SLURRY HYDROCRACKING PROCESS WITH BIOGENIC FEED

Description

FIELD

The field is related to a slurry hydrocracking process. Particularly, the field relates to a biogenic feedstock in a slurry hydrocracking process.

BACKGROUND

Hydroprocessing includes processes which convert hydrocarbons in the presence of hydroprocessing catalyst and hydrogen to more valuable products.

Hydrotreating is a hydroprocessing process used to remove heteroatoms such as sulfur and nitrogen from hydrocarbon streams to meet fuel specifications and to saturate olefinic compounds. Hydrotreating can be performed at high or low pressures but is typically operated at lower pressure than hydrocracking.

Hydrocracking is a hydroprocessing process in which hydrocarbons crack in the presence of hydrogen and hydrocracking catalyst to lower molecular weight hydrocarbons. Depending on the desired output, a hydrocracking unit may contain one or more beds of the same or different catalyst.

Slurry hydrocracking is a slurried catalytic process used to crack residue feeds to gas oils and fuels. Slurry hydrocracking is used for the primary upgrading of heavy hydrocarbon feedstocks obtained from the distillation of crude oil, including hydrocarbon residues or gas oils from atmospheric column or vacuum column distillation. In slurry hydrocracking, these liquid feedstocks are mixed with hydrogen and solid catalyst particles, e.g., as a particulate metallic compound such as a metal sulfide, to provide a slurry phase. Slurry hydrocracked effluent exits the slurry hydrocracking reactor at very high temperatures around 400 to 500° C. (752 to 932° F.).

Slurry hydrocracking is particularly useful to hydrocrack heavy-residue boiling point fraction of a fossil-based feedstock. In a fossil fuel fed refinery, a heavy-residue boiling point fraction can be virgin distilled resid fraction or a heavy resid through after a cracking or solvent-deasphalting processing.

A petroleum crude oil is typically distilled first at a refiner to obtain non-distillable bottom fractions, i.e., an atmospheric tower bottom and/or a vacuum tower bottom. The bottom fraction or often referred to as resid feed fraction exhibits boiling points above 343° C. (650° F.) or 525° C. (975° F.), respectively. Heavy residue fractions may also be from fluid catalyst cracking (FCC), for example, heavy cycle oil (HCO) or solvent deasphaltene, for example, a pitch stream after de-asphalted oil is separated. Slurry hydrocracking is one of the existing refining technologies that can upgrade and convert the heavy resid or high-boiling point bottom feedstock to lighter boiling products.

Hydroprocessing recovery units typically include a stripper for stripping hydroprocessed effluent with a stripping medium such as steam to remove unwanted hydrogen sulfide. The stripped effluent then is heated in a fired heater to fractionation temperature before entering a product fractionation column to separate and recover products such as naphtha, kerosene and diesel.

Biomass refining or biorefining is becoming more prevalent in industry. Cellulose fibers and sugars, hemicellulose sugars, lignin, syngas, and derivatives of these intermediates are being used by many stakeholders for chemical and fuel production. They are capable of processing incoming biomass much the same as petroleum refineries now process crude oil. Underutilized lignocellulosic biomass feedstocks have the potential to be much cheaper than petroleum, on a carbon basis, as well as much better from an environmental life-cycle standpoint.

Lignocellulosic biomass is the most abundant renewable material on the planet. The lignocellulosic biomass is a potential feedstock for producing chemicals, fuels, and materials. Lignocellulosic biomass normally comprises primarily cellulose, hemicellulose, and lignin. Cellulose and hemicellulose are natural polymers of sugars, and lignin is an aromatic/aliphatic hydrocarbon polymer reinforcing the entire biomass network. Some forms of biomass (e.g., recycled materials) do not contain hemicellulose.

As an alternative source of energy to fossil-based fuel, biomass feedstocks include dedicated energy crops, agricultural crop residues, forestry residues, algae, wood processing residues, municipal waste, and wet waste (crop wastes, forest residues, purpose-grown grasses, woody energy crops, algae, industrial wastes, sorted municipal solid waste [MSW], urban wood waste, and food waste. Here biomass feedstocks may refer to agricultural crop residues, forestry residues, algae, soft or hard wood that is commonly fed to pyrolysis process to obtain pyrolysis oil.

It is beneficial to process biomass in a way that effectively separates the major fractions (cellulose, hemicellulose, and lignin) from each other. Cellulose from biomass can be used in industrial cellulose applications directly, such as to make paper or other pulp-derived products. The cellulose can also be subjected to further processing to either modify the cellulose in some way or convert it into glucose. Hemicellulose sugars can be fermented to a variety of products, such as ethanol, or converted to other chemicals. Lignin from biomass has value as a solid fuel and also as an energy feedstock to produce liquid fuels, synthesis gas, or hydrogen; and as an intermediate to make a variety of polymeric compounds. Additionally, minor components such as proteins or rare sugars can be extracted and purified for specialty applications.

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.

There is a continuing need, therefore, for improved methods of producing fuel products from bio-oil.

SUMMARY

A slurry hydrocracking process is disclosed. The process comprises charging a catalyst, a bio-oil stream, a recycle stream, and a hydrogen stream to a slurry hydrocracking reactor. The bio-oil stream, and the recycle stream are hydrocracked in the presence of the catalyst and the hydrogen stream to produce a slurry hydrocracked effluent stream. A recycle stream is taken from the hydrocracked effluent stream. The bio-oil stream is added to the recycle stream which is charged into the slurry hydrocracking reactor. The present disclosure provides a process to upgrade a bio-oil stream in a slurry hydrocracking reactor. The process of upgrading the bio-oil stream mitigates the fouling issue of bio-oil handling.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGURE illustrates a schematic diagram of a slurry hydrocracking process accordance with an embodiment of the present disclosure.

