WO2018058172A1

WO2018058172A1 - Biooil refining methods

Info

Publication number: WO2018058172A1
Application number: PCT/AU2017/000205
Authority: WO
Inventors: Yannick Sylvain MATHIEU; Laurent Louis André SAUVANAUD; Avelino Corma Canos; William Neil Rowlands; Leonard James Humphreys; Thomas Maschmeyer
Original assignee: Licella Pty Ltd
Priority date: 2016-09-29
Filing date: 2017-09-29
Publication date: 2018-04-05

Abstract

A method for producing an upgraded biooil product, the method comprising: hydrotreating a biooil or a distillate thereof with hydrogen in the presence of hydrotreating catalysts, wherein the biooil was produced by hydrothermal treatment of organic feedstock.

Description

Biooil Refining Methods

Incorporation by Cross-Reference

The present application claims priority from Australian provisional patent application number 2016903967 filed on 29 September 2016, the entire content of which are incorporated herein by cross-reference.

Technical Field

The present invention relates generally to the field of refining oil. More specifically, the present invention relates to methods for upgrading biooil and fractionated components thereof, and upgraded fuel products generated from performing the methods.

Background

Dwindling petroleum resources and environmental pressure to lower carbon emissions is favouring the emergence of biomass processing to obtain transportation fuels, petrochemical precursors and other commodities from renewable sources. First generation conversion processes use edible sugars or oils to generate ethanol or Fatty Acid Methyl Esters (FAMEs) that are blended with gasoline and diesel fuels respectively. Besides the ethical debate on the use of edible materials, these industries are strongly dependent of expensive and limited feedstocks.

With the problem evident, attention has turned to alternative feedstocks such as agricultural residues, grasses, forestry wastes and the like which are available at a comparatively low cost and have been used as a feedstock to produce biooils by various methodologies including flash/fast pyrolysis, liquefaction, and gasification processes. Other approaches have involved upgrading low-rank fossil fuels such as coal, peat and other similar materials into bio-oils using similar techniques. However, the application range for biooils has been limited by unfavourable characteristics including high oxygen content, high acidity (pH~2.5), high viscosity, low volatility, corrosiveness, and/or immiscibility with fossil fuels, thermal instability, and a tendency to polymerise under exposure to air. This has made it necessary to refine/upgrade biooils before they can be used in most downstream applications.

Hydrothermal processes for converting organic matter into biooil typically produce viscous oils containing about 8-30% oxygen, and water soluble organic compounds containing > 20 % oxygen. In contrast to both crude oils and plant oils, oils produced by hydrothermal processes from coal, lignocellulosic material and other forms of biomass contain a huge variety of compounds and functional groups (e.g. acids, ketones, aldehydes, ethers, esters, furans, phenols, alcohols among many others). This has made the upgrading of biooils into higher value fuels and chemicals challenging, both from a technical viewpoint and from a cost perspective.

A need exists for more effective and/or cost-effective methods for upgrading biooils into higher-value fuel products and/or chemicals.

Summary of the Invention

Despite the considerable chemical and physical differences between crude oil and biooil, the present inventors have unexpectedly demonstrated that conventional hydroprocessing and catalytic cracking methods used to refine crude oil can be successfully applied to certain hydrothermally-produced biooils to provide upgraded fuel products. In some embodiments, the present inventors have modified conventional methods to augment the upgrading of hydrothermally-produced bio-oils.

The present invention thus relates at least to the following numbered embodiments: Embodiment 1 : A method for producing an upgraded biooil product, the method comprising:

hydrotreating a biooil or a distillate thereof with hydrogen in the presence of hydrotreating catalysts;

and optionally hydrocracking the biooil or biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof, with hydrogen using hydrocracking catalysts after said hydrotreating;

to thereby produce an upgraded biooil product, wherein:

the biooil was produced by hydrothermal treatment of organic feedstock material with an aqueous solvent at a temperature of between 250°C and 500°C, and at a pressure of between 20 bar and 350 bar;

prior to the hydrotreating the biooil comprises any one or more of:

an oxygen content on a dry basis of 5wt% db -25wt% db,

a Total Acid Number (TAN, ASTM D664) of 1 -200 mg KOH/g (e.g. 1 - 50 mg KOH/g),

a water content of 0.1%-5% (e.g. 0.5%-5%);

a gross calorific value on a dry basis of 30-40 MJ/kg; the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

Embodiment 2: The method of embodiment 1, wherein the method comprises said hydrocracking after the hydrotreating,

optionally wherein the biooil or biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof is hydrocracked in a mixture with a second oil selected from any one or more of gas oil, light gas oil, vacuum gas oil, atmospheric gas oil, straight run gas oil, long residue, atmospheric residue, atmospheric bottoms, short residue, vacuum bottoms, vacuum residue, coker gas oil, and/or heavy gas oil, and

optionally wherein the mixture subjected to the hydrocracking comprises:

at least 3wt% of the biooil or biodistillate thereof and at least 67% of the second oil, at least 5wt%> of the biooil or biodistillate thereof and at least 65% of the second oil, at least 7wt% of the biooil or biodistillate thereof and at least 63% of the second oil, at least 10wt% of the biooil or biodistillate thereof and at least 50% of the second oil,

at least 15wt% of the biooil or biodistillate thereof and at least 55% of the second oil,

at least 20wt% of the biooil or biodistillate thereof and at least 50% of the second oil,

at least 30wt% of the biooil or biodistillate thereof and at least 40% of the second oil,

at least 40wt% of the biooil or biodistillate thereof and at least 30% of the second oil,

at least 50wt% of the biooil or biodistillate thereof and at least 20% of the second oil,

at least 60wt% of the biooil or biodistillate thereof and at least 10% of the second oil,

at least 70wt% of the biooil or biodistillate thereof and at least 5% of the second oil, or

at least 80wt% of the biooil or biodistillate thereof and at least 10%> of the second oil. Embodiment 3: The method of embodiment 2, wherein the hydrocracking comprises:

hydrocracking the entire biooil or biodistillate thereof after said hydrotreating; and/or

fractionating the biooil or biodistillate thereof after said hydrotreating into an aqueous fraction comprising substantially water and a minor proportion of dissolved organic products (e.g. less than 5%wt, less than 10%wt), and a non-aqueous fraction, and hydrocracking the non-aqueous fraction; and/or

fractionating the biooil or biodistillate thereof after said hydrotreating into light and heavy fractions and subjecting the heavy fraction to hydrocracking.

Embodiment 4: A method for producing an upgraded biooil product, the method comprising hydrocracking a biooil or a biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof, with hydrogen using hydrocracking catalysts to thereby produce the upgraded biooil product, wherein:

prior to the hydrocracking the biooil comprises any one or more of: an oxygen content on a dry basis of 5wt% db -25wt% db,

a Total Acid Number (TAN, ASTM D664) of 1-200 mg KOH/g (e.g. 1- 50 mg KOH/g),

a water content of 0.1%-5% (e.g. 0.5%-5%);

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil;

and the method does not comprise a stage of hydrotreating the biooil, biodistillate thereof, or separated fraction/s.

Embodiment 5: The method of embodiment 4, wherein the hydrocracking comprises:

hydrocracking the entire biooil or biodistillate thereof; and/or fractionating the biooil or biodistillate thereof into an aqueous fraction comprising substantially water and a minor proportion of dissolved organic products (e.g. less than 5%wt, less than 10%wt), and a non-aqueous fraction, and hydrocracking the non-aqueous fraction; and/or

fractionating the biooil or biodistillate thereof into light and heavy fractions and subjecting the heavy fraction to hydrocracking.

Embodiment 6: The method of any one of embodiments 1 to 5, wherein the hydrocracking comprises treating the biooil or distillate thereof in the presence of hydrogen at:

a temperature of 350 °C to 450°C, or 380 °C to 425°C; and/or

a space velocity may range from 0.1 to 10 h^"1, or 0.3 to 1 h^"1; and/or

a pressure of 80 to 250 bar or 100 to 150 bar.

Embodiment 7: The method of any one of embodiments 1 to 6, wherein the hydrocracking is performed under conditions selected to:

minimise the amount of material boiling above the normal boiling range of diesel fuel in the upgraded fuel product; and/or

modify characteristics of the upgraded fuel product to approximate those of automotive fuel specifications for gasoline and diesel road fuels (e.g. as per EN228 and EN590 specifications).

Embodiment 8: The method according to any one of embodiments 1 to 7, wherein the hydrocracking comprises:

treating the biooil or distillate thereof at a temperature of between 350°C and 450°C (e.g. 380°C and 450°C) and at a pressure of between 80 bar and 250 bar (e.g. 100 bar and 200 bar) in the presence of hydrogen with hydrocracking catalysts capable of cracking hydrocarbon molecules in the biooil or distillate thereof.

Embodiment 9: A method for producing an upgraded biooil product, the method comprising the steps of:

(i) hydrotreating a biooil or a distillate thereof with hydrogen in the presence of hydrotreating catalysts to thereby produce a hydrotreated intermediate; and

(ii) catalytically cracking the hydrotreated intermediate with cracking catalysts at a temperature suitable to cleave hydrocarbon chains within the hydrotreated intermediate to thereby produce an upgraded fuel product,

wherein: the biooil was produced by hydrothermal treatment of organic feedstock material with an aqueous solvent at a temperature of between 250°C and 450°C, and at a pressure of between 100 bar and 350 bar;

prior to the hydrotreating the biooil comprises any one or more of:

an oxygen content on a dry basis of 5wt% db -25wt% db, a Total Acid Number (TAN, ASTM D664) 1-200 mg KOH/g (e.g. 1-50 mg KOH/g),

a water content of 0. \%-5% (e.g. 0.5%-5%),

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

Embodiment 10: The method of embodiment 9, wherein the hydrotreated intermediate (e.g. heavy oil fraction) is mixed with mineral oil (e.g. a gas oil, light gas oil vacuum gas oil, atmospheric gas oil, straight run gas oil, long residue, atmospheric residue, atmospheric bottoms, short residue, vacuum bottoms, vacuum residue, coker gas oil, heavy gas oil, or any combination thereof) prior to or during the catalytic cracking of step (ii), and the mineral oil has a boiling point that is no more than 20%, no more than 15%, no more than 10%, no more than 5%, or no more than 3%, higher or lower than the boiling point of the hydrotreated intermediate.

Embodiment 1 1 : The method of embodiment 10, wherein the hydrotreated intermediate is subjected to the catalytic cracking within a mixture comprising:

the hydrotreated intermediate and mineral oil,

between about 1% and 99% of the hydrotreated intermediate by weight and a remaining portion comprising or consisting of mineral oil, and/or

between 1% and 5% of the hydrotreated intermediate by weight and between about 95% - 99% by weight mineral oil.

Embodiment 12: The method according to any one of embodiments 9 to 1 1 , wherein the hydrotreated intermediate is fractionated into a distillate fraction and a heavy oil fraction, and the heavy oil fraction is subjected to the catalytic cracking of step (ii).

Embodiment 13: The method according to any one of embodiments 1 to 8, wherein the hydrotreating comprises: treating the biooil or distillate thereof at a temperature of between 280°C and 380°C (e.g. 320°C and 380°C, 350°C and 380°C) and at a pressure of between 10 bar and 150 bar in the presence of hydrogen with hydrotreating catalysts capable of removing any one or more of sulphur, nitrogen, and metals from the biooil or distillate thereof.

Embodiment 14: The method according to any one of embodiments 1 to 13, wherein the biooil or distillate thereof subjected to hydrotreating is a component fractionated from the biooil or distillate thereof prior to the hydrotreating.

Embodiment 15: The method according to any one of embodiments 1 to 14, wherein the hydroprocessing is performed at a space velocity in the range of:

(i) 10 to 0.1 h^"1,

(ii) 2 to 0.3 h^"1.

16. The method according to any one of embodiments 1 to 15, wherein the hydrotreating and/or hydrocracking comprises using several reactors sequentially in a cascade.

Embodiment 17: The method according to embodiment 16, wherein one or more components (e.g. water) is/are removed from the biooil under treatment between the reactors.

Embodiment 18: The method according to any one of embodiments 1 to 17, wherein the hydrotreating and/or hydrocracking catalysts are selected from the group consisting of: Ni, W, Co, Mo, and any combination thereof

Embodiment 19: The method according to embodiment 18, wherein the hydrotreating and/or hydrocracking catalysts further comprise any one or more of: P, B, Fe, Cu, V, Cr, Zn, Mn

Embodiment 20: The method according to embodiment 17 or embodiment 18, wherein the hydrotreating and/or hydrocracking catalysts are supported on an inorganic oxide selected from the group consisting of: silica, alumina, silica-alumina, zirconia, titania, magnesia, magnesia-alumina of hydrotalcite, spinel structure, molecular sieves, and any combination thereof.

Embodiment 21 : The method according to any one of embodiments 18 to 20, wherein the hydrotreating and/or hydrocracking catalysts are supported on an inorganic oxide having an acid function selected from the group consisting of: silica-alumina, a zeolite, a zeotype, beta zeolite, Y zeolite, X zeolite, omega zeolite, L zeolite, ITQ-21 zeolite and any combination thereof.

Embodiment 22: A method for producing an upgraded biooil product, the method comprising: catalytically cracking a biooil or a distillate thereof with cracking catalysts at a temperature suitable to cleave hydrocarbon chains within the biooil or distillate to thereby produce an upgraded fuel product,

wherein:

the biooil was produced by hydrothermal treatment of organic feedstock material with an aqueous solvent at a temperature of between 250°C and 450°C, and at a pressure of between 100 bar and 350 bar;

prior to the catalytic cracking the biooil comprises any one or more of:

an oxygen content on a dry basis of 5wt% db -25 wt% db, a Total Acid Number (TAN, ASTM D664) of 1-200 mg KOH/g (e.g. 1-50 mg KOH/g),

a water content of 0.1%-5% (e.g. 0.5%-5%)

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

Embodiment 23: The method of embodiment 22, wherein

the biooil or distillate thereof is as a component of a feedstock subjected to said catalytic cracking, and

the biooil or distillate thereof constitutes more than 5%, more than 10%, more than 15%, more than 20%, more than 25%, more than 30%, more than 35%, more than 40%, more than 45%, or more than 50%, of the feedstock.

Embodiment 24: The method of embodiment 23, wherein:

the feedstock comprises the biooil or distillate thereof mixed with mineral oil (e.g. a gas oil, light gas oil, a vacuum gas oil, atmospheric gas oil, straight run gas oil, long residue, atmospheric residue, atmospheric bottoms, short residue, vacuum bottoms vacuum residue, coker gas oil, heavy gas oil, or any combination thereof).

Embodiment 25: The method of embodiment 24, wherein the mineral oil has a boiling point that is no more than 20%, no more than 15%, no more than 10%, no more than 5%, or no more than 3%, higher or lower than the boiling point of the biooil or a distillate thereof Embodiment 26: The method of embodiment 24 or embodiment 25, wherein the biooil or distillate thereof is subjected to the catalytic cracking within a mixture comprising:

the biooil or distillate thereof, and mineral oil,

between about 1% and 99% of the biooil or distillate thereof by weight and a remaining portion comprising or consisting of mineral oil, and/or

between 1% and 5% of the biooil or distillate thereof by weight and between about 95% - 99% by weight mineral oil

Embodiment 27: The method of any one of embodiments 22 to 26, wherein the catalytic cracking is performed at a temperature of:

(i) between 450°C and 650°C, or

(ii) between 480°C and 550°C.

Embodiment 28: The method of any one of embodiments 22 to 27, wherein the catalytic cracking is performed at a pressure of:

(i) between 0.05 MPa and 1 Mpa, or

(ii) between 0.01 MPa and 0.3 MPa.

Embodiment 29: The method of any one of embodiments 22 to 28, wherein the catalytic cracking is performed in a Fluid Catalytic Cracking Unit (FCCU) suitable for upgrading of conventional crude oil.

Embodiment 30: The method of any one of embodiments 22 to 29, wherein:

the catalytic cracking comprises using regenerated cracking catalysts in a reaction zone of a Fluid Catalytic Cracking Unit (FCCU) suitable for upgrading of conventional crude oil, and the regenerated catalysts are provided at a temperature between 500°C and 800°C.

Embodiment 31 : The method of any one of embodiments 22 to 30, wherein feed subjected to catalytic cracking is preheated to temperatures of 150°C to 300°C.

Embodiment 32: The method of any one of embodiments 22 to 31 , wherein the catalytic cracking comprises using catalysts comprising any one or more of: zeolites, large pore zeolites, Y zeolites, X zeolites, beta zeolites, L zeolites, Omega zeolites, offretites, ITQ 21 zeolites, ZSM5, ZSM12, ferrierite, SAPOl l, platinum, or any combination thereof.

Embodiment 33: The method of any one of embodiments 22 to 32, wherein the catalytic cracking comprises using a matrix for the catalysts and a binder.

Embodiment 34: The method according to any one of embodiments 1 to 33, wherein the biooil comprises any one or more of: an energy content of 30-40 (GCV/HHV MJ/kg db)

a carbon content of 76-82 wt% db

a sulphur content of 0.01 -0.2 wt% db

a hydrogen content of 6-9 wt% db

kinematic viscosity of 100 to 2000 centiStokes at 40°C

a specific gravity of 0.98-1.1.

Embodiment 35: The method according to any one of embodiments 1 to 34, wherein the biooil was produced by hydrothermal treatment of lignocellulosic material with an aqueous solvent at a temperature of between 280°C and 420°C, 280°C and 370°C, or 300°C and 350°C, and at a pressure of between 100 bar and 300 bar.

Embodiment 36: The method according to any one of embodiments 1 to 35, wherein the biooil was produced by hydrothermal treatment of organic matter comprising any of softwood biomass, bagasse, wheat straw, oil palm, biomass used for oil production, spruce, pine, fir, microalgae, macroalgae, wheat straw, bagasse, eucalypt and any combination thereof.

