference and chromium acetylacetonate was used as a relaxation agent. Quantitative results may be obtained using an inverse-gated pulse sequence, and all 13C spectra may be acquired by using 11.3 us pulses and 10 seconds of delay between acquisitions. The number of scans may be 2048. Processing may include baseline correction and the use of 3 Hz exponential line broadening before Fourier transformation. The spectra may be 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 may be 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.

In accordance with an exemplary embodiment, as per 1H NMR spectroscopy, the heavy oil product stream in line 137 should comprise at least one or more of an aldehyde at a concentration of about 0 mol % H to about 3 mol % H, or preferably about 0 mol % H to about 2 mol % H, or more preferably about 0 mol % H to about 1 mol % H. As per 13C NMR spectroscopy the heavy oil product stream in line 137 should comprise at least one of the group ketones and aldehydes at a concentration of about 0 mol % C to about 6 mol % C, or preferably about 0 mol % C to about 4 mol % C, or more preferably about 0 mol % C to about 2 mol % C; at least one of the group carboxylic acids and esters at a concentration of about 0 mol % C to about 6 mol % C, or preferably about 0 mol % C to about 4 mol % C, or more preferably about 0 mol % C to about 3 mol % C; and at least one of the group ethers, alcohols, phenolic methoxys, and carbohydrates at a concentration of about 0 mol % C to about 6 mol % C, or preferably about 0 mol % C to about 4 mol % C, or more preferably about 0 mol % C to about 2 mol % C.

The composition of the heavy oil product stream in line 137 may also be characterized by a band area ratio of oxygenates measured by Attenuated Total Reflectance Infrared (ATR-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.

In an exemplary embodiment, the heavy oil product stream in line 137 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 1.2; 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.

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 or separation techniques may be used to separate the catalyst from the heavy oil in the catalyst separation vessel 136.

In an aspect, a fuel oil stream in line 166 may be taken from the heavy oil stream in line 137. In an embodiment, the remaining heavy oil stream in line 184 may be processed in an FCC unit or a hydroprocessing unit or a reforming unit 180 to provide a product stream in line 182. The fuel oil stream in line 166 may be sent to a marine fuel oil pool.

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 bio-oil 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 bio-oil 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 accordance with the present disclosure, the light upgraded bio-oil stream in line 159 may be analyzed at desired time intervals and analyzed offline using one or more of the infrared (IR) spectroscopy and NMR spectroscopy to determine its composition and quality. In accordance with an exemplary embodiment, as per 1H NMR spectroscopy, the light upgraded bio-oil stream in line 159 may comprise aldehydes at a concentration of about 0 mol % to about 4 mol % H, or preferably about 0 mol % to about 2 mol % H, or more preferably about 0 mol % to about 1 mol % H. In accordance with another exemplary embodiment, as per 13C NMR spectroscopy the light upgraded bio-oil stream in line 159 may comprise at least one or more of at least one of the group ketones and aldehydes at a concentration of about 0 mol % C to about 6 mol % C, or preferably about 0 mol % C to about 5 mol % C, or more preferably about 0 mol % C to about 3.5 mol % C; at least one of the group carboxylic acids and esters at a concentration of about 0 mol % C to about 6 mol % C, or preferably about 0 mol % C to about 5 mol % C, or more preferably about 0 mol % C to about 4 mol % C; and at least one of the group ethers, alcohols, phenyl methoxy groups, and carbohydrates at a concentration of about 0 mol % C to about 11 mol % C, or preferably about 0 mol % C to about 9 mol % C, or more preferably about 0 mol % C to about 7 mol % C, or yet more preferably about 0 mol % C to about 5 mol % C.

The light upgraded bio-oil stream in line 159 may be characterized by a band area ratio of oxygenates measured by ATR-IR spectroscopy. In an exemplary embodiment, the light upgraded bio-oil stream in line 159 may 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 0.6, or preferably from about 0 to about 0.5, or more preferably from about 0 to about 0.4; an OH/C ratio from about 0 to 3, or preferably from about 0 to about 2, or more preferably from about 0 to about 1.5; and an O/C ratio from about 0 to 1.7; or preferably from about 0 to about 1.3, or more preferably from about 0 to about 0.85.

In an aspect of the present disclosure, the light upgraded bio-oil stream in line 159 may be separated into several streams and at least one of the streams may be passed to an FCC unit or a hydroprocessing unit or a reforming unit 180 or taken as a product stream.