DEFINITIONS

As used herein, the term “bypass” with respect to a vessel or zone means that a stream does not pass through the zone or vessel bypassed although it may pass through a vessel or zone that is not designated as bypassed.

As used herein, the term “communication” means that material flow is operatively permitted between enumerated components.

As used herein, the term “downstream communication” means that at least a portion of material flowing to the subject in downstream communication may operatively flow from the object with which it communicates.

As used herein, the term “upstream communication” means that at least a portion of the material flowing from the subject in upstream communication may operatively flow to the object with which it communicates.

As used herein, the term “direct communication” means that flow from the upstream component enters the downstream component without undergoing a compositional change due to physical fractionation or chemical conversion.

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 “separator” means a vessel which has an inlet and at least an overhead vapor outlet and a bottoms liquid outlet and may also have an aqueous stream outlet from a boot. A flash drum is a type of separator which may be in downstream communication with a separator that may be operated at higher pressure.

As used herein, the term “column” means a distillation column or columns for separating one or more components of different volatilities. Unless otherwise indicated, each column includes a condenser on an overhead of the column to condense and reflux a portion of an overhead stream back to the top of the column and a reboiler at a bottom of the column to vaporize and send a portion of a bottoms stream back to the bottom of the column. Feeds to the columns may be preheated. The top pressure is the pressure of the overhead vapor at the vapor outlet of the column. The bottom temperature is the liquid bottom outlet temperature. Overhead lines and bottoms lines refer to the net lines from the column downstream of any reflux or reboil to the column. Stripper columns omit a reboiler at a bottom of the column and instead provide heating requirements and separation impetus from a fluidized inert media such as steam. Fractionation columns operate at close to atmospheric pressure for an atmospheric column or vacuum pressure for a vacuum column. Fractionation columns boil off elevated temperatures in reboilers and vapor and liquid equilibrates at packing and tray system when travels in the column, mass transfer devices. Complex pump-around, heating and cooling devices are applied to achieve separation efficiencies needed for product draw streams. A variety of product streams can be obtained with boiling point fractions mentioned in text below.

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, “fossil-based feed” “fossil-derived feed” “fossil feed” or “fossil feedstock” or “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. Fossil feed also includes coal or shale-oil based fuel derivatives.

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 “Boiling Point” (TBP) may also refer to other analytical techniques other than “True Boiling Point” (TBP)”. Such as simulated distillation or ASTM distillation. Commonly used simulated distillation techniques are ASTM D 2887, 7169. Commonly used simulated ASTM distillation standard are D86, D1160. They are inter-correlated.

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, D-1160, TBP, or Simulated distillation methods D 2887, D 7169.

As used herein, the term “diesel boiling range” means hydrocarbons boiling in the range of between about 1320 and about 399° C. (270° to 750° F.) by any standard gas chromatographic simulated distillation method such as ASTM D2887, D6352 or D7169, all of which are used by the petroleum industry.

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, “heavy vacuum gas oil” means the hydrocarbon material having a T5 between about 300° C. (572° F.) and about 450° C. (842° F.) and a T95 between about 510° C. (950° F.) and about 570° C. (1058° F.), or an EP of no more than about 626° C. (1158° F.) prepared by vacuum fractionation of atmospheric as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, D6352 or D7169, all of which are used by the petroleum industry.

As used herein, the term “pitch” means the hydrocarbon material boiling above about 524° C. (975° F.) atmospheric equivalent boiling point, or AEBP as determined by any standard gas chromatographic simulated distillation method such as ASTM D2887, D6352 or D7169, all of which are used by the petroleum industry.

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 the stream.

As used herein, the terms “C_x” are to be understood to refer to molecules having the number of carbon atoms represented by the subscript “x”. Similarly, the term “C_x−” refers to molecules that contain less than or equal to x and preferably x and less carbon atoms. The term “C_x+” refers to molecules with more than or equal to x and preferably x and more carbon atoms.

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

The present disclosure provides a slurry hydrocracking process. The slurry hydrocracking process may be used to upgrade a biomass-based feed such as bio-oil in the presence of a catalyst to produce one or more fuel.

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, packing wastes (paper/card board), 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 may 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 bio-oil stream can be 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 of animal fat and of 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.

Referring to the FIGURE, a slurry hydrocracking process 101 is disclosed. The process 101 comprises a hydroprocessing section 10, a separation section 20, and a fractionation section 100. The hydroprocessing section 10 may include a hydroprocessing reactor 12, a recycle gas scrubber 90, and a recycle gas compressor 95. In an embodiment, the hydroprocessing reactor 12 comprises a slurry hydrocracking reactor.

Generally, the slurry hydrocracking reactor 12 for a fossil-based fuel can operate at any suitable conditions, such as a temperature of about 400° C. (752° F.) to about 500° C. (932° F.) and a pressure of about 3 MPa to about 24 MPa. Exemplary slurry hydrocracking reactors are disclosed in, e.g., U.S. Pat. Nos. 5,755,955; 5,474,977; US 2009/0127161; US 2010/0248946; US 2011/0306490; and US 2011/0303580. Often, slurry hydrocracking is carried out using reactor conditions sufficient to crack at least a portion of a hydrocarbon feed stream in line 102 to lower boiling products, such as one or more distillate hydrocarbons, naphtha, and/or C₁-C₄ products. The hydrocarbon feed stream in line 102 may comprise hydrocarbons boiling from about 340° C. (644° F.) to about 570° C. (1058° F.). In an aspect, the hydrocarbon feed stream in line 102 is a fossil hydrocarbon feed stream. The fossil hydrocarbon feed stream in line 102 may include one or more of a crude oil atmospheric distillation column residuum boiling above about 340° C. (644° F.), a crude oil vacuum distillation column residuum boiling above about 560° C. (1044° F.), tars, a bitumen, coal oils, and shale oils. In an exemplary embodiment, the fossil hydrocarbon feed stream in line 102 is selected from at least one of an atmospheric column bottom stream, a vacuum tower bottom stream, heavy cycle oil, light cycle oil, and deasphalted oil.