Embodiment 37: The method of any one of embodiments 1 to 36, wherein the upgraded fuel product has an oxygen content below 1 wt%, an aromatic content below 40 wt%, and a polyaromatic content below 3 wt%.

Embodiment 38: The method of any one of embodiments 1 to 37, wherein the oxygen content of the upgraded fuel product is reduced compared to the oxygen content of the biooil by more than 5%, more than 10%, more than 15%, more that 20%, more than 25%, more than 30%, more than 40%, more than 50%, more than 60%, or more than 75%.

Embodiment 39: The method of any one of embodiments 1 to 38, wherein the Total Acid Number (TAN, ASTM D664) of the upgraded fuel product is reduced compared to the Total Acid Number (TAN, ASTM D664) of the biooil by more than 50%, more than 60%, more than 70%, more than 75%, more than 80%, more than 85%, more than 90%, more than 95%, more than 96%, more than 97%, more than 98%, or more than 99%.

Embodiment 40: The method of any one of embodiments 1 to 39, wherein the water content of the upgraded fuel product is reduced compared to the water content of the biooil by more than 50%, more than 60%, more than 70%, more than 75%, more than 80%, more than 85%, more than 90%, more than 95%, more than 96%, more than 97%, more than 98%, or more than 99%.

Embodiment 41 : The method of any one of embodiments 1 to 21, wherein the hydrotreating is conducted on a mixture comprising:

the biooil or biodistillate thereof, and a second oil selected from any one or more of crude oil, light gas oil, gas oil, straight run gas oil, heavy gas oil, atmospheric gas oil, light cycle oil, and/or mineral oil; wherein the mixture is optionally distilled (e.g. in an atmospheric distillation unit and/or a vacuum distillation unit) and/or optionally fractionated into different boiling ranges before said hydrotreating.

Embodiment 42: The method of embodiment 41, wherein the mixture comprises: at least 1 wt% of the biooil or biodistiUate thereof and at least 69% of the second oil, at least 3wt% of the biooil or biodistiUate thereof and at least 67% of the second oil, at least 5wt% of the biooil or biodistiUate thereof and at least 65% of the second oil, at least 7wt% of the biooil or biodistiUate thereof and at least 63% of the second oil, at least 10wt% of the biooil or biodistiUate thereof and at least 50% of the second oil, at least 15wt% of the biooil or biodistiUate thereof and at least 55% of the second oil, at least 20wt% of the biooil or biodistiUate thereof and at least 50% of the second oil, at least 30wt% of the biooil or biodistiUate thereof and at least 40% of the second oil, at least 40wt% of the biooil or biodistiUate thereof and at least 30% of the second oil, at least 50wt% of the biooil or biodistiUate thereof and at least 20% of the second oil, at least 60wt% of the biooil or biodistiUate thereof and at least 10% of the second oil, at least 70wt% of the biooil or biodistiUate thereof and at least 5% of the second oil, or at least 80wt% of the biooil or biodistiUate thereof and at least 10% of the second oil.

Embodiment 43: The method of any one of embodiments 4 to 8, wherein the hydrocracking is conducted on a mixture comprising:

the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof,

and a second oil selected from any one or more of crude oil, gas oil, , heavy gas oil, atmospheric residue, vacuum gas oil, vacuum residue, and/or mineral oil;

wherein the mixture is optionally distilled (e.g. in an atmospheric distillation unit and/or a vacuum distillation unit) and/or optionally fractionated into different boiling ranges before said hydrotreating.

Embodiment 44: The method of embodiment 43, wherein the hydrocracking is conducted on a mixture comprising:

at least 3wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 67% of the crude oil, at least 5wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 65% of the crude oil, at least 7wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 63% of the crude oil, at least 10wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 50% of the crude oil, at least 15wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 55% of the crude oil, at least 20wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 50% of the crude oil, at least 30wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 40% of the crude oil, at least 40wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 30% of the crude oil, at least 50wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 20% of the crude oil, at least 60wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 10% of the crude oil, at least 70wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 5% of the crude oil, or at least 80wt% of the hydrotreated biooil or biodistiUate thereof or separated fraction/s of the hydrotreated biooil or biodistiUate thereof, and at least 10% of the crude oil.

Embodiment 45: The method of any one of embodiments 22 to 40, wherein the catalytic cracking is conducted on a mixture comprising:

the biooil or distillate thereof; and

a second oil selected from any one or more of crude oil, light gas oil, gas oil, straight run gas oil, heavy gas oil, atmospheric gas oil, light cycle oil, and/or mineral oil; wherein the mixture is optionally distilled (e.g. in an atmospheric distillation unit and/or a vacuum distillation unit) and/or optionally fractionated into different boiling ranges before said hydrotreating.

Embodiment 46: The method of embodiment 45, wherein the catalytic cracking is conducted on a mixture comprising:

at least 3wt% of the biooil or biodistiUate thereof and at least 67% of the second oil, at least 5wt% of the biooil or biodisti ate thereof and at least 65% of the second oil, at least 7wt% of the biooil or biodistiUate thereof and at least 63 % of the second oil, at least 10wt% of the biooil or biodistiUate thereof and at least 50% of the second oil, at least 15wt% of the biooil or biodisti ate thereof and at least 55% of the second oil, at least 20wt% of the biooil or biodistillate thereof and at least 50% of the second oil, at least 30wt% of the biooil or biodistillate thereof and at least 40% of the second oil, at least 40wt% of the biooil or biodistillate thereof and at least 30% of the second oil, at least 50wt% of the biooil or biodistillate thereof and at least 20% of the second oil, at least 60wt% of the biooil or biodistillate thereof and at least 10% of the second oil, at least 70wt% of the biooil or biodistillate thereof and at least 5% of the second oil, or at least 80wt% of the biooil or biodistillate thereof and at least 10% of the second oil.

Embodiment 47: The method of any one of embodiments 41 to 46, wherein the mixture further comprises mineral oil.

Embodiment 48: The method of embodiment 47, wherein the mineral oil constitutes:

at least 3wt% of the mixture,

at least 5wt% of the mixture,

at least 7wt% of the mixture,

at least 10wt% of the mixture,

at least 15wt% of the mixture,

at least 20wt% of the mixture,

at least 30wt% of the mixture,

at least 40wt% of the mixture,

at least 50wt% of the mixture,

at least 60wt% of the mixture,

at least 70wt% of the mixture, or

at least 80wt% of the mixture.

Embodiment 49: The method of any one of embodiments 1 to 48, wherein the biooil or a distillate thereof used as a starting material in the method is provided in combination with a second oil comprising at least 20%, at least 30%, at least 40% or at least 50% of any one or more of: free fatty acids, triglycerides, diglycerides, monoglycerides, or any combination thereof.

Embodiment 50: A method for producing an upgraded biooil product, the method comprising the steps of:

(i) hydrocracking a biooil or a biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof, with hydrogen using hydrocracking catalysts to thereby produce a hydrocracked intermediate; and (ii) catalytically cracking the hydrocracked intermediate with cracking catalysts at a temperature suitable to cleave hydrocarbon chains within the hydrotreated intermediate to thereby produce an upgraded fuel product,

wherein:

prior to the hydrocracking the biooil comprises any one or more of: an oxygen content on a dry basis of 5wt% db -25 wt% db,

a Total Acid Number (TAN, ASTM D664) of 1-200 mg KOH/g (e.g. 1- 50 mg KOH/g),

a water content of 0.1%-5% (e.g. 0.5%-5%);

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

Embodiment 51 : The method of embodiment 50, wherein the method does not comprise a stage of hydrotreating the biooil, biodistillate thereof, or separated fraction/s.

Embodiment 52: The method of embodiment 50 or embodiment 51, wherein the hydrocracking comprises:

hydrocracking the entire biooil or biodistillate thereof; and/or

fractionating the biooil or biodistillate thereof into an aqueous fraction comprising substantially water and a minor proportion of dissolved organic products (e.g. less than 5%wt, less than 10%wt), and a non-aqueous fraction, and hydrocracking the non-aqueous fraction; and/or

Embodiment 53: The method of any one of embodiments 50 to 52, wherein the hydrocracking comprises treating the biooil or distillate thereof in the presence of hydrogen at:

a temperature of 350 °C to 450°C, or 380 °C to 425°C; and/or

a space velocity may range from 0.1 to 10 h^"1, or 0.3 to 1 h^"1; and/or a pressure of 80 to 250 bar or 100 to 150 bar.

Embodiment 54: The method of any one of embodiments 50 to 53, wherein the hydrocracked intermediate is subjected to the catalytic cracking within a mixture comprising:

the hydrocracked intermediate and mineral oil,

between about 1% and 99% of the hydrocracked intermediate by weight and a remaining portion comprising or consisting of mineral oil, and/or

between 1% and 5% of the hydrocracked intermediate by weight and between about 95% - 99% by weight mineral oil.

Embodiment 55: The method of any one of embodiments 50 to 54, wherein the hydrocracked intermediate is fractionated into a distillate fraction and a heavy oil fraction, and the heavy oil fraction is subjected to the catalytic cracking of step (ii).

Embodiment 56: The method of embodiment 1 , wherein the method:

does not comprise hydrocracking the biooil or biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof, before or after said hydrotreating; and

comprises dearomatizing the biooil or biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof after said hydrotreating; and

the upgraded biooil product is kerosene.

Embodiment 57. The method of embodiment 56, wherein the kerosene comprises a polyaromatics content of polyaromatics of less than 3 wt% and an aromatic content less than 25 wt%.

Certain elements of the present invention relate to upgrading biooil by hydroprocessing, as set out in the exemplary numbered embodiments below:

Embodiment 1 : An upgrading method for a biooil prepared through a hydrothermal process fed principally with lignocellulosic biomass consisting of contacting the whole biooil or one or several biooil fractions with hydrogen in the presence of a catalyst, yielding an upgraded liquid with low oxygen content.

Embodiment 2: The method of embodiment 1, where the hydrothermal process consist of hydrothermal liquefaction with near critical water

Embodiment 3: The method of embodiment 1, wherein said treatment temperature is in the range of 280 to 380°C, preferably 320 to 380°C, more preferably 350 to 380°C.

Embodiment 4: The method of embodiment 1, wherein said treatment pressure is between 10 and 150 bars, more preferentially between 40 and 120 bars. Embodiment 5: The method of embodiment 1, wherein said treatment is performed at a space velocity in the range of 10 to 0.1 h-1, preferentially in the range of 2 to 0.3 h-l.

Embodiment 6: The method of embodiment 1, wherein the catalyst comprises at least one metal from the group Ni, W, Co, Mo, and mixtures thereof.

Embodiment 7: The method of embodiment 6, wherein the catalysts is supported on an inorganic oxide such as silica, alumina, silica-alumina, zirconia, titania, magnesia, magnesia-alumina of hydrotalcite and spinel structure, molecular sieves.

Embodiment 8: The method of embodiment 1, where several reactors in cascade are used.

Embodiment 9: The method of embodiment 9, where a separation is performed between reactors to remove, for example water fraction.

Embodiment 10: The method of embodiment 1, where the hydroprocessed liquids are essentially a diesel stream.

Embodiment 11 : The method of embodiment 10, where the diesel stream has an oxygen content below lwt%, an aromatic content below 40 wt% and a polyaromatic content below 3wt%.

Embodiment 12: The method of embodiment 1, where a substantial fraction of kerosene can be extracted from the hydroprocessed liquids, with low oxygen content, low aromatic content and very low polyaromatic content.

Embodiment 13: The method of embodiment 12, where the kerosene stream has an oxygen content below 1 wt%, an aromatic content below 30 wt% and a polyaromatic content below 3 wt%.

Further elements of the present invention relate to upgrading biooil by hydrocracking, as set out in the exemplary numbered embodiments below:

Embodiment 1 : An upgrading method for a biooil prepared through a hydrofhermal process fed principally with lignocellulosic biomass consisting of contacting the whole biooil or one or several biooil fractions with hydrogen in the presence of a catalyst (hydrocracking), yielding an upgraded liquid with low oxygen content and reduced amount of material boiling above 350°C.

Embodiment 2: The method of embodiment 1, where the hydrothermal process consists of hydrothermal liquefaction with near critical water.

Embodiment 3: The method of embodiment 1, wherein said hydrocracking temperature is in the range of 350 to 450°C, preferably 380 to 425°C. Embodiment 4: The method of embodiment 1, wherein said hydrocracking pressure is between 80 and 250 bars, more preferentially between 100 and 200 bars.

Embodiment 5: The method of embodiment 1, wherein said treatment is performed at a space velocity in the range of 10 to 0.1 h-1, preferentially in the range of 1 to 0.2 h-1.

Embodiment 7: The method of embodiment 6, wherein the catalyst is supported on an inorganic oxide such as silica, alumina, silica-alumina, zirconia, sulphated zirconia, ceria, titania, magnesia, magnesia-alumina of hydrotalcite and spinel structure, molecular sieves.

Embodiment 8: The method of embodiment 7, where the catalyst is supported on an inorganic oxide having an acid function. Such inorganic oxide may be constituted of silica-alumina, or a zeolite or zeotype such as beta zeolite, Y zeolite, X zeolite, omega zeolite, L zeolite, ITQ-21 zeolite and combinations thereof.

Embodiment 9: The method of embodiment 1, where several reactors in cascade are used.

Embodiment 10: The method of embodiment 9, where a separation is performed between reactors to remove, for example water fraction.

Embodiment 11 : The method of embodiment 1 , where the hydroprocessed liquids have a reduced content of material boiling above 360 °C, preferably less than 5 wt%.

Embodiment 12: The method of embodiment 1 1, where the hydroprocessed liquid has an oxygen content below 1 wt%, an aromatic content below 40 wt% and a polyaromatic content below 3 wt%.

Embodiment 13: The method of embodiment 1, where a substantial fraction of kerosene can be extracted from the hydroprocessed liquids, with low oxygen content, low aromatic content and very low polyaromatic content.

Embodiment 14: The method of embodiment 13, where the kerosene stream as an oxygen content below 1 wt%, an aromatic content below 30 wt% and a polyaromatic content below 3 wt%.

Other elements of the present invention relate to upgrading biooil by hydroprocessing and catalytic cracking, as set out in the exemplary numbered embodiments below:

Embodiment 1 : An upgrading method for a hydrotreated biooil heavy fraction prepared through a process comprising a. obtaining a biooil through a hydrothermal process fed principally with lignocellulosic biomass

b. optionally fractionating said biooil

c. hydroprocessing biooil or preferentially biooil distillate, obtaining a deoxygenated stream

d. fractionating hydroprocessed biooil into a distillate and a hydrotreated biooil heavy fraction, and catalytically cracking said hydrotreated biooil heavy fraction, yielding gas, gasoline and diesel range products.

Embodiment 2: The method of embodiment 1, where the catalytic cracking of said fraction is carried out together with a mineral oil stream.

Embodiment 3: The method of embodiment 2, where the mineral oil is a petroleum refinery stream comprising gas oil, light gas oil, vacuum gas oil, atmospheric gas oil, straight run gas oil, long residue, atmospheric residue, atmospheric bottoms, short residue, vacuum bottoms vacuum residue, coker gas oil, heavy gas oil, or a mixture of them.

Embodiment 4: The method of embodiment 1, wherein catalytic cracking takes place at a temperature of 450 to 650°C, preferentially 480 to 550°C.

Embodiment 5: The method of embodiment 2, where biooil Fraction is added to mineral oil in a ratio of 1 to 99 to 90 to 10, preferentially 1 to 99 to 1 to 20.

Embodiment 6: The method of embodiment 1, wherein said hydrotreatment temperature is in the range of 280 to 380"C, preferably 320 to 380"C, more preferably 320 to 350°C.

Embodiment 7: The method of embodiment 1, wherein said hydrotreatment pressure is between 10 and 150 bars, more preferentially between 30 and 80 bars, more.

Embodiment 8: The method of embodiment 1, wherein said hydrotreatment is performed at a space velocity in the range of 10 to 0.1 h^"1, preferentially in the range of 2 to 0.3 h^"1.

Embodiment 9: The method of embodiment 6, wherein the catalyst comprises at least one metal from the group Ni, W, Co, Mo, and mixtures thereof.

Embodiment 10: The method of embodiment 6, where catalyst comprises at least one element of embodiment 9 and at least one element of the group: P, B, Fe, Cu, V, Cr, Zn, Mn

Embodiment 1 1 : The method of embodiment 6, wherein the catalysts is supported on an inorganic oxide such as silica, alumina, silica-alumina, zirconia, titania, magnesia, magnesia-alumina of hydrotalcite and spinel structure, molecular sieves. Embodiment 12: The method of embodiment 1, wherein said hydrotreatment uses several reactors in cascade.

Embodiment 13: The method of embodiment 9, where a separation is performed between reactors to remove, for example water fraction.

Embodiment 14: The method of embodiment 1, where the hydroprocessed liquids has a low oxygen content, preferably below 5wt%, more preferably below 2 wt%.

Embodiment 15: The method of embodiment 1, where the hydroprocessed liquids has a fraction boiling above 350 °C of at least 1 wt%, preferentially above 5 wt%.

Definitions

As used in this application, the singular form "a", "an" and "the" include plural references unless the context clearly dictates otherwise.

As used herein, the term "comprising" means "including." Variations of the word "comprising", such as "comprise" and "comprises," have correspondingly varied meanings. Thus, for example, a method "comprising" a hydroprocessing stage may consist exclusively of the hydroprocessing stage or may include one or more additional stage(s) (e.g. a catalytic cracking stage).

As used herein, "organic matter" encompasses any matter comprising carbon, including both fossilised and non-fossilised forms of carbon-comprising matter.

As used herein, the term "biooil" refers to oil products derived from thermochemical processing of fossilised organic material (e.g. coals such as lignite), non- fossilised organic material (e.g. lignocellulosic matter), or mixtures thereof.