In a preferred 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 in line 159 into one or more hydrocarbon streams. 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 passed to a receiver 173 to further separate the overhead stream. From the receiver 173, LPG and light gases are separated in stream 172. The liquid stream in line 174 from the receiver 173 is separated into a reflux stream in line 175 and a naphtha stream in line 176. The reflux stream in line 175 is recycled back to the fractionation column 170. A kerosene stream may be taken in line 181 from a side of the fractionation column 170. From the bottoms of the fractionation column 170, a diesel stream may be taken in line 178. A reboiling stream may be taken from the diesel stream in line 178, heated in the reboiler 183 and a reboiled stream in line 185 may be passed to the fractionation column 170.

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 250° C. (482° F.) to about 450° C. (842° F.) or about 300° C. (572° F.) to about 400° C. (752° F.).

A portion or an entirety of the naphtha stream in line 176 may be passed to the reforming unit 180 or another downstream processing unit. In an alternate embodiment, the naphtha stream in line 176 may be recovered from the process. In an aspect, the naphtha stream in line 176 may be used as is without further processing.

In an embodiment, a portion or an entirety of the diesel stream in line 178 may be passed to the FCC unit 180 or the hydroprocessing unit 180 or the reforming unit 180. In an alternate embodiment, the diesel stream in line 178 may be taken out from the process. In an aspect, the diesel stream in line 178 may be used as is without further processing.

In another embodiment, a portion or an entirety of the kerosene stream in line 181 may be passed to the FCC unit 180 or the hydroprocessing unit 180 or the reforming unit 180. In an alternate embodiment, the kerosene stream in line 181 may be taken out from the process. In an aspect, the kerosene stream in line 181 may be used as is without further processing.

In an exemplary embodiment, the heavy oil stream in line 137 is passed to the FCC unit 180 or the hydroprocessing unit 180 or the reforming unit 180 to provide the product stream in line 182. In an alternate embodiment, the heavy oil stream in line 137 may be recovered from the process. In an aspect, the heavy oil stream in line 137 may be used as is without further processing.

In an aspect, the fuel oil stream in line 166 may be passed to a stripping column 190 to strip the light materials. A stripping media such as steam may be passed to the stripping column 190 in a stripping media line 191. Lighter material may be taken in an overhead line 192 from the stripping column 190. A stripped fuel oil stream may be taken from the bottoms of the stripping column 190 in line 194. The stripping column 190 may be operated at a bottoms temperature of about 75° C. to about 250° C.

In an aspect, one or more the product streams in lines 166, 176, 178, 181, 182, 192, or 194 may be recycled to the bio-oil reactor 150. The hydrocarbon feedstock in line 202 may comprise one or more of the product streams in lines 166, 176, 178, 181, 182, 192, or 194. In an embodiment, the composition of the feedstock in line 202 may be similar to any of the product streams in lines 166, 176, 178, 181, 182, 192, or 194.

Another exemplary embodiment of the upgrading a bio-oil stream is shown in FIG. 2. Elements in FIG. 2 with the same configuration as in FIG. 1 will have the same reference numeral as in FIG. 1. Elements in FIG. 2 which have a different configuration as the corresponding element in FIG. 1 will have the same reference numeral but designated with a prime symbol (′). The configuration and operation of the embodiment of FIG. 2 is essentially the same as in FIG. 1 with the following exceptions.

In the embodiment shown in FIG. 2, the process 200 comprises a once-through bio-oil reactor 150 for upgrading the bio-oil stream. In the embodiment with the once-through bio-oil reactor 150, the spent hydrotreating catalyst may be separated from the upgraded bio-oil stream and withdrawn for further treatment or discarded.

As shown in FIG. 2, the upgraded bio-oil stream in line 154 is passed to the hot separator 160. The hot bottoms stream which contains the hydrotreating catalyst is taken in line 156 from the bottoms of the hot separator 160. The hot bottoms stream in line 156 may be characterized as a heavy oil stream comprising the hydrotreating catalyst. Light oil is taken in a hot overhead stream in line 155 from the hot separator 160. The hot bottoms stream in line 156 may be passed to a tank 177′. A heavy oil stream with the hydrotreating catalyst may be taken in line 179′ from the recycle tank 177′. The heavy oil stream in line 179′ is passed to the catalyst separation vessel 136 for separating hydrotreating catalyst. 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, an electrostatic precipitator or a combination thereof. In the catalyst separation vessel 136, the hydrotreating catalyst is separated from the heavy oil. A heavy oil product stream is taken in line 137 from the catalyst separation vessel 136. The hydrotreating catalyst is taken in line 138 from the vessel 136. The hydrotreating catalyst in line 138 is a spent hydrotreating catalyst which can be removed from the process 200. None of the upgraded bio-oil stream in line 154 is returned to the bio-oil reactor 150 in this embodiment. The rest of the process is the same as previously described in FIG. 1.