The fossil hydrocarbon feed stream 102 may be heated in a heater 237 to provide a heated fossil hydrocarbon feed stream in line 104. A catalyst may be combined with the fossil hydrocarbon feed stream in line 102 or in line 104. A portion of hydrogen stream in line 98 may be added into fossil hydrocarbon feed stream in line 104 to provide a mixed fossil hydrocarbon feed stream comprising a soaked gas before entering the heater 237.

In an embodiment, the catalyst may be taken from a catalyst preparation unit 230. A catalyst precursor in line 228 may be introduced into the catalyst preparation unit 230 where it may be mixed with a heavy hydrocarbon liquid stream in line 223. The resultant catalyst mixture may be dried if it contains water. A sulfiding agent may be added to the catalyst into the catalyst in the catalyst preparation unit 230 at some point before pre-activation if sufficient sulfur is not present in the heavy hydrocarbon liquid stream in line 223. Pre-activation is effected by heating the catalyst mixture to an elevated temperature. If pre-activation is conducted in the presence of sufficient sulfur, activation and pre-activation occur together. The catalyst may be preferably pre-formed and activated before entering the slurry hydrocracking reactor 12. The term “sulfur” includes any compound comprising sulfur including elemental sulfur. A catalyst containing stream may be discharged in line 232 from the catalyst preparation unit 230. The catalyst containing stream in line 232 is a fresh catalyst containing stream. In an aspect, the catalyst containing stream in line 232 is a catalyst precursor concentrate.

The heavy hydrocarbon liquid stream in line 223 from a fossil feed should be highly asphaltenic and comprise a highly dealkylated liquid to ensure dispersion of asphaltenes in the hydrocarbon liquid stream in line 223. The heavy hydrocarbon liquid stream in line 223 may comprise no more than 11.3 wt %, suitably no more than 11.2 wt % and preferably no more than 11.1 wt % hydrogen. The heavy hydrocarbon liquid stream in line 223 may have at least 7 wt %, suitably at least 8 wt % and preferably at least 9 wt % hydrogen. Hydrogen concentration may be determined by nuclear magnetic resonance. The heavy hydrocarbon liquid stream in line 223 should have sufficient asphaltenes to support the catalytic metal. Sufficient asphaltenes are quantified by at least 3 wt % microcarbon residue, suitably at least 3.1 wt % microcarbon residue, more suitably at least 4 wt % microcarbon residue and preferably at least 7 wt % microcarbon residue using ASTM D4530-15. The heavy hydrocarbon liquid stream in line 223 may have no more than 50 wt % and suitably no more than 30 wt % microcarbon residue. The heavy hydrocarbon liquid stream in line 223 may have a density of at least about 0.90 g/cc and suitably at least about 0.98 g/cc. A sulfur content of about 0.5 to about 2 wt % may be supplied to provide sufficient sulfiding agent to enable activation upon heating to an elevated temperature.

In an embodiment, an asphaltenic liquid may be mixed with a dealkylated aromatic liquid to provide the heavy hydrocarbon liquid stream in line 223 for producing a catalyst concentrate in the catalyst preparation unit 230. The dealkylated aromatic liquid should be suitable for dispersing asphaltenes molecules to permit the metal component to bond onto a condensed asphaltene molecule. A suitable dealkylated aromatic liquid may comprise no more than about 11 wt % hydrogen. Additionally, a suitable dealkylated aromatic liquid may have a density of at least about 0.94 g/cc and preferably at least about 0.95 g/cc. Moreover, a suitable dealkylated aromatic liquid may have a solubility blending number of at least 60. The dealkylated aromatic liquid should have at least 30 wt % aromatics, preferably at least 35 wt % aromatics and suitably at least about 20 wt % polyaromatics and preferably at least about 24 wt % polyaromatics. Greater polarity of the dealkylated aromatic compounds enables better solubility, so a nitrogen content of at least 0.15 wt % nitrogen and preferably at least about 0.2 wt % nitrogen is advantageous with the presumption that much of the nitrogen is incorporated into aromatic compounds.

In an embodiment, the catalyst in the catalyst containing stream in line 232 may comprise at least one metal selected from group VI and group VIII metals. In an aspect, the catalyst may comprise at least one of molybdenum, nickel in a format of oxides precursor or activated sulfides format. Other metal precursors such as vanadium, tungsten and irons may also be supplied as a catalyst precursor.

In an exemplary embodiment, the catalyst in the catalyst containing stream in line 232 may comprise molybdenum. In an exemplary embodiment, the catalyst precursor in line 228 may comprise a molybdenum catalyst precursor.

The heated fossil hydrocarbon feed stream in line 104 may be combined with at least a portion of the catalyst containing stream in line 232 to provide a mixed feed stream in line 234.