As used herein, the term "aqueous solvent" refers to a solvent comprising at least one percent water based on total weight of solvent. An "aqueous solvent" may therefore comprise between one percent water and one hundred percent water based on total weight of solvent.

As used herein, "hydrothermal treatment", "hydrothermally treated", "hydrothermally processed" and "hydrothermal processing" refer to a process in which organic matter is converted into biooil in the presence of water and optionally catalysts at elevated temperatures (e.g. 250°C - 500°C) and elevated pressures of 50 bar - 300 bar, inclusive of temperatures/pressures both below, at, and above the critical point of a solvent used in the process (e.g. water, aqueous alcohol).

As used herein, the term "hydrotreating" refers to contacting a hydrocarbon- containing mixture (e.g. a biooil) with hydrogen in the presence of one or more catalyst types for the removal of heteroatoms, such as sulphur, nitrogen and metals from the mixture.

As used herein, the term "hydrocracking" refers to a process breaking or cracking bonds of long-chain hydrocarbons in the presence of hydrogen and at least one catalyst to produce hydrocarbons of lower molecular weight.

As used herein the term "hydroprocessing" encompasses hydrotreating, hydrocracking and any combination of hydrotreating and hydrocracking. In conventional petroleum refining hydrocracking is typically carried out at higher temperatures and/or pressures than hydrotreating.

As used herein, "catalytic cracking" refers to a process breaking or cracking bonds of long-chain hydrocarbons in the absence or substantially in the absence of hydrogen and in the presence of at least one catalyst to produce hydrocarbons of lower molecular weight.

As used herein the term "vacuum gas oil" encompasses a petroleum fraction obtained from crude oil vacuum distillation having a boiling point range of about 310°C- 560°C (e.g. 320°C-550°C). "Vacuum gas oil" as used herein encompasses both light vacuum gas oil and heavy vacuum gas oil.

As used herein the terms "vacuum residue", "vacuum bottoms" and "short residue" encompass a petroleum fraction obtained from crude oil vacuum distillation that is generally too involatile to distil, having a boiling point of more than about 540°C (e.g. more than about 550°C).

As used herein the terms "mineral oil" and "paraffin oil" encompass a variety of oils derived from a mineral source (e.g. distillates of petroleum including crude oil distillates), comprising alkanes, alkenes, aromatics, polyaromatics and polar compounds. "Paraffin oil" is characterised by a high content of higher alkanes compared to mineral oil.

As used herein, the term "gas oil" encompasses a petroleum fraction obtained from crude oil distillation including light gas oil, atmospheric gas oil, heavy gas oil, straight run gas oil and vacuum gas oil.

As used herein, the term "light gas oil" encompasses a petroleum fraction obtained from crude oil distillation having a boiling point range of about 200°C-345°C (e.g. 205°C-340 °C).

As used herein, the term "atmospheric gas oil" encompasses a petroleum fraction obtained from crude oil distillation in a distillation unit operating at close to atmospheric pressure and having a boiling point range of about 200°C-350°C (e.g. 205°C-340 °C). As used herein, the term "heavy gas oil" encompasses a petroleum fraction obtained from crude oil distillation having a boiling point range falling in the range of about 345°C-540°C (e.g. 350°C-540°C).

As used herein, the term "coker gas oil" encompasses a petroleum fraction obtained from the processing of heavy petroleum fractions in a coker or delayed coker.

As used herein, the term "straight run gas oil" encompasses a petroleum fraction that is gas oil obtained straight from a crude distillation unit without any further processing.

As used herein, the terms "long residue", "atmospheric bottoms" and "atmospheric residues" encompass petroleum fractions that are generally too involatile to distill in an atmospheric crude distillation unit and having a boiling point of more than about 350°C.

As used herein, the term "light cycle oil" encompasses an aromatic-rich petroleum fraction that is one of the products of a fluidized catalytic cracking unit and having a boiling point range falling in the range of about 195°C-400°C (e.g. 350°C-540°C).

Any description of prior art documents herein, or statements herein derived from or based on those documents, is not an admission that the documents or derived statements are part of the common general knowledge of the relevant art.

For the purposes of description all documents referred to herein are hereby incorporated by reference in their entirety unless otherwise stated.

Brief Description of the Figures

Preferred embodiments of the present invention will now be described, by way of an example only, with reference to the accompanying figures wherein:

Figure 1 is a schematic flow diagram of a hydrotreatment process according to an embodiment of the present invention;

Figure 2 is a schematic flow diagram of a hydrotreatment process according to an embodiment of the present invention;

Figure 3 is a schematic flow diagram of a hydrotreatment process according to an embodiment of the present invention;

Figure 4 represents the conversion obtained in catalytic cracking of Vacuum Gas Oil and mixtures with increasing amounts of hydrotreated biooil heavy fraction.

Figure 5 represents the main selectivity obtained in catalytic cracking of Vacuum Gas Oil and mixtures with increasing amounts of hydrotreated biooil heavy fraction. Figure 6 represents the evolution of a characteristic hydrogen transfer parameter, isobutene on isobutane ratio, when blending increasing amounts of hydrotreated biooil heavy fraction into VGO.

Figure 7 shows a distillation curve of the distilled biooil produced in accordance with a method of the invention.

Figure 8 shows conversion and selectivity parameters for feeds subjected to catalytic cracking in accordance with methods of the present invention.

Figure 9 shows simulated distillation technique (SIMDIS) analysis of biooil (blue line) and vacuum gas oil (VGO) (Black line) (Figure 8A), and SIMDIS of VGO (red line) and VGO-biooil blend (90-10 wt%, black line) (Figure 8B), following catalytic cracking in accordance with methods of the present invention.

Figure 10 shows cracking activity and selectivity following catalytic cracking reactions performed on different feedstocks, as well as detailed gas composition.

Figure 11 shows a thermogravimetric (TG) analysis of flashed (dewatered) raw biooil.

Figure 12 shows the composition of an exemplary hydroprocessed oil product produced in accordance with an embodiment of the present invention (Run 8) over a 56h Time-on-stream.

Figure 13 shows SIMDIS analysis of biooil and a chromatogram comparison with petroleum based Vacuum Gas Oil.

Figure 14 shows SIMDIS analysis of biooil and a chromatogram comparison with petroleum based Straight Run Gas Oil (SRGO, diesel) and Vacuum Gas Oil (VGO, FCC feed).

Figure 15 shows a two stage process for the preparation of biooil and biooil upgrading options according to an embodiment of the invention.

Figure 16 shows conversion and selectivity parameters for Biooil, VGO and their mixture, feeds subjected to catalytic cracking in accordance with an embodiment of the present invention (500°C, TOS = 30s).

Figure 17 shows GCxGC plots of Hydrotreated Biocrude Heavy Fraction (HBH), Figure 17A) 2D plot; (Figure 17B) 3D plot, as prepared in accordance with an embodiment of the present invention. Detailed Description

The present invention provides methods for upgrading biooil produced by hydrothermal treatment of organic matter. In some embodiments, the biooil is upgraded by hydrotreating and/or hydrocracking according to the methods described herein. Following the hydrotreating and/or hydrocracking the hydrothermally-produced biooil may additionally be subjected to catalytic cracking as also described herein. Various embodiments of the present invention are described below. It will be appreciated by persons of ordinary skill in the art that numerous variations and/or modifications can be made to the present invention as disclosed in the specific embodiments without departing from the spirit or scope of the present invention as broadly described. The present embodiments are, therefore, to be considered in all respects as illustrative and not restrictive.

Organic Matter

Biooil upgraded in accordance with the methods of the present invention may be initially generated from the hydrothermal processing of organic matter. The organic matter may include any matter comprising carbon, including both fossilised and non- fossilised forms of carbon-comprising matter.

No limitation exists regarding the particular type of organic matter used to produce the biooil.

The organic matter may comprise naturally occurring organic matter (e.g. lignocellulosic biomass, fossil fuel materials including lignite, oil shale, peat and the like) and/or synthetic organic materials (e.g. synthetic rubbers, plastics, nylons and the like). The organic matter may comprise fossilised organic material (e.g. lignite) and/or non- fossilised organic material (e.g. lignocellulosic matter). In the case where more than one type (i.e. a mixture) of organic matter is utilised, no limitation exists regarding the particular proportion of the different components of organic matter.

In some embodiments, the organic matter used to produce the biooil comprises lignocellulosic matter. As used herein, "lignocellulosic matter" refers to any substance comprising lignin, cellulose and hemicellulose.

For example, the lignocellulosic matter may be a woody plant or component thereof. Examples of suitable woody plants include, but are not limited to, pine (e.g. Pinus radiata), birch, eucalyptus, bamboo, beech, spruce, fir, cedar, poplar, willow and aspen. The woody plants may be coppiced woody plants (e.g. coppiced willow, coppiced aspen).

Additionally or alternatively, the lignocellulosic matter may be a fibrous plant or a component thereof. Non-limiting examples of fibrous plants (or components thereof) include grasses (e.g. switchgrass), grass clippings, flax, corn cobs, corn stover, reed, bamboo, bagasse, hemp, sisal, jute, cannibas, hemp, straw, wheat straw, abaca, cotton plant, kenaf, rice hulls, and coconut hair.

Additionally or alternatively, the lignocellulosic matter may be derived from an agricultural source. Non-limiting examples of lignocellulosic matter from agricultural sources include agricultural crops, agricultural crop residues, and grain processing facility wastes (e.g. wheat/oat hulls, corn fines etc.). In general, lignocellulosic matter from agricultural sources may include hard woods, soft woods, hardwood stems, softwood stems, nut shells, branches, bushes, canes, corn, corn stover, cornhusks, energy crops, forests, fruits, flowers, grains, grasses, herbaceous crops, wheat straw, switchgrass, salix, sugarcane bagasse, cotton seed hairs, leaves, bark, needles, logs, roots, saplings, short rotation woody crops, shrubs, switch grasses, trees, vines, cattle manure, and swine waste. Additionally or alternatively, the lignocellulosic matter may be derived from commercial or virgin forests (e.g. trees, saplings, forestry or timber processing residue, scrap wood such as branches, leaves, bark, logs, roots, leaves and products derived from the processing of such materials, waste or byproduct streams from wood products, sawmill and paper mill discards and off-cuts, sawdust, and particle board).

Additionally or alternatively, the lignocellulosic matter may be derived from industrial products and by-products. Non-limiting examples include wood-related materials and woody wastes and industrial products (e.g. pulp, paper (e.g. newspaper) papermaking sludge, cardboard, textiles and cloths, dextran, and rayon).

In some embodiments, the organic matter used to produce the biooil comprises fossilised organic matter. "Fossilised organic matter" as contemplated herein encompasses any organic material that has been subjected to geothermal pressure and temperature for a period of time sufficient to remove water and concentrate carbon to significant levels.

For example, fossilised organic material may comprise more than about 10%, 20%, 30%, 40%, 50%, 60%, 70%, 75%, 80%, 85%, 90% or 95wt% carbon. Preferably, the fossilised organic material may comprise more than about 50 wt% carbon, more than about 60 wt% carbon, or more than about 70% weight carbon. Non-limiting examples of such materials include coals (e.g. anthracitic coals such as meta-anthracite, anthracite and semianthracite; bituminous coals; subbituminous coals; lignite (i.e. brown coal), coking coal, coal tar, coal tar derivatives, coal char), cokes (e.g. high temperature coke, foundry coke, low and medium temperature coke, pitch coke, petroleum coke, coke oven coke, coke breeze, gas coke, brown coal coke, semi coke), peat (e.g. milled peat, sod peat), kerogen, tar sands, oil shale, shale tar, asphalts, asphaltines, natural bitumen, bituminous sands, or any combination thereof.

It will be understood that the organic material used to produce the biooil may comprise a mixture of two or more different types of lignocellulosic matter, including any combination of the specific examples provided above.

The relative proportion of lignin, hemicellulose and cellulose in a given sample will depend on the specific nature of the lignocellulosic matter.

By way of example only, the proportion of hemicellulose in a woody or fibrous plant used to produce the biooil may between about 15% and about 40%, the proportion of cellulose may between about 30% and about 60%, and the proportion of lignin may between about 5% and about 40%. Preferably, the proportion of hemicellulose in the woody or fibrous plant may between about 23% and about 32%, the proportion of cellulose may between about 38% and about 50%, and the proportion of lignin may between about 15% and about 25%.

In some embodiments, the lignocellulosic matter used to produce the biooil may comprise between about 2% and about 35% lignin, between about 15% and about 45% cellulose, and between about 10% and about 35% hemicellulose.

In other embodiments, the lignocellulosic matter used to produce the biooil may comprise between about 20% and about 35% lignin, between about 20% and about 45% cellulose, and between about 20% and about 35% hemicellulose.

In some embodiments, the lignocellulosic matter used to produce the biooil may comprise more than about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, or 50% lignin.

In some embodiments, the lignocellulosic matter used to produce the biooil may comprise more than about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, or 50% cellulose.

In some embodiments, the lignocellulosic matter used to produce the biooil may comprise more than about 5%, 10%, 15%, 20%, 25%, 30%, 35%, 40%, 45%, or 50% hemicellulose. The skilled addressee will recognise the production of the biooil is not constrained by the relative proportions of lignin, hemicellulose and cellulose in a given source of lignocellulosic matter.

In certain embodiments of the invention, a mixture of organic material comprising lignite (brown coal) and lignocellulosic matter may be used to produce the biooil. The lignocellulosic matter of the mixture may, for example, comprise woody plant material and/or fibrous plant material. The proportion of lignite in the mixture may be greater than about 20%, 40%, 60%> or 80%. Alternatively, the proportion of lignocellulosic matter in the mixture may be greater than about 20%, 40%, 60% or 80%>.

In some embodiments, the organic matter utilised to produce the biooil comprises carbon-containing polymeric materials, non-limiting examples of which include rubbers (e.g. tyres), plastics and polyamides (e.g. nylons).

Non-limiting examples of suitable rubbers include natural and synthetic rubbers such as polyurethanes, styrene rubbers, neoprenes, polybutadiene, fluororubbers, butyl rubbers, silicone rubbers, plantation rubber, acrylate rubbers, thiokols, and nitrile rubbers. Non-limiting examples of suitable plastics include PVC, polyethylene, polystyrene, terphtalate, polyethylene and polypropylene.

The organic matter used to produce the biooil may comprise carbon-containing wastes such as sewage, manure, or household or industrial waste materials.

The organic matter used to produce the biooil may be optionally pre-treated prior to converting it into the biooil. It will be recognised that no strict requirement exists to perform a pre-treatment step. For example, pre-treatment of the organic matter may not be required if it is obtained in the form of a liquid or in a particulate form. However, it is contemplated that in many cases pre-treatment of the organic matter may be advantageous in enhancing production of the biooil.

In general, pre-treatment may be used to break down the physical and/or chemical structure of the organic matter making it more accessible to various reagents utilised in the methods of the invention (e.g. oil-based solvent, catalysts and the like) and/or other reaction parameters (e.g. heat and pressure). In certain embodiments, pre-treatment of organic matter may be performed for the purpose of increasing solubility, increasing porosity and/or reducing the crystallinity of sugar components (e.g. cellulose). Pre- treatment of the organic matter may be performed using an apparatus such as, for example, an extruder, a pressurized vessel, or batch reactor. Pre-treatment of the organic matter may comprise physical methods, non-limiting examples of which include grinding, chipping, shredding, milling (e.g. vibratory ball milling), compression/expansion, agitation, and/or pulse-electric field (PEF) treatment.

Additionally or alternatively, pre-treatment of the organic matter may comprise physio-chemical methods, non-limiting examples of which include pyrolysis, steam explosion, ammonia fibre explosion (AFEX), ammonia recycle percolation (ARP), and/or carbon-dioxide explosion. Pre-treatment with steam explosion may additionally involve agitation of the organic matter.

Additionally or alternatively, pre-treatment of the organic matter may comprise chemical methods, non-limiting examples of which include ozonolysis, acid hydrolysis (e.g. dilute acid hydrolysis using H₂SO₄ and/or HC1), alkaline hydrolysis (e.g. dilute alkaline hydrolysis using sodium, potassium, calcium and/or ammonium hydroxides), oxidative delignification (i.e. lignin biodegradation catalysed by the peroxidase enzyme in the presence of ¾(¾), and/or the organosolvation method (i.e. use of an organic solvent mixture with inorganic acid catalysts such as H₂S0₄ and/or HC1 to break lignin- hemicellulose bonds).

Additionally or alternatively, pre-treatment of the organic matter may comprise biological methods, non-limiting examples of which include the addition of microorganisms (e.g. rot fungi) capable of degrading/decomposing various component(s) of the organic matter.

In some embodiments, the organic matter used to produce the biooil is lignocellulosic matter subjected to an optional pre-treatment step in which hemicellulose is extracted. Accordingly, the majority of the hemicellulose (or indeed all of the hemicellulose) may be extracted from the lignocellulosic matter and the remaining material (containing predominantly cellulose and lignin) used to produce the biooil (e.g. by hydrofhermal conversion). However, it will be understood that this pre-treatment is optional and no requirement exists to separate hemicellulose from lignocellulosic matter before producing the biooil. Suitable methods for the separation of hemicellulose from lignocellulosic matter are described, for example, in PCT publication number WO/2010/034055, the entire contents of which are incorporated herein by reference.

For example, the hemicellulose may be extracted from lignocellulosic matter by subjecting a slurry comprising the lignocellulosic matter (e.g. 5%-15% w/v solid concentration) to treatment with a mild aqueous acid (e.g. pH 6.5-6.9) at a temperature of between about 100°C and about 250°C, a reaction pressure of between about 2 and about 50 atmospheres, for between about 5 and about 20 minutes. The solubilised hemicellulose component may be separated from the remaining solid matter (containing predominantly cellulose and lignin) using any suitable means (e.g. by use of an appropriately sized filter). The remaining solid matter may be used to produce the biooil, or alternatively mixed with one or more other forms of organic matter (e.g. lignite) to produce the biooil.