EXAMPLES

Example 1—Successful Semi-Batch Autoclave Tests

A total of six experiments were performed. For the six experiments, hydrotreating catalysts were sulfided and grounded to a less than about 100 micron particle size like a fine powder. The sixth experiment involved spent hydrotreating catalyst. The autoclave reactor was sealed and pressurized with H₂ with the H₂ flowing at 420-700 sccm throughout the entirety of the experiment. Subsequently, the autoclave reactor was heated to 420-450° C. at 2° C./min while stirring at 600-1000 rpm and held at the indicated temperature for 2 hours. After the reaction time of 2 hours, the autoclave reactor was cooled to room temperature (20-25° C.). Once cooled, the autoclave reactor was opened and liquid from the reactor was collected and designated heavy oil product. Similarly, a portion of the hydrocarbons became gas at the indicated reaction temperature and were swept out of the reactor via the H₂ flow and subsequently condensed into liquid in a condenser vessel downstream of the reactor at room temperature. After completion of the experiment, the liquid was drained from the condenser vessel and designated a light oil product and an aqueous product. The light oil and aqueous product naturally separated in a separatory funnel and were stored as separate products. Specific reaction conditions for the six experiments are provided in Table 1 below:

TABLE 1
Reactor
Conditions	Test 1	Test 2	Test 3	Test 4	Test 5	Test 6

T (° C.)	450	450	450	420	420	420
P (psig)	2000	2000	1500	1850	1850	1800
Oil Mass (g)	320	320	320	192	192	192
Catalyst Mass	7.5	7.5	7.5	2	1	4.6
(g)
Hydrogen	700	700	700	420	420	420
flow rate
(sccm)
Catalyst	Unsupported	Supported	Supported	Unsupported	Unsupported	Supported
Compound	NiWMoS	NiMoS	NiMoS	NiMoS	NiMoS	NiMoS
Catalyst State	Fresh	Fresh	Fresh	Fresh	Fresh	Spent
Carbon	not measured	not	not	not measured	not measured	12
Concentration		measured	measured
(wt %)
Catalyst	Liquid	Gas	Gas	Liquid	Liquid	Liquid
Sulfiding	Sulfiding	Sulfiding	Sulfiding	Sulfiding	Sulfiding	Sulfiding
Method		with H2S	with H2S
Extra	DMDS	Powdered	Powdered	DMDS	DMDS	DMDS
Sulfiding		Sulfur	Sulfur
Compound
Added to
Reactor

The product streams were analyzed for the six experiments. The analytical results of the analysis are as below in Table 2 and Table 3.

TABLE 2
Heavy Oil Product Stream

	Test 1	Test 2	Test 3	Test 4	Test 5	Test 6

Relative Density by	not	not	1.29	not	1.148	1.1285
ASTM D4052 (g/mL)	measured	measured		measured
Carbon by ASTM	87.6	83.7	84.8	79.5	87.5	86.5
D5291 (wt %)
Hydrogen by ASTM	6.41	6.91	6.19	7.45	7.06	7.52
D5291 (wt %)
Oxygen by ASTM	not	not	not	9.64	3.94	3.51
UOP649 (wt %)	measured	measured	measured
Oxygen by Difference,	5.84	8.07	8.91	13.05	5.44	5.98
ASTM D5291 (wt %)
Carboxylic Acid	not	not	not	not	30.2	0 (not
Number (mg KOH/g)	measured	measured	measured	measured		detected)
Phenolic Acid Number	not	not	not	not	76.3	96.2
(mg KOH/g)	measured	measured	measured	measured
NMR Spectroscopy
Aldehydes (mol % H)	0 (not	0.02	0.06	0 (not	0 (not	0.09
	detected)			detected)	detected)
Ketones, Aldehydes	0 (not	0 (not	0 (not	0 (not	0 (not	0 (not
(mol % C)	detected)	detected)	detected)	detected)	detected)	detected)
Esters, Carboxylic	0 (not	0 (not	0 (not	0 (not	0 (not	0 (not
Acids (mol % C)	detected)	detected)	detected)	detected)	detected)	detected)
Alcohols, Ethers,	0 (not	0 (not	0 (not	0 (not	0 (not	0 (not
Phenolic Methoxys,	detected)	detected)	detected)	detected)	detected)	detected)
Carbohydrates (mol %
C)
IR Spectroscopy
C—O/C (IR Band Area	0.10	0.05	0.08	0.01	0.2	0.15
Ratio)
C═O/C (IR Band Area	0.03	0.03	0.04	0 (not	0.01	0.01
Ratio)				detected)
OH/C (IR Band Area	0.29	0.04	0.13	0 (not	1.13	0.5
Ratio)				detected)
O/C (IR Band Area	0.13	0.08	0.12	0.01	0.22	0.17
Ratio)