In an embodiment, the mixed feed stream in line 234 may comprise an amount of catalyst from about 0.01 wt % to about 10 wt %, preferably from about 0.01 wt % to about 5 wt % of the fossil hydrocarbon feed stream, before being combined with hydrogen, as hereinafter described.

As described later in detail, a recycle stream in line 226 comprising a bio-oil stream may be combined with the mixed feed stream in line 234 to provide a slurry hydrocracking charge stream in line 238. The slurry hydrocracking charge stream in line 238 may be charged to the slurry hydrocracking reactor 12 after all liquid feed and recycle is mixed.

All freshly supplied catalysts are fed through stream 228.

The slurry hydrocracking reactor 12 may be operated at a pressure in the range of about 3.5 MPa (g) (500 psig) to about 24 MPa (g) (3500 psig). The reactor temperature may be in the range of about 400° C. to about 500° C. being preferred. The LHSV is typically below about 4 hr-1 on a fresh feed basis, with a range of about 0.1 to 3 hr⁻¹ being preferred. Although slurry hydrocracking can be carried out in a variety of known reactors of either up or downflow, it is particularly well suited to a tubular reactor through which feed, catalyst and gas move upwardly. Hence, the outlet of the slurry hydrocracking reactor 12 is above the inlet. Although only one slurry hydrocracking reactor 12 is shown in the FIGURE, one or more the slurry hydrocracking reactors 12 may be utilized in parallel or in series with interstage separation of converted product. Because the feed is converted to vaporous product, foaming tends to occur in the slurry hydrocracking reactor 12. An antifoaming agent may also be added to the slurry hydrocracking reactor 12, preferably to the top thereof, to reduce the tendency to generate foam. Suitable antifoaming agents include silicones.

In the slurry hydrocracking reactor 12, the heated charge stream comprising the recycle stream including the bio-oil stream is hydrocracked in the presence of the catalyst and the hydrogen stream to produce a slurry hydrocracked effluent stream. The slurry hydrocracked effluent stream is discharged in line 16 from the slurry hydrocracking reactor 12. The slurry hydrocracked effluent stream in line 16 may comprise a three-phase, gas-liquid-solid mixture. The slurry hydrocracked effluent stream in line 16 may be passed to the separation section 20. Solids in the slurry hydrocracked effluent stream in line 16 are mainly metal sulfides that are converted to sulfides on contact with hydrogen disulfide derived from fossil-based fuel which is typically rich in sulfur. Depending on catalyst precursors supplied in catalyst preparation unit 230, metal sulfides may comprise sulfides of molybdenum, nickel, vanadium, tungsten or irons.

The separation section 20 may comprise a hot separator 30, a warm separator 40, and a cold separator 50 which are all in downstream communication with the slurry hydrocracking reactor 12. The slurry hydrocracked effluent stream in line 16 may be passed into the hot separator 30. A hot liquid effluent stream is discharged in line 34 from the bottom and a hot vapor effluent stream is discharged in line 38 from the overhead of the hot separator 30. The hot separator 30 may be operated at a temperature of about 200 to about 500° C. The hot separator 30 may be operated at a pressure of about the slurry hydrocracking reactor 12 but a little less accounting for pressure drop through the lines.

The hot vapor effluent stream in line 38 from the hot separator 30 can be cooled in a heat exchanger 11 and provided to the warm separator 40. A warm liquid effluent stream is discharged in line 44 from the bottom and a warm vapor effluent stream is discharged in line 48 from the overhead of the warm separator 40. The warm separator 40 may be operated at a temperature of about 170 to about 400° C. The warm separator 40 may be operated at a pressure of about the slurry hydrocracking reactor 12 but a little less accounting for pressure drop through the lines.

The warm vapor effluent stream in line 48 from the warm separator 40 can be cooled in a heat exchanger 13 and provided to the cold separator 40. A cold liquid effluent stream is discharged in line 54 from the bottom and a cold vapor effluent stream is discharged in line 58 from the overhead of the cold separator 50. The cold separator 50 may be operated at a temperature of no more than about 100° C., preferably no more than about 70° C. The cold separator 50 may be operated at a pressure of about the slurry hydrocracking reactor 12 but a little less accounting for pressure drop through the lines.

The hot separator 30, the warm separator 40 and the cold separator 50 may be used to reduce the temperature of the slurry hydrocracked effluent while separating gases from liquids. The hot liquid effluent stream in line 34, the warm liquid effluent stream in line 44, and the cold liquid effluent stream in line 54 may be charged and fractionated in the fractionation section 100.

The hot liquid effluent stream in line 34 may be at a temperature of about 200 to about 500° C. and a pressure of about that of the hot separator 30. The warm liquid effluent stream in line 44 may be at a temperature of about 170 and about 400° C. and a pressure of about that of the warm separator 40. The cold liquid effluent stream in line 54 may be at a temperature of no more than about 100° C. and a pressure of about that the cold separator 30.

The cold vapor effluent stream in line 58 may comprise recoverable hydrogen. In an embodiment, the cold vapor effluent stream in line 58 may be passed to an amine scrubber 90 where it is contacted with a lean amine stream in line 59. A hydrogen rich stream is discharged from an overhead of the amine scrubber in line 92. A spent amine stream is discharged from the bottom of the amine scrubber in line 91. The spent amine stream may be regenerated and recycled back into the amine scrubber in line 59. The hydrogen rich stream in line 92 may be compressed in a recycle gas compressor 95. In an embodiment, the hydrogen rich stream in line 92 may be combined with a make-up hydrogen stream in line 93 to provide a combined hydrogen stream in line 94. The combined hydrogen stream in line 94 may be compressed in the recycle gas compressor 95 to provide a compressed hydrogen stream. A compressed hydrogen stream is discharged in line 96 from the recycle gas compressor 95 which may be recycled to the slurry hydrocracking reactor 12.