Biooil Production from Organic Matter

Organic matter utilised in accordance with the methods of the present invention is preferably treated in the form of a slurry. The slurry may be generated, for example, by generating a particulate form of the organic matter (e.g. by physical methods such as those referred to above and/or by other means) and mixing with an appropriate liquid (e.g. an aqueous solvent and/or an oil).

Organic matter component

In certain embodiments of the invention, the concentration of solid matter in the slurry may be less than about 85 wt%, less than about 75 wt%, or less than about 50 wt%. Alternatively, the concentration of solid matter may be more than about 10 wt%, more than about 20 wt%, more than about 30 wt%, more than about 40 wt%, more than about 50 wt%, or more than about 60 wt%.

The optimal particle size of solid components and the optimal concentration of solids in the slurry may depend upon factors such as, for example, the heat transfer capacity of the organic matter utilised (i.e. the rate at which heat can be transferred into and through individual particles), the desired rheological properties of the slurry and/or the compatibility of the slurry with component/s of a given apparatus within which the methods of the invention may be performed (e.g. reactor tubing). The optimal particle size and/or concentration of solid components in a slurry used for the methods of the invention can readily be determined by a person skilled in the art using standard techniques. For example, a series of slurries may be generated, each sample in the series comprising different particle sizes and/or different concentrations of solid components compared to the other samples. Each slurry can then be treated in accordance with the methods of the invention under a conserved set of reaction conditions. The optimal particle size and/or concentration of solid components can then be determined upon analysis and comparison of the products generated from each slurry using standard techniques in the art.

In certain embodiments of the invention, the particle size of solid components in the slurry may between about 10 microns and about 10,000 microns. For example, the particle size may be more than about 50, 100, 500, 750, 1000, 2000, 3000, 4000, 5000, 6000, 7000, 8000 or 9000 microns. Alternatively, the particle size may less than about 50, 100, 500, 750, 1000, 2000, 3000, 4000, 5000, 6000, 7000, 8000 or 9000 microns. In some embodiments, the particle size is between about 10 microns and about 50 microns, between about 10 microns and about 100 microns, between about 10 microns and about 200 microns, between about 10 microns and about 500 microns, between about 10 microns and about 750 microns, or between about 10 microns and about 1000 microns. In other embodiments, the particle size is between about between about 100 microns and about 1000 microns, between about 100 microns and about 750 microns, between about 100 microns and about 500 microns, or between about 100 microns and about 250 microns.

Water component

In certain embodiments of the invention, the concentration of water in the slurry may be above about 80 wt%, above about 85 wt%, or above about 90 wt%. Accordingly, the concentration of water may be above about 75 wt%, above about 70 wt%, above about 60 wt%, above about 50 wt%, above about 40 wt%, or above about 30 wt%. In some embodiments, the concentration of water is between about 90 wt% and about 95 wt%.

In some preferred embodiments the slurry comprises between about 10 wt% and about 30 wt% water.

In particularly preferred embodiments, the water is recycled from the product of the process. For example, a portion water present following completion of the reaction may be taken off as a side stream and recycled into the slurry.

Aqueous alcohol component

In certain embodiments of the invention, the slurry may contain one or more different aqueous alcohol/s. However, it is emphasised that the inclusion of alcohols is optional rather than a requirement. For example, it may be suitable or preferable to use an aqueous alcohol as the solvent when the organic matter used in the methods consists of or comprises a significant amount of lignocellulosic material and/or other materials such rubber and plastics due to the stronger chemical bonds in these types of organic matter.

Suitable alcohols may comprise between one and about ten carbon atoms. Non- limiting examples of suitable alcohols include methanol, ethanol, isopropyl alcohol, isobutyl alcohol, pentyl alcohol, hexanol and iso-hexanol. The slurry may comprise more than about 5 wt%, 10 wt%, 15 wt%, 20 wt%, 25 wt%, 30 wt%, 35 wt%, 40 wt%, 45 wt% or 50 wt% alcohol aqueous alcohol.

In certain embodiments, the solvent comprises a mixture of two or more aqueous alcohols. Preferably, the alcohol is ethanol, methanol or a mixture thereof.

Catalysts

In certain embodiments of the invention, the production of biooil from the organic matter may be enhanced by the use of one or more additional catalysts. Although some catalysts may be an intrinsic component of the organic matter (e.g. minerals), solvent (e.g. hydronium/hydroxide ions of water, compound/s in the oil), and/or vessel walls of a reactor apparatus in which the organic matter may be treated (e.g. transition/noble metals), the invention contemplates the use of additional catalyst(s) to enhance the production of biooil from the organic material.

Accordingly, certain embodiments of the invention relate to the production of biooil from the organic matter by treatment with an aqueous solvent under conditions of increased temperature and pressure in the presence of at least one additional catalyst. By "additional catalyst" it will be understood that the catalyst is supplementary to catalytic compounds intrinsically present in the organic matter, oil-containing solvent and/or walls of a reactor apparatus.

For example, an embodiment of the invention in which the organic feedstock is treated with an aqueous solvent under elevated temperature and pressure in a reactor apparatus would not be considered to utilise an "additional catalyst".

In contrast, an embodiment of the invention in which a feedstock is treated with an aqueous solvent in the presence of a supplementary base catalyst (e.g. sodium hydroxide) under conditions of elevated temperature and pressure in a reactor apparatus would be considered to utilise an "additional catalyst".

Although the use of additional catalyst/s may be advantageous in certain circumstances, the skilled addressee will recognise that the biooils may be produced from the organic matter without using additional catalysts.

An additional catalyst as contemplated herein may be any catalyst that enhances the formation of biooil from the organic matter, non-limiting examples of which include base catalysts, acid catalysts, alkali metal hydroxide catalysts, transition metal hydroxide catalysts, alkali metal formate catalysts, transition metal formate catalysts, reactive carboxylic acid catalysts, transition metal catalysts, sulphide catalysts, noble metal catalysts, water-gas-shift catalysts, and combinations thereof. Suitable catalysts are described, for example, in PCT publication number (WO 201 1 123897) entitled "Methods for biofuel production", the entire contents of which are incorporated herein by reference.

The optimal quantity of an additional catalyst used to produce the biooil from the organic matter may depend on a variety of different factors including, for example, the type of organic matter under treatment, the volume of organic matter under treatment, the solvent utilised, the specific temperature and pressure employed during the reaction, the type of catalyst and the desired properties of the biooil product. The optimal quantity of an additional catalyst to be used can be determined by one skilled in the art without inventive effort.

In certain embodiments, an additional catalyst or combination of additional catalysts may be used in an amount of between about 0.1% and about 10% w/v catalysts, between about 0.1 % and about 7.5% w/v catalysts, between about 0.1 % and about 5% w/v catalysts, between about 0.1% and about 2.5% w/v catalysts, between about 0.1% and about 1% w/v catalysts, or between about 0.1% and about 0.5% w/v catalysts (in relation to the solvent).

In general, the catalysts may be used to create or assist in forming and/or maintaining a reducing environment favouring the conversion of organic matter to biofuel. The reducing environment may favour hydrolysis of the organic matter, drive the replacement of oxygen with hydrogen, and/or stabilise the biooil formed.

Treatment under subcritical conditions (as opposed to supercritical conditions) may be advantageous in that less energy is required to perform the methods and reaction components may better preserved during treatment. When subcritical conditions are utilised it is contemplated that the additional use of one or more catalysts may be particularly beneficial in increasing the yield and/or quality of the biooil. Further, the cost benefits of reduced input energy (i.e. to maintain subcritical rather than supercritical conditions) and preservation of the solvent may significantly outweigh the extra cost incurred by additionally including one or more of the catalysts described herein.

It is contemplated that under conditions of increased temperature and pressure water molecules in the solvent may dissociate into acidic (hydronium) and basic (hydroxide) ions facilitating hydrolysis of solid matter under treatment (i.e. solid to liquid transformation). In certain embodiments, the temperature and pressure at which the reaction is performed may be sufficiently high for desired levels of hydrolysis to occur without the use of additional catalysts. In other cases, the temperature and pressure at which the reaction is performed may not be sufficiently high for desired levels of hydrolysis to occur without the further addition of catalysts. The additional catalysts may be hydrolysis catalysts. In certain embodiments, the hydrolysis catalysts may be base catalysts. Any suitable base catalyst may be used.

Non-limiting examples of suitable base catalysts for hydrolysis include alkali metal salts, transition metal salts, organic bases, and mixtures thereof.

The alkali metal salts or transition metal salts may comprise any inorganic anion(s), non-limiting examples of which include sulfate, sulfite, sulfide, disulfide, phosphate, aluminate, nitrate, nitrite, silicate, hydroxide, methoxide, ethoxide, alkoxide, carbonate and oxide.

Preferred alkali metal or transition metal salts are sodium, potassium, iron, calcium and barium salts, and may comprise one or more anions selected from phosphate, aluminate, silicate, hydroxide, methoxide, ethoxide, carbonate, sulphate, sulphide, disulphide and oxide.

Non-limiting examples of suitable organic bases include ammonia, basic and polar amino-acids (e.g. lysine, histidine, arginine), benzathin, benzimidazole, betaine, cinchonidine, cinchonine, diethylamine, diisopropylethylamine, ethanolamine, ethylenediamine, imidazole, methyl amine, N-methylguanidine, N-mefhylmorpholine, N- methylpiperidine, phosphazene bases, picoline, piperazine, procain, pyridine, quinidine, quinoline, trialkylamine, tributylamine, triethyl amine, trimethylamine and mixtures thereof.

In certain embodiments, the hydrolysis catalysts may be acid catalysts although it will be recognised that acid catalysts may generally slower in catalysing hydrolysis of the organic matter than base catalysts. Any suitable acid catalyst may be used.

Non-limiting examples of suitable acid catalysts for hydrolysis include liquid mineral acids, organic acids, and mixtures thereof. The liquid mineral acids and organic acids may comprise any inorganic anion(s), non-limiting examples of which include aluminate, sulphate, sulphite, sulphide, phosphate, phosphite, nitrate, nitrite, silicate, hydroxide and alkoxide (under supercritical or near supercritical conditions), carbonate and carboxy group anions.

Non-limiting examples of suitable organic acids include acetic acid, butyric acid, caproic acid, citric acid, formic acid, glycolic acid, 3- hydroxypropionic acid, lactic acid, oxalic acid propionic acid, succinic acid, uric acid, and mixtures thereof.

In certain embodiments, the acid catalyst(s) for hydrolysis may be present in minerals of the organic matter and/or derived from the in situ formation of carboxylic acids and/or phenolics during the treatment process. In certain embodiments of the invention, a mixture of one or more acid hydrolysis catalysts and one or more base hydrolysis catalysts may be used to enhance hydrolysis of solid matter under treatment.

Production of the biooils from the organic matter may use catalysts for hydrolysis of the organic matter (as discussed in the preceding paragraphs). Additionally or alternatively, catalysts that increase and/or accelerate the removal of oxygen (either directly or indirectly) from compounds in the organic matter under treatment may be used. The removal of oxygen may provide a number of advantageous effects such as, for example, increasing the energy content and stability of the biooil produced.

An acid catalyst may be used to enhance the removal of oxygen, for example, by dehydration (elimination) of water. Accordingly, in certain embodiments an acid catalyst may be used to enhance hydrolysis, and to enhance the removal of oxygen from organic matter under treatment.

Any suitable acid catalyst may be used to enhance oxygen removal. Non-limiting examples of suitable acid catalysts for oxygen removal include liquid mineral acids, organic acids, and mixtures thereof. The liquid mineral acids and organic acids may comprise any inorganic anion(s), non-limiting examples of which include aluminate, sulphate, sulphite, sulphide, phosphate, phosphite, nitrate, nitrite, silicate, hydroxide and alkoxide (under supercritical or near supercritical conditions), carbonate and carboxy group anions.

In certain embodiments alumino-silicates including hydrated forms (e.g. zeolites) may be used during conversion of the organic matter to assist in dehydration (elimination) of water.

Additionally or alternatively, the removal of oxygen may be enhanced by thermal means involving decarbonylation of, e.g. aldehydes (giving R₃C-H and CO gas) and decarboxylation of carboxylic acids in the material under treatment (giving R₃C-H and C0₂ gas). The speed of these reactions may be enhanced by the addition of acid and/or transition (noble) metal catalysts. Any suitable transition or noble metal may be used including those supported on solid acids. Non-limiting examples include Pt/Al₂0₃/Si0₂, Pd/Al₂0₃/Si0₂, Ni/Al₂0₃/Si0₂, and mixtures thereof.

Additionally or alternatively, a combined acid and hydrogenation catalyst may be used to enhance the removal of oxygen, for example, by hydrodeoxygenation (i.e. elimination of water (via acid component) and saturation of double bonds (via metal component)). Any suitable combined acid and hydrogenation catalyst may be used including those supported on solid acids. Non-limiting examples include Pt/Al₂0₃/Si0₂, Pd/Al₂0₃/Si0₂, Ni/Al₂0₃/Si0₂, NiO/Mo0₃, CoO/Mo0₃, NiO/W0₂, zeolites loaded with noble metals (e.g. ZSM-5, Beta, ITQ-2), and mixtures thereof.

Catalysts may be used that enhance hydrolysis of the organic matter under treatment, and/or that enhance the removal of oxygen from compounds in the organic matter (as discussed in the preceding paragraphs). Additionally or alternatively, catalysts that enhance the concentration of hydrogen (either directly or indirectly) into compounds of the organic matter under treatment may be used. The concentration of hydrogen may provide a number of advantageous effects such as, for example, increasing the energy content and stability of the biooil produced.

A transfer hydrogenation catalyst may be used to enhance the concentration of hydrogen into compounds of the organic matter under treatment, for example, by transfer hydrogenation or in situ hydrogen generation.

Any suitable transfer hydrogenation catalyst may be used to increase the concentration of hydrogen. Non-limiting examples of suitable transfer hydrogenation catalysts include alkali metal hydroxides (e.g. sodium hydroxide), transition metal hydroxides, alkali metal formates (e.g. sodium formate), transition metal formates, reactive carboxylic acids, transition or noble metals, and mixtures thereof.

In certain embodiments, an additional sodium hydroxide catalyst is utilised in the reaction mixture for converting the organic matter into biooil at a concentration of between about 0.1M and about 0.5M.

In other embodiments low-valent iron species catalysts (including their hydrides) are utilised for converting the organic matter into biooil, including iron zero homogeneous and heterogeneous species.

The alkali metal hydroxide or formate may comprise any suitable alkali metal. Preferred alkali metals include sodium, potassium, and mixtures thereof. The transition metal hydroxide or formate may comprise any suitable transition metal, preferred examples including Fe and Ru. The reactive carboxylic acid may be any suitable carboxylic acid, preferred examples including formic acid, acetic acid, and mixtures thereof. The transition or noble metal may be any suitable transition or noble metal, preferred examples including platinum, palladium, nickel, ruthenium, rhodium, and mixtures thereof. Additionally or alternatively, a transition metal catalyst may be used to enhance the concentration of hydrogen into organic matter under treatment, for example, by hydrogenation with H₂. Non-limiting examples of suitable transition metal catalysts for hydrogenation with H₂ include zero-valent metals (e.g. iron, platinum, palladium, and nickel), transition metal sulfides (e.g. iron sulfide (FeS, Fe_xS_y), and mixtures thereof.

Additionally or alternatively, a water gas shift catalyst may be used to enhance the concentration of hydrogen into organic matter under treatment (i.e. via a water-gas shift reaction). Any suitable water gas shift (WGS) catalyst may be used including, for example, transition metals, transition metal oxides, and mixtures thereof (e.g. magnetite, platinum-based WGS catalysts, finely divided copper and nickel).

Additionally or alternatively, the concentration of hydrogen into organic matter under treatment may be facilitated by in situ gasification (i.e. thermal catalysis). The in situ gasification may be enhanced by the addition transition metals. Any suitable transition metal may be used including, for example, those supported on solid acids (e.g. Pt/Al₂0₃/Si0₂, Pd/Al₂0 /Si0₂, Ni/Al₂0₃/Si0₂, and mixtures thereof), and transition metal sulphides (e.g. Fe_xS_y, FeS/Al₂0₃, FeS/Si0₂, FeS/Al₂0₃/Si0₂, and mixtures thereof). Table 1 below provides a summary of various exemplary catalysts that may be employed to convert the organic matter into the biooil and the corresponding reactions that they may catalyse.

Table 1

Hydrolysis Base catalysts Sub/superHydroxide ion

critical water in sub/super- critical water

All alkali and M = any alkali M = Na, K, Fe, Ca, transition metal or transition Ba

salts, both metal

cations and

anions can A = anions, A = aluminate, contribute. including: phosphate, silicate,

Include all aluminate, hydroxide, common sulphate, methoxide, inorganic anions sulphite, ethoxide

sulphide carbonate phosphate, sulphate phosphite sulphide nitrate, nitrite disulphide (FeS₂) silicate oxide hydroxide

alkoxide

carbonate

oxide

Any organic

base ammonia,

pyridine, etc.