TABLE 3
Light Oil Product Stream

	Test 1	Test 2	Test 3	Test 4	Test 5	Test 6

Relative Density by	0.9847	0.9488	0.9307	0.9452	0.9585	0.9469
ASTM D4052 (g/mL)
Carbon by ASTM	79.8	82.6	79.4	76.6	76.3	75.7
D5291 (wt %)
Hydrogen by ASTM	9.12	9.43	9.3	9.61	9.48	9.63
D5291 (wt %)
Oxygen by ASTM	not	not	not	13	14.6	13.9
UOP649 (wt %)	measured	measured	measured
Oxygen by	10.93	7.84	11.06	13.79	14.22	14.67
Difference, ASTM
D5291 (wt %)
Carboxylic Acid	not	not	not	38.1	46.1	50
Number (mg KOH/g)	measured	measured	measured
Phenolic Acid	not	not	not	138.8	156.4	126.8
Number (mg KOH/g)	measured	measured	measured
NMR Spectroscopy
Aldehydes (mol % H)	0 (not	0 (not	0 (not	0.01	0.03	0.01
	detected)	detected)	detected)
Ketones, Aldehydes	1.00	0.38	0.98	2.53	2.92	2.47
(mol % C)
Esters, Carboxylic	0.98	0.56	0.69	1.59	2.14	1.94
Acids (mol % C)
Alcohols, Ethers,	0 (not	0 (not	0 (not	0.6	1.13	1.67
Phenolic Methoxys,	detected)	detected)	detected)
Carbohydrates (mol %
C)
IR Spectroscopy
C—O/C (IR Band Area	0.35	0.24	0.26	0.01	0.44	0.34
Ratio)
C═O/C (IR Band	0.18	0.11	0.11	0 (not	0.4	0.34
Area Ratio)				detected)
OH/C (IR Band Area	1.00	0.67	0.61	0 (not	0.94	0.72
Ratio)				detected)
O/C (IR Band Area	0.52	0.35	0.37	0.01	0.85	0.69
Ratio)

Example 2—Pilot Plant Continuous Bio-Oil Upgrading

Another experiment was conducted in a 2 L stirred tank reactor pilot plant. The pilot plant was operated continuously to upgrade bio-oil for the test shown below. The oxide form of a hydrotreating catalyst powder was sieved to less than about 100 micron particle size. A feed tank was filled with a bio-oil stream, a sulfiding compound like tertiary butyl polysulfide, and the sieved catalyst powder. That solution was mixed and recirculated and then fed to the reactor along with a liquid stream containing the recycled catalyst in oil as well as streams of hydrogen gas and hydrogen sulfide gas. The catalyst was sulfided in-situ. After reaction, the products were processed in a hot separator, a cold separator, and an oil-water separator to produce a light oil stream, a heavy oil product stream, and an aqueous byproduct stream. The heavy oil stream, which contained the catalyst, was sampled and a portion was subsequently recycled back with the feed to the reactor. The operating conditions and other parameters of the bio-oil upgrading process are displayed in Table 4 below:

TABLE 4
TEST 1

	T (° C.)	371
	P (psig)	1300
	LHSV Fresh feed (hr−1)	0.13
	Gas:Oil Fresh feed (scfb)	16500
	Catalyst in Feed (ppmw)	500
	Mass Flow Fresh Feed (g/hr)	300
	Recycle Oil Flow Rate (g/hr)	75
	Flow Rate Light Oil (g/hr)	89.3
	Flow Rate Heavy Oil (g/hr)	27.4
	Flow Rate Aqueous (g/hr)	159.7
	Catalyst Compound	Unsupported
		NiWMoS
	Sulfiding Compound	TBPS, H2S

The product streams were analyzed for the experiment, and the analytical results of the analysis are as below in Table 5.