In an embodiment, the compressed hydrogen stream in line 96 may be heated in a heater 97 to provide a hydrocracking hydrogen stream in line 99. The hydrocracking hydrogen stream in line 99 may be charged to the slurry hydrocracking reactor 12. In an embodiment, the hydrocracking hydrogen stream in line 99 may be combined with the mixed feed stream in line 234 to provide the slurry hydrocracking charge stream in line 238 and passed to the slurry hydrocracking reactor 12. A portion of the compressed hydrogen stream in line 96 may be taken in line 98 before passing it to the heater 97. The portion of the compressed hydrogen stream in line 197 may be combined with the fossil hydrocarbon feed stream in line 102 and charged to the slurry hydrocracking reactor 12 as previously described.

The separation section 20 may optionally include a hot flash drum 60, a warm flash drum 70 and a cold flash drum 80. The hot flash drum 60 may receive the hot liquid effluent stream in line 34 from the hot separator 30. The hot flash drum 60 flashes the hot liquid effluent stream at a lower pressure than in line 34 to separate a liquid hot flash stream in line 64 from a vaporous hot flash stream in line 68. Water may be separated and collected from the boot of the hot flash drum 60 in line 61. The hot flash drum 60 may be operated at a temperature of about 200 to about 500° C. and a pressure of about 350 to about 6200 kPa.

The warm flash drum 70 may receive the warm liquid effluent stream in line 44 from the warm separator 40. Moreover, the vaporous hot flash stream in line 68 from the hot flash drum 60 can be cooled in a heat exchanger 15 and provided to the warm flash drum 70. In an embodiment, the vaporous hot flash stream in line 68 may be combined with the warm liquid effluent stream in line 44 to provide a mixed warm effluent stream in line 69. The mixed warm effluent stream in line 69 may be passed to the warm flash drum 70. The warm flash drum 70 flashes the vaporous hot flash stream in line 68 and the warm liquid effluent stream in line 44 at lower pressure to separate a liquid warm flash stream in line 74 from a vaporous warm flash stream in line 78. The vaporous warm flash stream in line 78 may be cooled in a heat exchanger 17 and passed to the cold flash drum 80. Water may be separated and collected from the boot of the warm flash drum 70 in line 71. The warm flash drum 70 may be operated at a temperature of about 170 to about 400° C. and a pressure of about 350 to about 6200 kPa.

The cold liquid effluent stream in line 54 from the cold separator 50 may be passed into the cold flash drum 80. Moreover, the vaporous warm flash stream in line 78 from the warm flash drum 70 may be cooled in a heat exchanger 17 and provided to the cold flash drum 80. The cold flash drum 80 flashes the cold liquid effluent stream in line 54 and the vaporous warm flash stream in line 78 to separate a liquid cold flash stream in line 84 from a vaporous cold flash stream comprising normally gaseous hydrocarbons in line 88. The cold flash drum 80 may be operated at a temperature of no more than about 100° C. and a pressure of about 350 to about 6200 kPa.

The hot flash drum 60, the warm flash drum 70 and the cold flash drum 80 are used to reduce the pressure of the slurry hydrocracked effluent stream while separating gases from liquids. It is envisioned that one or all of the flash drums 60, 70, 80 can be dispensed with, so that the separator hydrocracking effluent streams the hot liquid effluent stream in line 34, the warm liquid effluent stream in line 44, and the cold liquid effluent stream in line 54 may be taken directly to the fractionation section 100.

The fractionation section 100 may include a debutanizer column 140, a product fractionation column 170, and a stripper column. In an embodiment, the fractionation section 100 may comprise two separate stripper columns, a cold stripper column 110, a hot stripper column 150. The cold stripper column 110 may strip the cold liquid effluent stream and the hot stripper column 150 may strip the hot liquid effluent stream and the warm liquid effluent stream. The cold stripper column 110 may be in downstream communication with the slurry hydrocracking reactor 12, the cold separator 50 and/or the cold flash drum 80 for stripping the relatively cold liquid effluent stream in line 54 which is a portion of the slurry hydrocracking effluent stream. The hot stripper column 150 may be in downstream communication with the slurry hydrocracking reactor 12, the hot separator 30 and/or the hot flash drum 60 for stripping the relatively hot liquid effluent stream in line 34 which is also a portion of the slurry hydrocracking effluent stream. In the embodiment of FIGURE, the hot stripper column 150 may be in downstream communication with the warm separator 40 and/or the warm flash drum 70 for stripping the relatively warm liquid effluent stream which is also a portion of the slurry hydrocracking effluent stream.

In the embodiment as shown in FIGURE, the liquid cold flash stream in line 84 may be fed to the cold stripper column 110 near the top of the column. The liquid cold flash stream in line 84 may be stripped in the cold stripper column 110 with a cold stripping media which is an inert gas such as steam from a cold stripping media line 114 to provide a cold vapor stream of LPG, naphtha, hydrogen, hydrogen sulfide, steam and other gases in an overhead line 116. At least a portion of the cold vapor stream may be condensed and separated in a receiver 118. A net overhead line 122 from the receiver 118 carries vaporous off gas perhaps for further treating. A condensed cold overhead stream comprising unstabilized liquid naphtha from the bottoms of the receiver 118 in a condensed line 120 may be split between a reflux stream in line 124 refluxed to the top of the cold stripper column 110 and a net condensed cold overhead stream which may be transported in condensed cold overhead line 126 to further fractionation such as in the debutanizer 140. The cold stripped stream in cold stripped line 112 recovered from a bottom of the cold stripper column 110 comprises diesel that boils in the diesel boiling range and can be used as diesel blending stock without further fractionation. The cold stripper column 110 may be operated with a bottom temperature of about 149° C. (300° F.) to about 260° C. (500° F.) and an overhead pressure of about 0.5 MPa (gauge) (73 psig) to about 2.0 MPa (gauge) (290 psig). The temperature in the overhead receiver 118 may range from about 38° C. (100° F.) to about 66° C. (150° F.) and the pressure is essentially the same as in the overhead of the cold stripper column 110.