Hydrolysis Acid catalysts Sub/superHydronium ion

(slower) critical water in sub/super- critical water

Any liquid HA, where Acids may form mineral or from the in-situ organic acid A = anions, formation of

including: carboxylic acids, aluminate, phenolics and the sulphate, presence of sulphite, minerals sulphide

phosphate,

phosphite

nitrate, nitrite

silicate

hydroxide

alkoxide

carbonate

carboxy group

Dehydration Acid catalysts Sub/super- Hydronium ion

(elimination) critical water in sub/super- critical water

including: carboxylic acids, aluminate, phenolics and the sulphate, presence of sulphite, minerals.

sulphide

phosphate, zeolites or phosphite alumino-silicates in nitrate, nitrite general may be silicate added

hydroxide

alkoxide

carbonate

carboxy group

Transfer Transfer All alkali and M = any alkali M = Na, K

Hydrogenation hydrogenation transition metal or transition

or in-situ H₂ catalysts hydroxides and metal

generation formates

All reactive A = hydroxide, A = hydroxide, carboxylic acids formate formate

formic, acetic All transition All transition M = Fe, Pd, Pd, Ni and noble metals and noble Ru Rh

metals

Decarboxylation Largely Acid and All transition Pt/Al₂03/Si0₂

thermal transition and noble Pd/Al₂0₃/Si0₂

(noble) metal metals Ni/Al₂0₃/Si0₂ cats have been supported on

reported to aid solid acids

the process

Decarbonylation Largely As for As for As for

thermal decarboxylation decarboxylation decarboxylation

In-situ Largely Transition supported Pt/Al₂0₃/Si0₂ gasification thermal metals transition Pd/Al₂0₃/Si0₂ metals Ni/Al₂0₃/Si0₂

Fe

sulphides Fe_xS_y

FeS/Al₂0₃

FeS/Si0₂

FeS/Al₂0₃/Si0₂

Water-Gas Shift WGS catalysts Standard WGS As per literature As per literature catalysts

Direct Transition Zero valent Fe, Pt, P, Ni as

Hydrogenation metals metals zero valent

with H₂

Sulphides FeS, Fe_xS_y

Hydrode- Combined Transition metal M = transition Pt/Al₂0₃/Si0₂ oxygenation acid and and solid acid metal Pd/Al₂0₃/Si0₂

hydrogenation Ni/Al₂0₃/Si0₂ catalyst A = acidic solid NiO/Mo0₃

NiO/W0₂ zeolites loaded with noble metals, e.g. ZSM-5, Beta, ITQ-2

Catalysts for use in treating the organic matter to produce the biooil can be produced using chemical methods known in the art and/or purchased from commercial sources.

It will be understood that no particular limitation exists regarding the timing at which the additional catalyst(s) may be applied when treating the organic matter to produce the biooil. For example, the catalyst(s) may be added to the organic matter, solvent, or a mixture of the same (e.g. a slurry) before heating/pressurisation to target reaction temperature and pressure, during heating/pressurisation to target reaction temperature and pressure, and/or after reaction temperature and pressure are reached. The timing of catalyst addition may depend on the reactivity of the organic matter feedstock utilised. For example, highly reactive organic matter feedstocks may benefit from catalyst addition close to or at the target reaction temperature and pressure, whereas less reactive organic matter feedstocks may have a broader process window for catalyst addition (i.e. the catalysts may be added prior to reaching target reaction temperature and pressure).

Oil component

In some embodiments of the invention, a slurry comprising the organic matter for conversion into the biooil also comprises organic matter mixed with oil (e.g. an oil-based solvent). The oil may be additional to any oil present in the organic matter used to produce the biooil. The oil may be any suitable oil, non-limiting examples of which include paraffmic oil, gas-oil, crude oil, synthetic oil, coal-oil, bio-oil, shale oil/kerogen oil, aromatic oils (i.e. single or multi-ringed components or mixtures thereof), ether extractables, hexane extractables and any mixture of any of the previous components. The oil may be incorporated into the slurry mixture at any point before target reaction temperature and/or pressure are reached. For example, the oil may be added to the slurry in a slurry mixing tank. Additionally or alternatively, the oil may be added to the slurry en route to a reactor and/or during heating/pressurisation of the slurry.

In particularly preferred embodiments, the oil is the bio-oil recycled after production from the organic matter. For example, a portion of the bio-oil produced may be taken off as a side stream and recycled into the slurry.

No particular limitation exists regarding the proportion of oil in a slurry comprising the organic matter for conversion into the biooil. For example, the slurry may comprise more than about 2 wt% oil, more than about 5wt% oil, more than about 10wt% oil, or more than about 20, 30, 40, 50, 60 or 70wt% oil. Alternatively, the slurry may comprise less than about 98 wt% oil, less than about 95wt% oil, less than about 90 wt% oil, or less than about 80, 70, 60, 50, 40 or 30 wt% oil.

In some preferred embodiments, the slurry comprises between about 40wt% and about 50 wt% oil. In other preferred embodiments, the slurry comprises about 45wt% oil.

In other preferred embodiments the slurry comprises a feedstock to oil ratio of 0.5- 1.2: 1. The oil may be paraffinic oil.

Reaction conditions

The specific conditions of temperature and pressure used when hydrothermally converting the organic matter into biooil may depend on a number different factors including, for example, the type of organic matter under treatment, the physical form of the organic matter under treatment, the relative proportions of components in the reaction mixture (e.g. the proportion of solvent, water, oil, organic matter and any other additional component/s such as, for example, catalyst/s and/or alcohol/s), the types of catalyst(s) utilised (if present), the retention time, and/or the type of apparatus in which the methods are performed. These and other factors may be varied in order to optimise a given set of conditions so as to maximise the yield and/or reduce the processing time. In preferred embodiments, all or substantially all of the organic material used as a feedstock is converted into biooil.

Desired reaction conditions may be achieved, for example, by conducting the reaction in a suitable apparatus (e.g. a sub/supercritical reactor apparatus) capable of maintaining increased temperature and increased pressure.

Temperature and Pressure

When treating the organic matter to produce the biooil, a reaction mixture is provided and treated at a target temperature and pressure for a fixed time period ("retention time"). The temperature and/or pressure required to drive conversion of organic material into biooil will depend on a number of factors including the type of organic matter under treatment and the relative proportions of components in the reaction mixture under treatment (e.g. the proportion of solvent, water, oil, organic matter and any other additional component/s such as, for example, catalyst/s and/or alcohol/s). It will be recognised that various catalysts as described herein (see sub-section above entitled "Cato/ysfc") may be used to increase the efficiency of reactions which may in turn reduce the temperature and/or pressure required to drive conversion of the organic matter to the biooil. The skilled addressee can readily determine appropriate reaction temperature and pressure for a given reaction mixture. For example, the optimal reaction temperature and/or pressure for a given feedstock slurry may be readily determined by the skilled addressee by preparing and running a series of reactions that differ only by temperature and/or pressure utilised and analysing the yield and/or quality of biooil produced.

The skilled addressee will also recognise that the pressure utilised is a function of the slurry components and pressure drop, induced by the slurry, and strongly dependent on any particular reactor design (e.g. pipe diameter and/or length etc.).

In certain embodiments, treatment of the organic matter to produce the biooil using the methods of the invention may be conducted at temperature(s) of between about 150°C and about 550°C and pressure(s) of between about 10 bar and about 400 bar. Preferably, the reaction mixture is maintained at temperature(s) of between about 150°C and about 500°C and pressure(s) of between about 80 bar and about 350 bar. More preferably the reaction mixture is maintained at temperature(s) of between about 180°C and about 400°C and pressure(s) of between about 100 bar and about 330 bar. Still more preferably the reaction mixture is maintained at temperature(s) of between about 200°C and about 380°C and pressure(s) of between about 120 bar and about 250 bar.

In particularly preferred embodiments, the reaction mixture is maintained at temperature(s) of between about 200°C and about 400°C, and pressure(s) of between about 100 bar and about 300 bar.

In other particularly preferred embodiments, the reaction mixture is maintained at temperature(s) of between about 250°C and about 380°C, and pressure(s) of between about 50 bar and about 300 bar.

In other particularly preferred embodiments, the reaction mixture is maintained at temperature(s) of between about 320°C and about 360°C and pressure(s) of between about 150 bar and about 250 bar. In other particularly preferred embodiments, the reaction mixture is maintained at temperature(s) of between about 330°C and about 350°C and pressure(s) of between about 230 bar and about 250 bar. In another particularly preferred embodiment, the reaction mixture is maintained at temperature(s) of about 340°C and pressure(s) of between about 240 bar.

In certain embodiments, the reaction mixture is maintained at temperature(s) of above about 180°C and pressure(s) above about 150 bar. In other embodiments, the reaction mixture is maintained at temperature(s) of above about 200°C and pressure(s) above about 180 bar. In additional embodiments, reaction mixture is maintained at temperature(s) of above about 250°C and pressure(s) above about 200 bar. In other embodiments, the treatment is performed at temperature(s) of above about 300°C and pressure(s) above about 250 bar. In other embodiments, reaction mixture is maintained at temperature(s) of above about 350°C and pressure(s) above about 300 bar.

It will be understood that in certain embodiments the solvent used to convert the organic matter into the biooil may be heated and pressurised beyond its critical temperature and/or beyond its critical pressure (i.e. beyond the 'critical point' of the solvent). Accordingly, the aqueous solvent may be a 'supercritical' solvent if heated and pressurised beyond the 'critical point' of the solvent.

In certain embodiments the solvent used to convert the organic matter into the biooil may be heated and pressurised to level(s) below its critical temperature and pressure (i.e. below the 'critical point' of the solvent). Accordingly, the solvent may be a 'subcritical' solvent if its maximum temperature and/or maximum pressure is below that of its 'critical point'. Preferably, the 'subcriticaP solvent is heated and/or pressurised to level(s) approaching the 'critical point' of the solvent (e.g. between about 10°C to about 50°C below the critical temperature and/or between about 10 atmospheres to about 50 atmospheres below its critical pressure).

In some embodiments, the solvent used to convert the organic matter into the biooil may be heated and pressurised to levels both above and below its critical temperature and pressure (i.e. heated and/or pressurised both above and below the 'critical point' of the solvent at different times). Accordingly, the solvent may oscillate between 'subcritical' and 'supercritical' states.

Retention time

The specific time period over which the organic matter is converted into the biooil may be achieved upon reaching a target temperature and pressure (i.e. the "retention time") may depend on a number different factors including, for example, the type of aqueous solvent used, the percentage of alcohol (if present) in the solvent, the oil content (if any) the type of organic matter under treatment, the physical form of the organic matter under treatment, the types of catalyst(s) (if present) in the mixture and their various concentration(s), and/or the type of apparatus in which the methods are performed. These and other factors may be varied in order to optimise a given method so as to maximise the yield and/or reduce the processing time. Preferably, the retention time is sufficient to convert all or substantially all of the organic material used as a feedstock into biooil.

In certain embodiments, the retention time is less than about 60 minutes, 45 minutes, 30 minutes, 25 minutes, 20 minutes, 15 minutes, 10 minutes or less than about 5 minutes. In certain embodiments, the retention time is more than about 60 minutes, 45 minutes, 30 minutes, 25 minutes, 20 minutes, 15 minutes, 10 minutes or more than about 5 minutes. In other embodiments, the retention time is between about 1 minute and about 60 minutes. In additional embodiments, the retention time is between about 5 minutes and about 45 minutes, between about 5 minutes and about 35 minutes, between about 10 minutes and about 35 minutes, or between about 15 minutes and about 30 minutes. In further embodiments, the retention time is between about 20 minutes and about 30 minutes.

Persons skilled in the art will recognised that various catalysts as described herein (see sub-section below entitled "Catalysts") may be used to increase the efficiency of the treatment which may in turn reduce the retention time required to convert the organic matter into biooil. Similarly, the retention time required will be influenced by the proportions of various components in the reaction mixture (e.g. water, oil, alcohol catalyst/s etc.).

The optimal retention time for a given set of reaction conditions as described herein may be readily determined by the skilled addressee by preparing and running a series of reactions that differ only by the retention time, and analysing the yield and/or quality of biooil produced.

Heating/cooling, pressurisation/de-pressurisation

A reaction mixture (e.g. in the form of a slurry) comprising organic matter, aqueous solvent, optionally oil, and optionally one or more catalysts as defined herein may be brought to a target temperature and pressure (i.e. the temperature/pressure maintained for the "retention time") over a given time period.

Reaction mixes that do not contain a significant proportion of oil may require a very fast initial conversion to generate some solvent in-situ. However, the incorporation of oil into the reaction mixture as described herein allows the oil to act as a solvent thus alleviating the requirement for rapid heating/pressurisation.

In continuous flow systems, pressure will generally change from atmospheric to target pressure during the time it takes to cross the pump (i.e. close to instantaneous) whereas in a batch system it will mirror the time that it takes to heat the mixture up.

In some embodiments, the reaction mixture may be brought to a target temperature and/or pressure in a time period of between about 30 seconds and about 30 minutes.

In some embodiments, the reaction mixture may be brought to a target temperature and/or pressure in a time period less than about 15 minutes, less than about 10 minutes, less than about 5 minutes, or less than about 2 minutes.

In certain embodiments, the reaction mixture may be brought to a target pressure substantially instantaneously and brought to a target temperature in less than about 20 minutes, less than about 10 minutes, or less than about 5 minutes. In other embodiments, the reaction mixture may be brought to a target pressure substantially instantaneously and brought to a target temperature in less than about two minutes. In other embodiments, the reaction mixture may be brought to a target pressure substantially instantaneously and brought to a target temperature in between about 1 and about 2 minutes.

Additionally or alternatively, following completion of the retention time period the reaction mixture may be cooled to between about 150°C and about 200°C, between about 160°C and about 200°C, preferably between about 170°C and about 190°C, and more preferably about 180°C, in a time period of less than about 10 minutes, preferably less than about 7 minutes, more preferably less than about 6 minutes, preferably between about 4 and about 6 minutes, and more preferably about 5 minutes. Following the initial cooling period, the temperature may further reduced to ambient temperature with concurrent de-pressurisation by fast release into a cool aqueous medium (e.g. cooled water).

The processes of heating/pressurisation and cooling/de-pressurisation may be facilitated by performing the methods of the invention in a continuous flow system (see section below entitled "Continuous flow").

Continuous flow

Biooil production from the organic matter may be assisted by performing the conversion under conditions of continuous flow.

Although the conversion need not be performed under conditions of continuous flow, doing so may provide a number of advantageous effects. For example, continuous flow may facilitate the accelerated implementation and/or removal of heat and/or pressure applied to the slurry. This may assist in achieving the desired rates of mass and heat transfer, heating/cooling and/or pressurisation/de-pressurisation. Continuous flow may also allow the retention time to be tightly controlled. Without limitation to a particular mode of action, it is postulated that the increased speed of heating/cooling and/or pressurisation/de-pressurisation facilitated by continuous flow conditions along with the capacity to tightly regulate retention time assists in preventing the occurrence of undesirable side -reactions (e.g. polymerisation) as the slurry heats/pressurises and/or cools/de-pressurises. Continuous flow is also believed to enhance reactions responsible for conversion of the organic matter to biooil by virtue of generating mixing and shear forces believed to aid in emulsification which may be an important mechanism involved in the transport and "storage" of the oils generated away from the reactive surfaces of the feedstock as well as providing interface surface area for so-called Όη-water catalysis'.

Accordingly, in preferred embodiments the methods of the invention are performed under conditions of continuous flow. As used herein, the term "continuous flow" refers to a process wherein the organic matter mixed treated in the form of a slurry is subjected to:

(a) heating and pressurisation to a target temperature and pressure,

(b) treatment at target temperature(s) and pressure(s) for a defined time period (i.e. the "retention time"), and

(c) cooling and de-pressurisation, while the slurry is maintained in a stream of continuous movement along the length (or partial length) of a given surface. It will be understood that "continuous flow" conditions as contemplated herein are defined by a starting point of heating and pressurisation (i.e. (a) above) and by an end point of cooling and de-pressurisation (i.e. (c) above).

Continuous flow conditions as contemplated herein imply no particular limitation regarding flow velocity of the slurry provided that it is maintained in a stream of continuous movement.

Preferably, the minimum (volume-independent) flow velocity of the slurry along a given surface exceeds the settling velocity of solid matter within the slurry (i.e. the terminal velocity at which a suspended particle having a density greater than the surrounding solution moves (by gravity) towards the bottom of the stream of slurry).

For example, the minimum flow velocity of the slurry may be above about 0.01 cm/s, above about 0.05 cm/s, preferably above about 0.5 cm/s and more preferably above about 1.5 cm/s. The upper flow velocity may be influenced by factors such as the volumetric flow rate and/or retention time. This in turn may be influenced by the components of a particular reactor apparatus utilised to maintain conditions of continuous flow.

Continuous flow conditions may be facilitated, for example, by performing the methods of the invention in a suitable reactor apparatus. A suitable reactor apparatus will generally comprise heating/cooling, pressurising/de-pressuring and reaction components in which a continuous stream of slurry is maintained.

The use of a suitable flow velocity (under conditions of continuous flow) may be advantageous in preventing scale-formation along the length of a particular surface that the slurry moves along (e.g. vessel walls of a reactor apparatus) and/or generating an effective mixing regime for efficient heat transfer into and within the slurry.

Biooil products

Biooils produced by hydrothermal conversion of the organic matter may comprise a number of advantageous features, non-limiting examples of which include reduced oxygen content, increased hydrogen content, increased energy content and increased stability. In addition, bio-oils produced by hydrothermal conversion of the organic matter may comprise a single oil phase containing the liquefaction product. The product may be separated from the oil phase using, for example, centrifugation eliminating the need to evaporate large amounts of water. Biooil dissolved in the aqueous phase may optionally be recovered by means such as evaporation of water or adsorption on, for example, ionic or non-ionic resin media, and added to the water-insoluble bio-oil.

The biooil may comprise an energy content of greater than about 25 MJ/kg, greater than about 30 MJ/kg, more preferably greater than about 32 MJ/kg, more preferably greater than about 35 MJ/kg, still more preferably greater than about 37 MJ/kg, 38 MJ/kg or 39 MJ/kg, and most preferably above about 41 MJ/kg. The bio-oil product may comprise less than about 15%wt dry basis (db) oxygen, preferably less than about 10% wt db oxygen, more preferably less than about 8% wt db oxygen and still more preferably less than about 7% wt db oxygen, and preferably less than about 5% wt db oxygen. The bio-oil product may comprise greater than about 6% wt db hydrogen, preferably greater than about 7% wt db hydrogen, more preferably greater than about 8% wt db hydrogen, and still more preferably greater than about 9% wt db hydrogen. The molar hydrogen: carbon ratio of a bio-oil of the invention may be less than about 1.5, less than about 1.4, less than about 1.3, or less than about 1.2.