TABLE 5
Test 1

	Heavy Oil	Light Oil

	Relative Density by	0.9989	0.896
	ASTM D4052 (g/mL)
	Carbon by ASTM	83.6	72.9
	D5291 (wt %)
	Hydrogen by ASTM	9.08	10.1
	D5291 (wt %)
	Oxygen by ASTM	6.36	11.8
	UOP649 (wt %)
	Oxygen by Difference,	6.3	16.7
	ASTM D5291 (wt %)
	Carboxylic Acid	9.1	51.1
	Number (mg KOH/g)
	Phenolic Acid Number	112.6	86
	(mg KOH/g)

NMR Spectroscopy

	Aldehydes (mol % H)	0.07	0.05
	Ketones, Aldehydes	0 (not	0 (not
	(mol % C)	detected)	detected)
	Esters, Carboxylic	0 (not	0.23
	Acids (mol % C)	detected)
	Alcohols, Ethers,	3.43	7.53
	Phenolic Methoxys,
	Carbohydrates (mol %
	C)

IR Spectroscopy

	C—O/C (IR Band Area	0.09	0.30
	Ratio)
	C═O/C (IR Band Area	0.04	0.31
	Ratio)
	OH/C (IR Band Area	0.28	0.71
	Ratio)
	O/C (IR Band Area	0.13	0.60
	Ratio)

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 present disclosure is a process for upgrading a bio-oil stream comprising reacting a bio-oil stream with hydrogen in the presence of hydrotreating catalyst fines comprising a metal from Group IVB, Group VB, Group VIB, Group VIIB, or Group VIII on an inorganic support in a reactor to produce an upgraded bio-oil stream, wherein the hydrotreating catalyst fines have D90 particle size of about 1000 microns; and separating the spent hydrotreating catalyst from the upgraded bio-oil stream. An embodiment of the present disclosure is one, any, or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrotreating catalyst is a spent hydrotreating catalyst. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrotreating catalyst is a sulfided hydrotreating catalyst. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrotreating catalyst fines have D90 particle size of about 900 microns. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the concentration of the metal is in the range of about 0.01 to about 7.0 wt % of a reaction mixture in the reactor. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the spent hydrotreating catalyst comprises about 5 wt % to about 25 wt % carbon. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising taking a recycle stream comprising the catalyst from the upgraded bio-oil stream; and charging the recycle stream to the bio-oil reactor. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising passing the upgraded bio-oil stream to a hot separator; and separating a hot bottoms stream from the upgraded bio-oil stream in the hot separator to provide a hot overhead stream comprising a light upgraded bio-oil stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising passing the hot overhead stream to a cold separator to separate gaseous components and provide a bottoms light oil stream; and separating water from the bottoms light oil stream to produce the light upgraded bio-oil stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising separating catalyst stream from the hot bottoms stream to provide a heavy oil stream comprising the catalyst; and recycling the heavy oil stream to the reactor. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising passing the hot bottoms stream to a filtration vessel to separate catalyst and provide a heavy oil product stream, the filtration vessel comprising a vacuum distillation column, a wiped film evaporator, a centrifuge, an electrostatic precipitator, or a combination thereof. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph, wherein the hydrotreating catalyst hydrodeoxygenates oxygenates in the bio-oil stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the first embodiment in this paragraph further comprising charging a non-bio derived stream to the reactor.

A second embodiment of the present disclosure is a process for upgrading a bio-oil stream comprising reacting a bio-oil stream with hydrogen in the presence of a spent hydrotreating catalyst fines comprising a metal from Group IVB, Group VB, Group VIB, Group VIIB, or Group VIII on an inorganic support in a reactor to produce an upgraded bio-oil stream, wherein the hydrotreating catalyst fines have D90 particle size of about 1000 microns in the reactor; and separating the spent hydrotreating catalyst from the upgraded bio-oil stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the spent hydrotreating catalyst comprise about 5 wt % to about 25 wt % carbon. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein a concentration of the metal is in the range of about 0.01 to about 7.0 wt % of a reaction mixture in the reactor. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the second embodiment in this paragraph, wherein the hydrotreating catalyst is a sulfided hydrotreating catalyst.

A third embodiment of the present disclosure is a process for upgrading a bio-oil stream comprising reacting a bio-oil stream with hydrogen in the presence of spent hydrotreating catalyst fines comprising a metal from Group IVB, Group VB, Group VIB, Group VIIB, or Group VIII on an inorganic oxide support in a reactor to produce an upgraded bio-oil stream, wherein the reactor is operated at a temperature of about 300° C. (572° F.) to about 500° C.; and separating the spent hydrotreating catalyst from the upgraded bio-oil stream. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the hydrotreating catalyst is a sulfided hydrotreating catalyst. An embodiment of the present disclosure is one, any or all of prior embodiments in this paragraph up through the third embodiment in this paragraph, wherein the spent hydrotreating catalyst fines have D90 particle size of about 900 microns.

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.