The unstabilized naphtha in condensed cold overhead line 126 may be fed to the debutanizer column 140 which is in downstream communication with the slurry hydrocracking reactor 12 and the cold stripper column 110. The debutanizer column fractionates the unstabilized naphtha in an overhead stream in line 142, which is cooled and passed to an overhead receiver 119 to provide a net off-gas stream in line 143 and an overhead liquid stream in line 144. A reflux stream is taken in line 145 from the overhead liquid stream in line 144 and passed to the debutanizer column 140. A net LPG stream comprising predominantly C4-hydrocarbons is taken in line 146. A bottoms stream in line 141 is taken from the bottom of the debutanizer column 140. A reboil stream in line 147 is taken from the bottoms stream and heated in the reboiler 149 to provide a reboiled stream in line 151 which is recycled to the debutanizer column 140. A naphtha stream comprising predominantly C5+ hydrocarbons may be discharged in bottoms line 148 of the debutanizer column 140. The debutanizer column may be operated at a top pressure of about 1034 kPa (150 psig) to about 2758 kPa (gauge) (400 psig) and a bottom temperature of about 149° C. (300° F.) to about 260° C. (500° F.). The pressure should be maintained as low as possible to maintain reboiler temperature as low as possible while still allowing complete condensation with typical cooling utilities without the need for refrigeration.

In the embodiment as shown in FIGURE, the liquid hot flash stream in line 64 may be fed to the hot stripper column 150. The liquid warm flash stream in line 74 may be fed to the hot stripper column 150 near the top thereof and at a location above the feed inlet for the hot flash stream in line. The liquid hot flash stream in line 64 and the liquid warm flash stream in line 74 may both be stripped in the hot stripper column 150 with a hot stripping media which is an inert gas such as steam from line 152 to provide a hot vapor stream of diesel, naphtha, hydrogen, hydrogen sulfide, steam and other gases in an overhead line 154. At least a portion of the hot vapor stream may be condensed and separated in a receiver. However, in an aspect, the hot stripper overhead stream in overhead line 154 may be fed directly to the cold stripper column 110 with an inlet location below the inlet location of the cold liquid effluent stream in line 54. The hot stripper column 150 may be operated with a bottom temperature of about 160° C. (320° F.) and about 371° C. (700° F.) and an overhead pressure of about 0.5 MPa (gauge) (73 psig) to about 2.0 MPa (gauge) (292 psig).

A hot stripped stream may be taken from the hot stripper column 150 in a hot stripped line 158. At least a portion of the hot stripped stream in hot stripped line 158 may be fed to the product fractionation column 170 which may be a vacuum column for fractionation therein. In an aspect, the product fractionation column 170 may be in downstream communication with the hot stripped line 158 of the hot stripper column 150.

The hot stripped stream in the hot stripped line 158 may be heated in a fired heater 130 before it enters the product fractionation column 170. A heated hot stripped stream in line 159 may be fed to the product fractionation column 170. The product fractionation column 170 may strip the heated hot stripped stream in line 158 with stripping media such as steam from line 172 to provide several product streams. The product streams may include a light diesel stream in overhead line 188, a heavy diesel stream in line 212 from a side cut outlet, a light vacuum gas oil (LVGO) stream in line 214 from a side cut outlet, a heavy vacuum gas oil (HVGO) stream in line 216 from a side cut outlet and a slop wax stream in line 178 from a side cut outlet and a bottoms pitch stream in line 181. Heat may be removed from the product fractionation column 170 by cooling the diesel stream in line 212, the LVGO stream in line 214 and the HVGO stream in line 216 and sending a portion of each cooled stream back to the column. A portion of the heavy diesel stream in line 175 may be taken in line 211, which is cooled and returned back to the fractionation column 170. A heavy diesel product stream may be taken in line 213 from the fractionation column 170. A portion of the LVGO stream in line 176 may be taken in line 213, which is cooled and returned back to the fractionation column 170. A LVGO product stream may be taken in line 214 from the fractionation column 170. A portion of the HVGO stream in line 177 may be taken in line 215, which is cooled and returned back to the fractionation column 170. A HVGO product stream may be taken in line 216 from the fractionation column 170.

In an aspect, the product fractionation column 170 may be operated as a vacuum column. As such, the overhead light diesel stream in line 188 may be pulled from the product fractionation column 170 through a vacuum system 186 on an overhead line 182 of the product fractionation column 170. The vacuum system may include an eductor for generating a vacuum when a steam stream or other inert gas stream in line 184 is fed through the eductor. The product fractionation column 170 is maintained at a pressure of about 0.1 (1 torr(a)), and 6.7 kPa(a) (50 torr(a)), preferably between about 0.2 kPa(a) (1.5 torr(a)) and 2.0 kPa(a) (15 torr(a)) and at a vacuum distillation temperature of about 300° C. (572° F.) to about 400° C. (752° F.) resulting in an atmospheric equivalent cut point between HVGO and pitch of between about 454° C. (850° F.) and 593° C. (1100° F.), preferably between about 482° C. (900° F.) and 579° C. (1075° F.).