In some embodiments, the biooil may comprise an energy content of between about 32 MJ/kg and about 38 MJ/kg (e.g. about 36 MJ/kg to about 37 MJ/kg), and an oxygen content of between about 9% wt and about 13% wt (e.g. about 1 1% wt).

The bio-oil may comprise, for example, any one or more of the following classes of compounds: phenols, aromatic and aliphatic acids, ketones, aldehydes, hydrocarbons, alcohols, esters, ethers, furans, furfurals, terpenes, polycyclics, oligo- and polymers of each of the aforementioned classes, plant sterols, modified plant sterols, asphaltenes, pre- asphaltenes, and waxes.

Table 2 below describes various and non-limiting hydrothermal processing conditions and features of the biooils produced by hydrothermal treatment of the organic matter. These are applicable to any form of organic matter, including, but not limited to lignocellulosic biomass, microalgae, macroalgae, lignin, cellulose, hemicellulose, lignite, peat, primary sludge, activated sludge, softwood biomass, bagasse, wheat straw, oil palm, and in general any biomass used for oil production. Table 2

Table 3 below also provides exemplary and non-limiting features of biooils produced by hydrothermal treatment of lignocellulosic matter, with comparison made to crude oil and pyrolysis oils.

^Pyrolysis oils are unstable with respect to removal of water, therefore comparisons on a dry basis are difficult to make.

Hydrothermal conversion of the organic matter into biooil may produce other additional biofuel products. This will depend on the specific nature of the organic matter feedstock under hydrothermal treatment.

In certain embodiments, the product may comprise bio-oil, in addition to any one or more of oil char (e.g. carbon char with bound oils), gaseous product (e.g. methane, hydrogen, carbon monoxide and/or carbon dioxide), alcohol (e.g. ethanol, methanol and the like), and biodiesel.

In certain embodiments, a biofuel may be produced from fossilised organic matter such as, for example, lignite (brown coal), peat or oil shale. The biofuel may comprise solid, liquid and gas phases. The solid phase may comprise a high carbon char (upgraded PCI equivalent coal). The liquid phase may comprise biooil. The gaseous product may comprise methane, hydrogen, carbon monoxide and/or carbon dioxide.

In other embodiments, a biofuel may be produced from organic matter comprising lignocellulosic matter. The biofuel may comprise a liquid phase comprising biooil. Upgrading/Refining Hydrothermally-Produced Biooil

According to the methods of the present invention, hydrothermally-produced biooil may be upgraded (i.e. refined) into higher-value fuel products and/or chemicals.

In general, the hydrothermally-produced biooils are upgraded or refined using one or more of hydroprocessing, hydrotreating, hydrocracking, and/or catalytic cracking.

Non-limiting and exemplary methods for upgrading/refining the hydrothermally- produced biooils are described below.

Exemplary Method #1: Hydrotreatment of Biooil

In accordance with the methods of the present invention, biooil produced by the hydrothermal treatment of organic matter can be upgraded/refined into higher-value fuel products and/or chemicals.

Certain aspects of the present invention relate to processing the hydrothermally- produced biooil by hydrotreatment.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrotreating and not subjected to hydrocracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrotreating before hydrocracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrocracking before hydrotreating.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrotreating then hydrocracking then hydrotreating.

Hydrothermal production of biooil

Biooil for use in the catalytic cracking methods may be produced from a hydrothermal process, using one or several biomass-based feedstocks.

By way of non-limiting example only, the biooil may be produced from any organic matter feedstock or combination thereof set out in the section above entitled "Organic Matter".

By way of non-limiting example only, the biooil may be produced from the organic matter feedstock according to any of the processes described above in the section entitled "Biooil Production from Organic Matter" . Fractionation ofbiooil

By way of non-limiting example only, the hydrothermally-produced biooil may be fractionated before hydrotreating. This is not however a requirement.

Any suitable fractionation process may be used, non-limiting examples of which include vacuum distillation, solvent fractionation (e.g. where the selective solubility of bio-oil components in selected solvents is used as a means of fractionation), and pyrolytic distillation. Different fractions of the biooil may be hydroprocessed under different conditions.

Figures 1 and 2 show non-limiting and exemplary processing schemes related to the invention. Although not required, it may be advantageous to fractionate the biooil 100 or a mixture of biooil 100 and additive 1 10 before the hydrotreating step, yielding an aqueous fraction 200, a distillate stream 300 and a residue stream 400. Fractionation process 10 can be achieved by known methods in the art, for example, by vacuum distillation. The distillation can be carried out in a manner that maximises distillate yield.

Hydrotreatment

The biooil, biooil distillate or fraction/s thereof may be fed into a hydrotreatment reactor 20. The hydrotreatment can be carried out in a single reactor 20 as shown in Figure 1. Hydrotreatment may be carried out in a multibed reactor or in multiple reactors in a series. Optionally, the reaction products from one reactor can be fractionated before feeding into a subsequent reactor in the series. In particular, as described in Figure 2, it may be advantageous to separate the hydrotreated stream 500 from the first hydrogenation reactor 20 in the separation device 30. The hydrotreated stream 500 can be separated into a non-aqueous fraction 600 and an aqueous fraction 700. Aqueous fraction 700 may comprise essentially water with a small amount of dissolved organic products. The non-aqueous fraction 600 may then fed into a second hydrotreating reactor 40, where it can be further upgraded yielding stream 800.

The hydrotreating reactors can be fixed beds, with a number of different stacked beds within the reactor. In the case of using several reactors, each reactor may be filled with different catalysts. Bed configuration optimisation is known to persons skilled in the art. In some embodiments, it may be desirable to provide to the first hydrotreating reactor 20 a guard bed 21 to retain heavy material with high coking tendency before the biooil distillate stream 300 contacts with hydrotreating catalyst 22. Alumina may be a suitable material for the guard bed 21. Suitable hydrotreating catalysts are known to persons skilled in the art and may comprise one or several metals, for example, selected from the group of Ni, Co, Mo, and W. The metals may, in some embodiments, be in the form of metal sulphide.

The metals (e.g. metal sulphides) may be supported on an inorganic oxide such as, for example, alumina, silica, silicon carbide, zirconia, titania, niobium oxide, magnesia, alumina-magnesia with hydrotalcite or spinel structure, molecular sieves or any combination thereof. Dopants such as P, B may be added to the catalyst formulation.

Additionally or alternatively, the catalysts may comprise one or several precious metals, for example, selected from the group of Pt, Pd, Rh, and Ir. This may be desirable particularly when a multistep configuration is used. In the case of a multistep configuration, it may be advantageous to hydrodeoxygenate and hydrodesulphurise the feed in a first step, for example, in reactor 20 as shown in Figure 2, using non-precious metals as active catalysts. Following this, in a second step such as in reactor 40 shown in Figure 2, further upgrading (e.g. aromatic saturation and/or ring opening) can be carried out, using a catalyst that may contain one or several the aforementioned precious metals.

Hydrotreatment of the biooil, biooil distillate, or fraction/s thereof may be carried out at a temperature of, for example, 280°C to 380°C (e.g. 320 °C to 380°C). Space velocity may range from 0.1 to 10 h^"1, preferably 0.3 to 2 h^"1. The pressure may between 20 bar and 120 bar (e.g. 40 bar to 120 bar).

Operating conditions for hydrotreatment of the biooil may be selected depending on the specific purpose.

Lower pressure/lower temperature treatment (i.e. cheaper treatment) may be used to an upgraded product constituted essentially of hydrocarbons, with reduced content of oxygen, for example, below 2 wt% of oxygen, to for use in further upgrading, for example, in a petroleum refinery. Properties of the hydrotreated biooil (e.g. hydrotreated biooil distillate) may facilitate its co-processing with petroleum stream/s such as diesel without significant changes to the refinery process.

Higher pressure/higher temperature treatment may be used to obtain a more significantly upgraded product comprising very low oxygen or being substantially free of oxygen (e.g. an oxygen content below 0.2 wt%), as well as a reduced amount of aromatics and polyaromatics, and very low sulphur and nitrogen or being substantially free of sulphur and nitrogen. Additionally or alternatively, the liquid product density and/or boiling point range may be close to or within road diesel fuel specifications such as those described in EN590, such that the hydrotreated biooil, biooil distillate, or fraction/s thereof may be blended with a diesel stream for direct use as road diesel.

Products

Referring again to Figure 2, following hydrotreatment an aqueous stream 700 and a non-aqueous stream 800 can be obtained. The non-aqueous stream 800 may have a low oxygen content than the biooil prior to the hydrotreatment, with oxygen content less than 5 wt%, less than 4 wt%, less than 3 wt%, less than 2 wt%, less than 1 wt%, or less than 0.5 wt%. The hydrotreated product can thus be fully compatible with petroleum streams such as middle distillate streams. The hydrotreated product 800 depicted in Figure 2 can be further fractionated into naphtha and a diesel stream. Additionally or alternatively, the hydroprocessed product 800 can be fractionated into naphtha, kerosene and a diesel stream. The kerosene stream may represent more than 50% of the stream 800. The kerosene stream from hydrotreated stream 800 may present a content of polyaromatics of less than 3 wt% and an aromatic content less than 25%, making it suitable for use as jet fuel or as a jet fuel blending component. The kerosene stream may be dearomatized to obtain higher quality kerosene (high density, non-aromatic kerosene for special applications, e.g. military). The diesel stream from hydrotreated stream 800 may have a poly-aromatic content between 2-11 wt%>, and a total aromatic content of less than 35 wt%, making it suitable for use as road diesel or as a blending component for road diesel.

Exemplary Method #2: Hydrotreating and/or Hydrocracking of Biooil

Certain aspects of the present invention relate to processing the hydrothermally- produced biooil by hydrotreatment and/or by hydrocracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrocracking and not subjected to hydrotreating.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrocracking before hydrotreating. Hydrothermal production of biooil

By way of non-limiting example only, the biooil may be produced from any organic matter feedstock or combination thereof set out in the section above entitled "Organic Matter ".

By way of non-limiting example only, the biooil may be produced from the organic matter feedstock according to any of the processes described above in the section entitled "Biooil Production from Organic Matter ".

Fractionation of biooil

By way of non-limiting example only, the hydrothermally-produced biooil may be fractionated before hydroprocessing (i.e. hydrotreating and/or hydrocracking). This is not however a requirement.

Any suitable fractionation process may be used, non-limiting examples of which include vacuum distillation and pyrolytic distillation. Different fractions of the biooil may be hydroprocessed under different conditions.

Referring to Figure 3 and without any particular limitation on the process, it may be advantageous to fractionate the biooil 100 before commencing hydroprocessing yielding, for example, an aqueous fraction 200 (comprising predominantly water left over from the hydrothermal biooil production process), a distillate stream 300 (comprising biooil (atmospheric equivalent boiling point (AEBP) range of approximately 100°C to 550°C) including a middle distillate stream having an AEBP of less than about 360°C and a heavy distillate stream having an AEBP of more than about 360°C), and a residue stream 400 (comprising material with higher boiling points (e.g. above 550°C AEBP)). While it is possible to treat residue stream 400 together with distillate stream 300 in hydroprocessing stage/s (e.g. hydrotreatment and/or hydrocracking), doing so may in some cases result in reduced solubility of the biooil in hydrocarbon streams, and coking during hydroprocessing (i.e. during hydrotreating and/or hydrocracking). Accordingly, in some embodiments residue and distillate may be separated into different streams and subjected to hydroprocessing (i.e. hydrotreating and/or hydrocracking) separately under different conditions. Significant amounts of water can in some cases be detrimental to the stability of hydroprocessing catalyst/s. Accordingly, in some embodiments it may be advisable to limit the amount of water present when performing hydroprocessing step/s by removing water from the biooil and/or removing water from one or more fraction/s derived from the biooil (e.g. the residues stream and/or the distillate stream).

Optional fractionation process 10 may be performed by any suitable means (e.g. vacuum distillation and/or pyrolytic distillation). For example, if vacuum distillation is used, the pressure could range from 10 millibar to 200 millibar absolute pressure (e.g. 20 millibar) and the maximum temperature may be 280°C, 290°C, 300°C, 310°C, 320°C, 330°C, 340°C, 350°C, or 360°C. Additionally or alternatively, the distillation may be performed in a manner that maximises distillate yield, for example, by promoting pyrolysis of the heavier fraction of the biooil. The pyrolytic distillation may be performed under vacuum, at or close to atmospheric pressure, or for example in the range of 10 millibar to 5 bar absolute pressure. By way of non-limiting example, the temperature reached in the pyrolytic distillation process may be a maximum of 350°C, 360°C, 370°C, 380°C, 390°C, 400°C, 410°C, 420°C, 430°C, 440°C, 450°C, 460°C, 470°C, 480°C, 490°C, or 500°C (e.g. between 450°C and 550°C).

In some embodiments the biooil can be further fractionated into at least one light fraction containing gasoline and diesel boiling range components, and a heavier fraction comprising a 10% distillation point above 300°C, a 10% distillation point above 320°C, and/or a 10% distillation point above 340°C.

Hydrotreatment and/or hydrocracking

Figure 3 shows an exemplary biooil hydroprocessing scheme according to some embodiments of the present invention.

Regardless of whether or not the hydrothermally-produced biooil or biooil distillate is subjected to fractionation, it may be fed into a hydroprocessing reactor (i.e. a single reactor facilitating hydrotreatment and hydrocracking) or a series of reactors collectively facilitating hydrotreatment and hydrocracking. Accordingly, the hydroprocessing can be carried out in a single reactor, in a multibed reactor, in multiple reactors in series (e.g. hydrotreatment reactor 20 and hydrocracking reactor 40), or in a combination of thereof. Optionally, the reaction products from a hydrotreating reactor 20 can be fractionated before feeding into a hydrocracking reactor 40. For example, as described in Figure 3, the hydroprocessed stream 500 from the first hydrotreating reactor 20 may be separated in a separation device 30 into a non-aqueous light distillate fraction 600, a non-aqueous heavy distillate fraction 610, and an aqueous fraction 700. Aqueous fraction 700 may be constituted essentially of water with a small amount of dissolved organic products. The non-aqueous light distillate fraction 600 may be fed into a second hydrotreating/dearomatization reactor 40, where it may be further upgraded yielding product 800. The non-aqueous heavy distillate fraction 610 may be fed into a second hydrotreating/hydrocracking reactor 50, where it may be further upgraded yielding product 810.

Dearomatization of hydrocarbon-containing material such as, for example, hydrotreated biooil and/or kerosene produced according to the methods described herein may be accomplished by any means known in the art. For example it may be dearomatized by further hydroprocessing using, for example, noble metal catalysts such as Pt, Pd, Ir, Rh, and Ru or combinations thereof at temperatures of 170 to 370 °C with hydrogen pressures of 35 to 80 bar and space velocities of 1 to 5 h^"1. The further hydroprocessing may have the objective, for example, of fully hydrogenating unsaturated and aromatic structures to yield a high density, high energy jet fuel. A non-limiting example of a commercial process for light cycle oil (LCO) dearomatization is the UOP Unisar process. Aditionally or alternatively, dearomatization may be accomplished by solvent extraction of the aromatics with glycols (e.g. diethylene glycol, triethylene glycol, tetraethylene glycol), and/or amines (e.g. N-methyl pyrrolidinone, N-formylmorpholine), and/or Sulphur containing solvents (e.g. dimethylsulphoxide, tetramethylenesulphone). Water and other co-solvents may be added to modify the behaviour of the main solvent. Non-limiting examples of commercial processes for dearomatization of light hydrocarbon fractions include Udex (Dow-UOP), Sulfolane (Shell-UOP), Aerosolvan (Lurgi), Tetra (Union Carbide), Morphylex (Krupp-Koppers) and DMSO (IFP). Examplary methods for dearomitization are described, for example, in Petroleum Refining. Vol. 2 Separation Processes, J.P. Wauquier , Publisher: IFP Editions Technip (August 23, 2000), ISBN- 13 978-2710807612.

The hydroprocessing reactors (e.g. hydrotreating reactor 20 or hydrocracking reactor 40) may, in some cases, be fixed beds with a number of different stacked beds within the reactor. In the case of using several reactors, each reactor may be filled with different catalysts. Bed configuration optimisation is well known to persons skilled in the relevant art. By way of non-limiting example, first hydrotreating reactor 20 may comprise a guard bed 21 to retain heavy material with high coking tendency before the biooil distillate stream 300 contacts with hydrotreating catalyst 22. Alumina may be a suitable material for guard bed. Suitable hydroprocessing (e.g. hydrotreating and/or hydrocracking) catalysts for use in the present invention are known to people skilled in the relevant art and may comprise, for example, one or several metals from the group of Ni, Co, Mo, W (e.g. in the form of metal, metal sulphide or metal phosphide). The hydroprocessing catalysts may also comprise one or several of the following elements: Fe, Cu, V, Cr, Mn, and in some embodiments they may be provided in combination with at least one of the former group. Metal, metal sulphide or metal phosphide may be supported on an inorganic oxide such as alumina, silica, silicon carbide, zirconia, sulphated zirconia, titania, ceria niobium oxide, magnesia, alumina-magnesia with hydrotalcite or spinel structure, molecular sieves and mixtures thereof. Dopants such as P, B may be added to the catalyst formulations. The catalysts may also contain one or several precious metal from the group of Pt, Pd, Rh, Ir, Re, Au or a mixture of them, particularly if a multistep configuration is used. In the case of multistep operation, it may be favourable to remove most of the oxygen, sulphur and/or nitrogen present in the feed in a first step, for example in reactor 20 in figure 2, using non-precious metals as active catalysts. Then, in a second step, such as reactor 40, further upgrading such as aromatic saturation and/or ring opening can be carried out, using a catalyst that may contain one or several precious metals.