In the embodiment as shown in FIGURE, the cold stripper bottom stream in cold stripped line 112 may be recovered directly as a diesel blending stock.

In accordance with the present disclosure, a recycle stream for recycling to the slurry hydrocracking reactor 12 may be taken from at least one of the HVGO stream in line 216 and the pitch stream in line 181. The pitch stream in line 181 comprises the concentrated catalyst with unconverted hydrocarbon feed stream. In an aspect, the concentrated catalyst in the pitch stream may comprise metal sulfides from the reactor 12. A portion of the pitch stream in line 181 may be taken in a recycle pitch stream in line 222. The recycle pitch stream in line 222 may be recycled to the slurry hydrocracking reactor 12. The recycle pitch stream in line 222 may comprise recovered concentrated catalyst from the fractionation column 170. A net pitch stream may be discharged in line 221. A portion of the HVGO stream in line 216 may be taken in a recycle HVGO stream in line 218. The recycle HVGO stream in line 218 may be recycled to the slurry hydrocracking reactor 12. A net HVGO stream may be discharged in line 217. The net pitch stream discharge in 221 and the net HVGO discharged in line 217 may be about 1-30% mass ratio to a combined mass feed of the fresh feed in line 102 and the bio-oil stream in line 225.

In an exemplary embodiment as shown in FIGURE, the recycle pitch stream in line 222 may be combined with the recycle HVGO stream in line 218 to provide a combined recycle stream in line 224 for recycling to the slurry hydrocracking reactor 12. In a preferred embodiment, the combined recycle stream in line 224 is the recycle pitch stream in line 222.

The metal sulfides catalysts in recycle stream 224 may be in mass concentration of about 10 ppm to about 40000 ppm if catalyst precursor is molybdenum in the combined recycle stream 224.

In accordance with the present disclosure, a bio-oil stream may be processed in the slurry hydrocracking reactor. Feeding the bio-oil stream directly into the slurry hydrocracking reactor 12 may cause problems such as fouling and plugging. Further, a dedicated bio-oil upgrading in the slurry hydrocracking reactor 12 may be subject to issues related to building dedicated catalyst system and supply expensive hydrogen. The present process 101 addresses these issues by providing a solution to bio-oil upgrading in the slurry hydrocracking reactor 12. Applicants found that a bio-oil stream in line 225 can be charged into the slurry hydrocracking reactor 12 with the recycle stream from the fractionation section instead of a direct feeding into the reactor 12. Further, the bio-oil stream in line 225 can be processed in the slurry hydrocracking reactor 12 with the fossil hydrocarbon feed stream in line 102. The optimum location of the bio-oil stream addition into the process mitigates the issues of fouling and provides significant economic benefits as compared to a dedicated bio-oil slurry hydrocracking reactor 12. The recycle stream from the fractionation section is a warm recycle stream and adding the bio-oil stream in line 225 into the warm stream would prevent the fouling issue of bio-oil. By using the present process, no high temperature limitation will be required for bio-oil stream in line 225 or the recycle stream in line 224 or in line 226 as long as thermal cracking temperature can be avoided, or stream temperature of either of the recycle stream in line 224 and in line 226 can be from about 90° C. to about 300° C.

In an embodiment, the bio-oil stream in line 225 may be produced from a lignocellulosic biomass.

In an aspect, the bio-oil stream in line 225 may be added into the combined recycle stream in line 224 to produce a mixed recycle stream in line 226. The bio-oil stream in line 225 may be added directly into the combined recycle stream in line 224. The bio-oil stream in line 225 may be in direct communication with the recycle line 224. The mixed recycle stream in line 226 was recycled to the slurry hydrocracking reactor 12. The mixed recycle stream in line 226 may be combined with the mixed feed stream in line 234 to provide the slurry hydrocracking charge stream in line 238. The slurry hydrocracking charge stream in line 238 is charged to the slurry hydrocracking reactor 12 and processed as earlier described.

The metal sulfides catalysts in the combined recycle stream in line 224 may be in mass ratio to the bio-oil stream in mass concentration of about 50 ppm to about 20000 ppm if catalyst precursor in line 228 is molybdenum.

The bio-oil stream in line 225 may be in 1:40% of mass ratio relative to fossil hydrocarbon feed stream in line 102. The fresh catalyst addition in line 228 may be adjusted so that metal sulfides catalysts in the combined recycle stream in line 224 may be in mass ratio to the bio-oil stream in line 225 of about 50 ppm to about 20000 ppm.

In an alternate embodiment, the recycle HVGO stream in line 218 may be optionally used and combined with the bio-oil stream in line 225. In such an embodiment, the recycle pitch stream in line 222 may be recycled with the bio-oil stream in line 225 to the slurry hydrocracking reactor 12. The bio-oil stream in line 225 may be directly added into the recycle pitch stream in line 222 to provide the mixed recycle stream in line 226. The mixed recycle stream in line 226 may be combined with the mixed feed stream in line 234 to provide the slurry hydrocracking charge stream in line 238.

EXAMPLE

A bio-oil stream was charged to a slurry hydrocracking reactor. The bio-oil feed comprised 7-10 wt % hydrogen and 50 wt % oxygen. A molybdenum catalyst was mixed with a vacuum residue stream to provide a catalyst stream. The bio-oil stream was combined with the catalyst stream to produce the slurry hydrocracking charge stream. The slurry hydrocracking charge stream was charged into the slurry hydrocracking reactor. The slurry hydrocracking reactor was operated at a pressure of 2000 psig, a temperature of 690° F. to 710° F., and LHSV of 0.5 to 2 hr¹. A total of ere run. The results are in the Table below.