Referring again to Figure 3, the hydrocracking 40 may be carried out at any suitable reaction temperature (e.g. 350 °C to 450°C, 380 °C to 425°C). The space velocity may range from 0.1 to 10 h^"1, (e.g. from 0.3 to 1 h^"1). The hydrocracking may be carried out at a pressure of 80 to 250 bars (e.g. 100 to 150 bars).

The hydrocracking conditions may be chosen so as to ensure complete or near complete deoxygenation of the biooil, biooil distillate, or fraction/s thereof.

Additionally or alternatively, hydrocracking conditions may be chosen to minimise the amount of material boiling above the normal boiling range of diesel fuel in the product stream 800. Additionally or alternatively, the hydrocracking conditions may be chosen to adjust the properties of product stream 800 as close as possible the automotive fuel specifications for gasoline and diesel road fuels as described for example in EN228 and EN590 specifications.

In some embodiments the biooil, biooil distillate, or fraction/s thereof may be subjected to hydro treatment followed by hydrocracking. For example, in some embodiments, the hydrothermally-produced biooil/biooil distillate, or fraction/s thereof may be treated in a series of several reactors performing different operations. Referring to Figure 3, the biooil/biooil distillate, or fraction/s thereof, may be hydrotreated (e.g. substantially deoxygenated, desulphurised, etc.) in hydrotreating reactor 20. The hydrotreated biooil/biooil distillate, or fraction/s thereof may then be fed into the hydrocracking reactor 40. In one embodiment, light and heavy fractions of the hydrotreated biooil/biooil distillate may be separated, and only the heavier fraction then subjected to hydrocracking in hydrocracking reactor 40.

In other embodiments, the biooil, biodistillate, or fraction/s thereof can be used in the hydrocracking methods in their entirety without prior hydrotreatment. For example, the hydrothermally-produced biooil, biooil distillate, or fraction/s thereof may be fed directly into hydrocracking reactor 40 without prior processing in hydrotreating reactor 20. If unfractionated biooil or biodistillate is used in the hydrocracking methods, the lighter fraction of the biooil/biodistillate may be deoxygenated while the heavier fraction of the biooil/biodistillate may be deoxygenated and cracked into lighter products, and thereby yield a favourable proportion of components boiling in the gasoline or diesel range.

Additionally or alternatively, different fractions of the biooil or biooil distillate may be separated (e.g. depending on their boiling point range such as, for example, a light biooil distillate and a heavy biooil distillate), and the light biooil/biooil distillate fraction may be treated in a separate process, with less severe operating conditions. Such a process may include hydrotreatment (e.g. in a gasoil desulphurisation unit) yielding, for example, deoxygenated gasoline and diesel-range molecules. The heavy biooil/biooil distillate fraction may be fed into the hydrocracking process of the invention.

Products

As shown in Figure 3 the hydroprocessed (i.e. hydrotreated and/or hydrocracked) product stream 800 (i.e. refined/upgraded biooil) may have an oxygen content below, for example: 5wt%, 4wt%, 3wt%, 2wt%, lwt%, 0.5wt%, or 0.2 wt%. Additionally or alternatively, the polyaromatics and aromatic content of the stream 800 may be lower than 15wt% and 60wt% respectively, lower than 10wt% and 50wt% respectively, or lower than 3 wt% and 30wt% respectively. Additionally or alternatively, the density of the stream 800 may be lower than 0.90 (e.g. lower than 0.88). Additionally or alternatively, the hydroprocessed stream 800 may have a sulphur content below lOppm.

The hydroprocessed product stream 800 may be further fractionated into a naphtha and a diesel stream. Alternatively, the hydroprocessed product stream 800 may be fractionated into a naphtha, a kerosene and a diesel stream. The kerosene stream may, for example, represent more than 50% of the stream 800. The kerosene stream from hydroprocessed stream 800 may comprise content of polyaromatics below 3wt% and an aromatic content below 25%, making it suitable for use as jet fuel or as a jet fuel blending component. A diesel stream generated from hydroprocessed stream 800 may have a poly- aromatic content below 2-l lwt%, and a total aromatic content below 35wt%, making it suitable for use as road diesel or as a blending component for road diesel.

Exemplary Method #3: Hydrotreating and/or Catalytic Cracking of Biooil

Certain aspects of the present invention relate to processing the hydrothermally- produced biooil by hydrotreatment and/or by catalytic cracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrotreating and catalytic cracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrotreating before hydrocracking. By way of non-limiting example only, the hydrotreating can be performed according to any of the processes described above in the section entitled "Hydrotreatment of biooil" .

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to hydrotreating followed by hydrocracking then catalytic cracking, or hydrotreating followed by catalytic cracking then hydrocracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be fractionated before hydroprocessing (i.e. hydrotreating and/or hydrocracking and/or catalytic cracking). Any suitable fractionation process may be used, non-limiting examples of which include vacuum distillation and pyrolytic distillation. Different fractions of the biooil may be hydroprocessed under different conditions. Hydrothermal production of biooil

Fractionation of biooil

By way of non-limiting example only, the hydrothermally-produced biooil or biooil distillate may be fractionated before hydrotreating and/or catalytically cracking the biooil/biooil distillate. This is not however a requirement.

Fractionating the hydrothermally-produced biooil/biooil distillate may provide an aqueous fraction, a distillate fraction and a residue fraction. Any suitable fractionation process may be used, non-limiting examples of which include vacuum distillation and pyrolytic distillation. The distillation may be carried out in a way that maximises distillation yield, for example, by promoting to some extent pyrolysis of the heavier and residual fractions of the biooil/biooil distillate. Any residual fraction from the biooil/biooil distillate may be removed to minimise the coking tendency of the feed. Additionally or alternatively, the amount of water in the biooil/biooil distillate may be minimised to in turn minimise potential damage to catalysts and/or the lowering of hydrogen partial pressure in subsequent treatment stage/s (e.g. hydrotreatment and/or catalytic cracking as applicable).

Hydrotreatment

By way of non-limiting example only, the hydrothermally-produced biooil or biooil distillate may be subjected to hydrotreating prior to catalytic cracking.

The biooil, biooil distillate, or fraction/s thereof may be fed into a hydroprocessing reactor. The hydrotreating can be carried out in a single reactor with a single bed of catalyst, in a multibed reactor, or in a series of multiple reactors. When using multiple reactors, effluent from the first reactor maybe fractionated before feeding into the following reactor for example, to remove water and other components such as CO or C0₂ formed during the hydrodeoxygenation of the biooil, biooil distillate, or fraction/s thereof.

The hydrotreating reactor/s may be fixed beds, with a number of different stacked beds within the reactor. In the case of using several reactors, each reactor may be filled with different catalysts. Bed configuration optimisation is known by persons skilled in the relevant art. In some embodiments, a first hydrotreating reactor may comprise a guard bed to retain heavy material with high coking tendency before the biooil, biooil distillate, or fraction/s thereof contacts with hydrotreating catalyst. Alumina may be a suitable material for guard bed.

Suitable hydrotreating catalysts are known to people skilled in the relevant art and may comprise one or several metals from the group of Nickel (Ni), Cobalt (Co), Molybdenum (Mo), Tungsten (W), for example, in the form of metal sulphide or metal phosphide. Hydroprocessing catalysts may also comprise one or several of the following elements: Iron (Fe), Copper (Cu), Vanadium (V), Chromium (Cr), Manganese (Mn), preferentially in combination with at least one of the former group. Metals or metal sulphides or metal phosphides may be supported on an inorganic oxide such as, for example, alumina, silica, silicon carbide, zirconia, titania, ceria, niobium oxide, magnesia, alumina-magnesia with hydrotalcite or spinel structure, molecular sieves and mixtures thereof. Dopants such as P, B may be added to the catalyst formulation. Catalyst may also contain one or several precious metal from the group of Platinum (Pt), Palladium (Pd), Rhodium (Rh), Iridium (Ir), Rhenium (Re), Gold (Au) or a mixture of them, especially in the case that a multistep configuration is used. In the case of a multistep operation, the feed may be hydrodeoxygenated and/or hydrodesulphurised in a first step/reactor using, for example, non-precious metals as active catalysts. Following this further upgrading in a second step/reactor such as, for example, aromatic saturation and/or ring opening can be carried out using, for example, a catalyst that may contain one or several precious metals.

The hydrotreating may be carried out under relatively mild conditions, for example, at a temperature of 280°C to 380°C (e.g. 320 °C to 380°C), and/or a space velocity from 0.1 to 10 h^"1 (e.g. 0.3 to 2 h^"1), and/or a pressure between 20 and 100 bars (e.g. 30 to 80 bars).

The hydrotreated liquid may have a reduced oxygen content. In one embodiment of the invention, the hydroprocessed liquid may have an oxygen content below, for example: 5wt%, 4wt%, 3wt%, 2wt%, lwt%, 0.5wt%, or 0.2 wt%. The hydrotreated stream may comprise a high percentage of hydrocarbons. The hydroprocessed stream may contain number of saturated polycyclic components of the abietane family. As a consequence of the high amount of hydrocarbons, water may separate readily from the hydrotreated liquid product. The latter may then be fractionated into distillates (e.g. gasoline, kerosene, diesel) and heavy oil fractions. The distillates may be mixed with mineral oil streams of similar boiling point range and may be further processed to yield fuels. The heavy oil fraction may be characterised as having a 10 wt% boiling point above 300°C (e.g. 320°C or 340°C). While some applications as low value fuel may exist for such a fraction, it may be processed further to yield more gasoline, kerosene and diesel fuels, as well as chemicals of interest such as propylene and butenes.

Catalytic cracking

The heavy oil fraction from the biooil distillate hydroprocessing may then be catalytically cracked.

By way of non-limiting example, the catalytic cracking may be carried out at an existing Fluid Catalytic Cracking Unit (FCCU). The FCCU may be suitable for upgrading of conventional crude oil. The FCCU may be in a petroleum refinery.

In some embodiments, the heavy oil fraction may be subjected to catalytic cracking as a component of a larger feedstock (e.g. a FCCU feed). Additionally or alternatively, the heavy oil fraction (e.g. after hydroprocessing) may be subjected to catalytic cracking in a mixture with one or more of: mineral oil/s (e.g. gas oil, light gas oil, vacuum gas oil, atmospheric gas oil, straight run gas oil, long residue, atmospheric residue, atmospheric bottoms, short residue, vacuum bottoms, vacuum residue, coker gas oil, heavy gas oil, or any combination thereof), atmospheric residues, vacuum residues, coker gas oils, and/or any known component of an FCCU feed. Additionally or alternatively, the heavy oil fraction (e.g. after hydroprocessing) may be subjected to catalytic cracking in a mixture with oxygenated feeds such as pyrolysis oils, hydrogenated pyrolysis oils, and/or vegetable oils.

In some embodiments, the catalytic cracking step may comprise contacting the heavy oil fraction with a regenerated cracking catalyst in the reaction zone of a FCCU. The regenerated catalyst may be provided at a temperature between 500°C and 800°C. The feed, comprising or consisting of the heavy oil fraction, may be preheated to temperatures of 150°C to 300°C. Contrary to some prior art, where special injection devices had to be used because the renewable component of the feed had limited thermal stability, the nature of the heavy oil fraction makes it suitable to use in the same way as hydrocarbon feed is used.

Catalytic cracking of the biooil, biooil distillate, or fraction/s thereof may be conducted at any suitable temperature. By way of non-limiting example, the reaction temperature at which catalytic cracking is performed may range from 500°C to 800°C, from 450°C to 650°C, or from 480°C to 550°C. Additionally or alternatively, the pressure ranges at which catalytic cracking is performed may range from 0.05 to IMPa (e.g. 0.1 to 0.3Mpa). Catalyst to oil ratio may be varied in a range that allow thermal balance of the unit. A typical catalyst to oil ratio may range from 2 to 20. Injection patterns for optimising the product slate are well known in the art and may, for example, comprise one or several, staged injections in a riser reactor (ascending flow). Alternatively, a part of the feed, or recycled streams from the process, may be processed in a parallel reactor under different processing conditions, for example higher temperature and catalyst to oil ratio. In such a variation, operating temperature can be in the range of 450°C -700°C (e.g. 500 °C to 600°C). Such configurations may be used for increasing the yield of small olefins. Alternatively, the reactor of the FCCU can be a downer rector (downward flow).

The catalyst/s used in the cracking methods may comprise any catalyst which is usually employed in the FCC technique. The catalysts may comprise a main catalytic component (e.g. a zeolite), and in some embodiments a series of additives that may include, for example, other zeolitic components and/or a matrix, and a binder. The binder may, for example, be kaolin. The main zeolitic component may be a large pore zeolite such as Y zeolite, which properties may be tuned by Rare-Earth exchange (REY), stabilisation through dealumination (USY), or a combination thereof (REUSY). Other suitable zeolitic materials may include X zeolite, beta zeolite, L zeolite, Omega zeolite, offretite, ITQ 21 zeolite. Zeolitic additive may include medium pore zeolite or zeotype such as ZSM5, ZSM12, ferrierite, SAPOl l in order to increase the production of propylene and butenes, decrease olefins in gasoline. The matrix may include an alumina or silica-alumina component aimed at improving the cracking of very large feed molecules. Other additives may be added such as Platinum to favour combustion in regenerator, and/or other materials to decrease sulphur oxides and nitrogen oxides generation during coke combustion in regenerator, or reduce sulphur content in cracked products, especially gasoline.

In some embodiments, the biooil heavy fraction may be cracked using catalysts in which the main cracking component is a Y zeolite tuned in a way that reduces hydrogen transfer reaction rate, for example, by having high silica to alumina ratio (lower cell size) and/or a reduced amount of rare earths.

After catalytic cracking, products may be segregated from the solid catalysts using any suitable separation device, for example, a set of cyclone and a stripper. Products are may then be entrained with steam into a fractionation zone, whereas the spent catalyst, stripped from volatile products, can be sent to a regenerator to burn any coke that may be deposited on it. The regenerated catalyst may then sent back to the reaction zone. The combustion of the coke, which is exothermic, may provide heat to the process that is transferred to the reaction zone using the solid catalyst as heat carrier. The amount of coke produced during the reaction is autothermal and may hence be controlled. An excessive amount of coke produced can lead to a decrease of the feed rate. It is believed that the nature of the biooil heavy component generated from the method described above is especially suited for this process compared to other oils from renewable origin as the amount of coke produced by the present feed, in any blend level with mineral oil may produce similar amounts of coke compared with feeding 100% mineral oil, so that little or no adaptation of the FCCU operating conditions may be necessary when processing a blend containing the biooil heavy component.

Exemplary Method #4: Catalytic Cracking of Biooil

In accordance with the methods of the present invention, biooil, biooil distillate, or fraction/s thereof produced by the hydro thermal treatment of organic matter can be upgraded/refined into higher-value fuel products and/or chemicals.

Certain aspects of the present invention relate to processing the hydrothermally- produced biooil by catalytic cracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to catalytic cracking without hydro treatment.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to catalytic cracking without hydrocracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to catalytic cracking without hydro treating and without hydrocracking.

By way of non-limiting example only, the hydrothermally-produced biooil may be subjected to catalytic cracking followed by hydrotreating and/or hydrocracking. Fractionation ofbiooil

By way of non-limiting example only, the hydrothermally-produced biooil or biooil distillate may be fractionated before catalytically cracking the biooil/biooil distillate. This is not however a requirement.

Fractionating the hydrothermally-produced biooil/biooil distillate may provide an aqueous fraction, a distillate fraction and a residue fraction. Any suitable fractionation process may be used, non-limiting examples of which include vacuum distillation and pyrolytic distillation. The distillation may be carried out in a way that maximises distillation yield, for example, by promoting to some extent pyrolysis of the heavier and residual fractions of the biooil/biooil distillate. Any residual fraction from the biooil/biooil distillate may be removed to minimise the coking tendency of the feed. Additionally or alternatively, the amount of water in the biooil/biooil distillate may be minimised during the refining step, and thus providing a feedstock that is substantially free of water. A certain amount of free water may be present in the biooil/biooil distillate as a consequence of a water wash aimed at removing, for example, traces of catalyst from the previous conversion step.

Catalytic cracking

The biooil, biooil distillate, or fraction/s thereof may be catalytically cracked.

In some embodiments, the biooil, biooil distillate, or any fraction/s thereof may be subjected to catalytic cracking as a component of a larger feedstock (e.g. a FCCU feed).

For example, the biooil, biooil distillate, or fraction/s thereof may be subjected to catalytic cracking in a mixture with one or more mineral oil/s (e.g. gas oil, light gas oil, vacuum gas oil, atmospheric gas oil, straight run gas oil, long residue, atmospheric residue, atmospheric bottoms, short residue, vacuum bottoms, vacuum residue, coker gas oil, heavy gas oil, or any combination thereof). It has been unexpectedly found that a small amount of biooil can be co-processed with mineral oil, without adversely impacting or perturbing FCC operation. This may be advantageous in commercial operation because it means that fuels and blendstocks such as gasoline and light cycle oil (LCO) containing a small but significant renewable component (e.g. 5-10 weight % renewable component) can be manufactured in existing/conventional oil refineries without altering the operational conditions of the FCC units in the refineries and without significantly affecting the operation of other refinery units and/or decreasing the intervals for catalyst regeneration or renewal/replacement. The mineral oil may be mixed with the biooil, biooil distillate or fraction/s thereof before feeding, or the materials can be fed separately the process (e.g. to a FCC unit) to be combined therein. The mixed materials may then be catalytically cracked (e.g. by feeding into or combining within a Fluid Catalytic Cracking unit). Catalytic cracking of the mixture may yield more distillate and/or other products of interest (e.g. small olefins). Oxygen in the biooil, biooil distillate, or fraction/s thereof may be removed (mainly as CO or C0₂) during the process.