	TABLE
	Component	Test 1	Test 2	Test 3

	H2 (wt %)	−4.3	−4.6	−4.5
	C1-C4 (wt %)	13.0	12.3	11.9
	H2O (wt %)	31.2	31.7	31.3
	CO2 (wt %)	9.9	9.5	9.4
	CO (wt %)	0.0	0.0	0.0
	C5+ to 300° F. (wt %)	10.1	10.2	10.2
	300-550° F. (wt %)	12.9	13.2	13.6
	550-716° F. (wt %)	10.0	10.2	10.4
	975° F. + (wt %)	6.9	6.8	7.0
	Sum	100.0	100.0	100.0

During the tests, the net hydrocracked effluent stream was collected over testing duration. The products were collected in two broad boiling point fractions. One fraction had C5 and up to ˜716° F. boiling hydrocarbons, and a second fraction had a heavier boiling point >716° F. The first cut was namely a light cut and the second cut was a heavy cut. The light cut had 7-8 wt % oxygen and the heavy cut had 5-6 wt % oxygen. Both the light cut and the heavy cut were upgraded to a higher hydrogen content than the bio-oil stream. The light cut and the heavy cut both had an oxygen content of 11-13 wt % hydrogen as compared to 7-10 wt % hydrogen in the bio-oil.

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 slurry hydrocracking process, comprising charging a catalyst, a bio-oil stream, a recycle stream, and a hydrogen stream to a slurry hydrocracking reactor; hydrocracking the bio-oil stream in the presence of the catalyst and the hydrogen stream to produce a slurry hydrocracked effluent stream; taking a recycle stream from the hydrocracked effluent stream; and adding the bio-oil stream to the recycle 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 bio-oil stream is added directly into the recycle 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 the slurry hydrocracked effluent stream into a vapor hydrocracked effluent stream and a liquid hydrocracked effluent stream; and fractionating the liquid hydrocracked effluent stream to provide a vacuum gas oil stream and a pitch 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 recycle stream is taken from at least one of the vacuum gas oil stream and the pitch 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 fossil hydrocarbon feed stream into the slurry hydrocracking reactor, wherein an amount of the bio-oil stream is about 1 wt % to about 40 wt % of the hydrocarbon feed 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 bio-oil stream is produced from a lignocellulosic biomass. 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 recycle stream comprises a recovered concentrated catalyst and the catalyst charged into the reactor comprises a fresh 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 bio-oil stream and the recycle stream are combined in an mass ratio of active metal in the recycle stream to the bio-oil stream of about 50 ppm to about 20000 ppm. 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 combining the recycle stream, and the bio-oil stream to provide a mixed recycle stream; and combining mixed recycle stream with the fossil hydrocarbon feed stream, and the catalyst to provide the slurry hydrocracking charge 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 combining the fossil hydrocarbon feed stream and a fresh catalyst to provide a mixed feed stream; and combining the mixed feed stream and the mixed recycle stream to provide the slurry hydrocracking charge 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 slurry hydrocracking charge stream comprises an amount of catalyst from about 0.01 wt % to about 5 wt % of the fossil hydrocarbon feed 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 heating the mixed feed stream to provide a heated mixed feed stream; and combining the heated mixed feed stream and the mixed recycle stream to provide the slurry hydrocracking charge 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 catalyst comprises at least one metal from group VI and group VIII metals. 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 fossil hydrocarbon feed stream is selected from at least one of an atmospheric column bottom stream, a vacuum tower bottom stream, heavy cycle oil, light cycle oil, and deasphalted oil.

A second embodiment of the present disclosure is a slurry hydrocracking process, comprising charging a hydrogen stream, a fossil feed and a recycle stream a slurry hydrocracking reactor, wherein the recycle stream comprises a recovered concentrated catalyst, fractionated hydrocracked products and a bio-oil feed; hydrocracking the fossil hydrocarbon feed and recycle stream in the presence of the catalyst and the hydrogen stream to produce a slurry hydrocracked effluent stream; taking a recycle stream from the hydrocracked effluent stream; and adding the bio-oil stream directly into the recycle 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 further comprising charging a fossil hydrocarbon feed stream into the slurry hydrocracking reactor, wherein an amount of the bio-oil stream is about 1 wt % to 40 wt % of the fossil hydrocarbon feed 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 further comprising separating the slurry hydrocracked effluent stream into a vapor hydrocracked effluent stream and a liquid hydrocracked effluent stream; and fractionating the liquid hydrocracked effluent stream to provide a vacuum gas oil stream and a pitch 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 recycle stream is taken from the pitch stream optionally with vacuum gas oil stream.

A third embodiment of the present disclosure is a slurry hydrocracking process, comprising charging a fossil feed, a fresh catalyst, a hydrogen stream, and a recycle stream comprising a recovered concentrated catalyst and a bio-oil feed to a slurry hydrocracking reactor; hydrocracking the fossil feed and the biooil feed fed in the recycle stream in the presence of the recovered concentrated catalyst, the hydrogen stream and the fresh catalyst stream to produce a slurry hydrocracked effluent stream; taking a recycle stream from the hydrocracked effluent stream; and adding the bio-oil stream directly into the recycle 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 further comprising fractionating the hydrocracked effluent stream to provide a vacuum gas oil stream and a pitch stream; and taking the recycle stream from at least one of the vacuum gas oil stream and the pitch 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.