Additionally or alternatively, the biooil, biooil distillate, or fraction/s thereof may be subjected to catalytic cracking in a mixture with atmospheric residues, vacuum residues, coker gas oils, and/or any known component of an FCCU feed.

Additionally or alternatively, the biooil, biooil distillate, or fraction/s thereof may be subjected to catalytic cracking in a mixture with oxygenated feeds such as pyrolysis oils, hydrogenated pyrolysis oils, and/or vegetable oils.

The biooil, biooil distillate, or fraction/s thereof may be component of a feedstock subjected to the catalytic cracking. The biooil, biooil distillate, or fraction/s thereof may constitute more than 5%, more than 10%, more than 15%, more than 20%, more than 25%, more than 30%>, more than 35%, more than 40%, more than 45%, more than 50%, more than 60%, more than 570%, of the feedstock.

In some embodiments, the catalytic cracking step may comprise contacting the biooil, biooil distillate, or fraction/s thereof with a regenerated cracking catalyst in the reaction zone of a FCCU. The regenerated catalyst may be provided at a temperature between 500°C and 800°C. The biooil, biooil distillate, or fraction/s thereof may be preheated to temperatures of 150°C to 300°C. Contrary to some prior art, where special injection devices had to be used because the renewable component of the feed had limited thermal stability, the nature of the biooil, biooil distillate, or fraction/s thereof makes them suitable to use in the same way as hydrocarbon feed is used.

Catalytic cracking of the biooil, biooil distillate, or fraction/s thereof may be conducted at any suitable temperature. By way of non-limiting example, the reaction temperature at which catalytic cracking is performed may range from 500°C to 800°C, from 450°C to 650°C, or from 480 °C to 550°C. Additionally or alternatively, the pressure ranges at which catalytic cracking is performed may range from 0.05 to IMPa (e.g. 0.1 to 0.3Mpa). Catalyst to oil ratio may be varied in a range that allow thermal balance of the unit. A typical catalyst to oil ratio may range from 2 to 20. Injection patterns for optimising the product slate are well known in the art and may, for example, comprise one or several, staged injections in a riser reactor (ascending flow). Alternatively, a part of the feed, or recycled streams from the process, may be processed in a parallel reactor under different processing conditions, for example higher temperature and catalyst to oil ratio. In such a variation, operating temperature can be in the range of 450°C -700°C (e.g. 500°C to 600°C). Such configurations may be used for increasing the yield of small olefins. Alternatively, the reactor of the FCCU can be a downer reactor (downward flow).

In some embodiments, the biooil, biooil distillate, or fraction/s thereof may be cracked using catalysts in which the main cracking component is a Y zeolite tuned in a way that reduces hydrogen transfer reaction rate, for example, by having high silica to alumina ratio (lower cell size) and/or a reduced amount of rare earths.

After catalytic cracking, products may be segregated from the solid catalysts using any suitable separation device, for example, a set of cyclone and a stripper. Products are may then be entrained with steam into a fractionation zone, whereas the spent catalyst, stripped from volatile products, can be sent to a regenerator to burn any coke that may be deposited on it. The regenerated catalyst may then sent back to the reaction zone. The combustion of the coke, which is exothermic, may provide heat to the process that is transferred to the reaction zone using the solid catalyst as heat carrier. The amount of coke produced during the reaction is autothermal and may hence be controlled. An excessive amount of coke produced can lead to a decrease of the feed rate. It is believed that the nature of the biooil, biooil distillate, or any fraction/s thereof generated from the method described above is especially suited for this process compared to other oils from renewable origin as the amount of coke produced by the present feed, in any blend level with mineral oil may produce similar amounts of coke compared with feeding 100% mineral oil, so that little or no adaptation of the FCCU operating conditions may be necessary when processing a blend containing the biooil, biooil distillate, or fraction/s thereof.

It will be appreciated by persons skilled in the art that numerous variations and/or modifications may be made to the invention as shown in the specific embodiments without departing from the spirit or scope of the invention as broadly described. The present embodiments are, therefore, to be considered in all respects as illustrative and not restrictive.

Examples

The present invention will now be described with reference to specific Examples, which should not be construed as in any way limiting.

Example 1: Hydrotreating biooil distillate obtained from hydrothermal treatment of lignocellulosic biomass (hydrotreating conditions #1)

A biooil was prepared from Pinus Radiata using a hydrothermal process. Briefly, the wood was milled to a maximum particle size of 150 to 500 microns and slurried with water to a consistency of up to 12% dry basis wood flour in water. The slurry was pressurised to approximately 240 bar using a high pressure slurry pump and then continuously pumped while being raised to a reaction temperature of between 320°C and 370°C using a combination of heating methods including electrical heating, counterflow heat-exchangers, and injection of supercritical water. Sodium hydroxide solution was injected after the slurry had been raised to reaction temperature using a high pressure dosing pump. The sodium hydroxide was added at a concentration of 8-14% of the wood by weight on a dry basis. The slurry was then pumped through insulated reaction vessels to give an overall residence time in the process at the reaction temperature of about 20-30 minutes. The reaction mixture was then cooled to about 100-120°C and then depressurised into a product tank. The biooil was recovered on standing as a heavier-than- water dark brown/black viscous oil insoluble in water. The water in contact with the biooil was at pH 7-9. The biooil was washed with water and then partly dried by decantation and/or passing a stream of nitrogen over a stirred vessel of the biooil at about 80°C. The biooil was subjected to a pyrolysis distillation in batch that yielded a distillate material and a residual fraction. The biooil distillate had the properties listed in Table 4 below. Oxygen content was measured by difference after Elemental Analysis for C, H, N and S. TAN was measured following ASTM D-664 guidelines.

Table 4

Biooil Distillate properties

C, wt% 78.5

H, wt% 8.9

N, wt% 0.2

S, wt% 0.0

O (by difference) , wt% 12.4

Density @152C 1.03

TAN (mg KOH/g) 9

The biooil distillate was then hydrotreated in a fixed bed with a NiMo catalyst supported on alumina. The catalyst was presulphided with a stream of 10% ¾S in ¾. Reactor temperature was 350°C, and total pressure 70 bars. 4 g of catalyst was loaded into the reactor, and feed rate of the biooil distillate was 4 grams per hour, so space velocity was 1 h^"1. Hydrogen fed to the reactor was 122 Nml/min, or approximately 16 wt% of feed or approximately 1900 scf per scf of feed. Gases were analyzed in a chromatograph so that Ci to C₄ yield could be determined. Liquids were weighed, and the aqueous fraction separated. The non-aqueous fraction was analyzed by Simulated Distillation and GCxGC technique so that boiling point distribution and aromatic distribution could be determined. Density was also measured following ASTM 5002 specifications. After 50 hours of operation, the yields at the output of the reactor were stable as shown in Table 5.

Table 5

Hydrotreated Biooil Distillate yields

Gases, wt% 2.2

C0₂ 0.1

methane 0.8

Ethane 0.1

LPG 1.1

Liquids, wt% 97.8

Gasoline (IBP-216) 28.1

Diesel (216-359) 49.9

Bottoms (359-FBP) 8.6

Water 11.2 Hydrocarbon liquid properties

Density @152C 0.901

Saturates 42.0

Monoaromatics 48.8

Polyaromatics 5.7

Polars 3.5

TAN of the product was below detection limit of the method used (0.1 mgKOH/g). Oxygen content of the hydrocarbon liquid was estimated to be below 2 wt%, probably below 1 wt%. Polyaromatic content was maintained below specifications limits for road diesel as defined by EN590.

Example 2: Hydrotreating biooil distillate obtained from hydro thermal treatment of lignocellulosic biomass (hydrotreating conditions #2)

A biooil was prepared from Pinus Radiata using a hydrothermal process, as per Example 1 above.

The same biooil distillate of Example 1 was treated with the same protocol but different reactor operating conditions. Reactor temperature was maintained at 350°C, but total pressure was lowered at 40 bars. Space velocity was reduced at 0.5 h-1 by halving the feed flow rate to 2 grams per hour. Hydrogen flow as reduced accordingly to 62 Nml/min or approximately 950 scf hydrogen per scf of feed. After 120 hours on stream yields pattern was found stable as shown in Table 6:

Table 6

Hydrotreated Biooil Distillate yields

Gases, wt% 2.0

C0₂ 0.1

methane 0.7

Ethane 0.2

LPG 0.9

Liquids, wt% 98.0

Gasoline (IBP-216) 28.9

Diesel (216-359) 49.58

Bottoms (359-FBP) 8.2

Water 11.4

Hydrocarbon liquid properties

Density @152C 0.9155

Saturates 40.1

Monoaromatics 44.6

Polyaromatics 10.7

Polars 4.6 Lowering the operation pressure was compensated by increasing contact time (lowering space velocity) and similar yield pattern was obtained compared with Example 1. Due to lower pressure the amount of aromatic increased, which increased the density of the whole liquid. The oxygen content of the product was measured indirectly by Elemental Analysis and was found below 2 wt%. TAN of the product was below detection limit of the method used (0.1 mgKOH/g). It has to be noted that the characteristics of the whole liquid may be compared favorably to a light Cycle Oil from Catalytic Cracking by people skilled in the art of refining. It is thus a feature of this invention that the hydroprocessed biooil distillate may be further processed or co- processed by a refiner with known refining technology by the people skilled in the art to yield a drop-in fuel stream.

Example 3: Hydrotreating biooil distillate obtained from hydrothermal treatment of lignocellulosic biomass (hydrotreating conditions #3)

The same biooil distillate of Example 1 was treated with the same protocol but different reactor operating conditions. Reactor temperature was maintained at 350°C, but total pressure was increased to 120 bars. Catalyst was a NiMo supported on silica- alumina. Catalyst preactivation, flows and space velocity were the same as in Example 1. After 30 hours on stream yield pattern was as shown in Table 7:

Table 7

Hydrotreated Biooil Distillate yields

Gases, wt% 1.9

C0₂ 0.2

methane 0.7

Ethane 0.1

LPG 0.9

Liquids, wt% 98.1

Gasoline (IBP-216) 33.6

Diesel (216-359) 52.5

Bottoms (359-FBP) 5.4

Water 6.7

Hydrocarbon liquid properties

Density @152C 0.8916

Saturates 56.6

Monoaromatics 41.9

Polyaromatics 1.2

Polars 0.3 Compared to Example 1, the higher pressure and different catalyst allowed to reduce the amount of material boiling above 359°C, yielding a liquid hydrocarbon product with a density below 0.9 and a content of saturates above 65 wt%. In particular, the amount of polyaromatics was reduced below 10 wt%, below the limits set by, for example, EN590 specification for diesel fuels. TAN of the product was below detection limit of the method used (0.1 mgKOH/g).

Example 4: Hydrotreating biooil distillate obtained from hydro thermal treatment of lignocellulosic biomass (hydrotreating conditions #4)

The same biooil distillate as in Example 1 was treated with the same protocol but different reactor operating conditions. Reactor temperature was maintained at 350°C, but total pressure was increased to 120 bars. Catalyst was a NiW supported on silica-alumina. Catalyst preactivation, flows and space velocity were the same as in Example 1. After 50 hours on stream yield pattern was as shown in Table 8:

Table 8

Hydrotreated Biooil Distillate yields

Gases, wt% 1.6

co₂ 0.2

methane 0.6

Ethane 0.1

LPG 0.7

Liquids, wt% 98.4

Gasoline (IBP-216) 32.5

Diesel (216-359) 49.3

Bottoms (359-FBP) 5.0

Water 11.7

Hydrocarbon liquid properties

Density @152C 0.8927

Saturates 63.7

Monoaromatics 30.9

Polyaromatics & polars 5.5

Compared to Example 1, the higher pressure and different catalyst allowed to reduce the amount of material boiling above 359°C, yielding a liquid hydrocarbon product with a density below 0.9 and a content of saturates above 60 wt%. In particular, the amount of polyaromatics was reduced below 10 wt%, below the limits set by, for example, EN590 specification for diesel fuels. As well, the oxygen content of the nonaqueous liquid stream was estimated to be below 2 wt%, and probably below 1 wt%. TAN of the product was below detection limit of the method used (0.1 mgKOH/g).

Example 5: Hydrotreating biooil middle distillate obtained from hydrothermal treatment of lignocellulosic biomass

The biooil was subjected to vacuum distillation that generated a biooil distillate and a Distillation residue. The biooil distillate was then further separated by distillation into two fractions: a biooil middle distillate (BMD) and a biooil heavy distillate (BHD). The biooil middle distillate had the properties listed in Table 9 below. Oxygen content was measured by Elemental Analysis. TAN was measured following ASTM D-664 guidelines.

Table 9

Biooil Middle Distillate properties

C, wt% 79.5

H, wt% 9.5

N, wt% 0.1

S, wt% 0.0

O (by difference) , wt% 10.8

Density @152C 1.04

TAN (mg KOH/g) 35

The biooil middle distillate was then hydrotreated in a fixed bed with a NiMo catalyst supporter on alumina. The catalyst was presulphided with a stream of 10% ¾S in H₂. Reactor temperature was 350°C, and total pressure 70 bars. 4 g of catalysts were loaded to the reactor, and feed rate of the biooil distillate was 4 grams per hour, so space velocity was 1 h^"1. Hydrogen fed to the reactor was 124 Nml/min, or approximately 16 wt% of feed or approximately 1900 scf per scf of feed. Gases were analyzed in a chromatograph so that Q to C₄ yield could be determined. Liquids were weighted, and the aqueous fraction separated. The non-aqueous fraction was analyzed by Simulated Distillation and GCxGC technique so that boiling point distribution and aromatic distribution could be determined. Density was also measured following ASTM 5002 specifications. After 50 hours of operation, the yields at the output of the reactor were as shown in Table 10:

Table 10

Hydrotreated Biooil Distillate yields

Gases, wt% 2.0

CO 0.3

C0₂ 0.5

methane 0.7

Ethane 0.1

LPG 0.4

Liquids, wt% 98.0

Gasoline (IBP-216) 26.1

Diesel (216-359) 57.2

Bottoms (359-FBP) 3.8

Water 10.7

Hydrocarbon liquid properties

Density @152C 0.9059

Saturates 48.0

Monoaromatics 48.0

Polyaromatics & polars 4.0

TAN of the product was below detection limit of the method used (0.1 mgKOH/g). As observed with the full biooil distillate of Example 1, polyaromatic content was maintained below specifications limits for road diesel as defined by EN590.

Example 6: Hydrotreating biooil heavy distillate obtained from hydrothermal treatment of lignocellulosic biomass

The biooil heavy distillate produced as in Example 5 was treated in an Autoclave at 150 bars total pressure, 350°C and 20 hours. 23g of biooil heavy distillate were treated. 5 wt% of a NiMo supported on alumina catalyst was loaded together with the feed. The catalyst was previously sulphided using a gas mixture of 10% H₂S in H₂ for 4 hours at 400°C.

After the test, gases were recovered in a gas bag and analyzed in a chromatograph so that d to C₄ yield could be determined. The mixture of liquids and solid catalyst was weighted, and then most of the oil was recovered. The remaining solid and liquid mixture was then separated through filtration and the solid was washed with hexane and methanol. Methanol/hexane filtrate was separated by decantation and water in methanol phase was determined by Karl Fisher. The non-aqueous oil fraction was analyzed by Simulated Distillation and GCxGC technique so that boiling point distribution and aromatic distribution could be determined. Density was also measured following ASTM 5002 specifications. Yields obtained from the hydrogenation are shown in Table 11 below. Hydrogen consumption was estimated at 4 wt% of the feed.

Table 11

Hydrotreated Biooil Distillate yields

Gases, wt% 10.0

CO 0.3

C0₂ 4.6

methane 2.4

Ethane 0.8

LPG 1.9

Liquids, wt% 90.0

Gasoline (IBP-216) 11.1

Diesel (216-359) 53.0

Bottoms (359-FBP) 16.9

Water 8.5

Coke, wt% 0.4

Hydrocarbon liquid properties

Density @152C 0.9425 Example 7: Hydrotreating biooil distillate obtained from hydro thermal treatment of macroalgae

A biooil from macroalgae was produced through a hydrothermal process. The Biooil was subjected to a vacuum distillation that yielded a distillate material and a residual fraction. The biooil distillate had the properties listed in the Table 12 below, Oxygen content was measured by Elemental Analysis. TAN was measured following ASTM D-664 guidelines.

Table 12

Biooil Distillate properties

C, wt% 76.0

H, wt% 11.3

N, wt% 1.3

S, wt% 0.0

O (by difference) , wt% 11.4

Density @15^qC 0.9365

TAN (mg KOH/g) This biooil distillate was then treated in an autoclave at 90 bars total pressure, 350°C and 20 hours. 45.2g of biooil distillate were loaded together with 5 wt% of a NiMo supported on alumina catalyst. The catalyst was previously sulphided using a gas mixture of 10% H₂S in H₂ for 4 hours at 400°C.

After the test, gases were recovered in a gas bag and analyzed in a chromatograph so that Ci to C₄ yield could be determined. The mixture of liquids and solid catalyst was weighted, and then most of the oil was recovered. The remaining solid and liquid mixture was then separated through filtration and the solid was washed with hexane and methanol. Methanol/hexane filtrate was separated by decantation and water in methanol phase was determined by Karl Fisher. The non-aqueous oil fraction was analyzed by Simulated Distillation. Density was also measured following ASTM 5002 specifications. Yields obtained from the hydrogenation are shown in Table 13 below. Hydrogen consumption was estimated at 3 wt% of the feed.

Table 13

Hydrotreated Biooil Distillate yields

Gases, wt% 5.9

CO 0.3

C0₂ 4.0

methane 0.5

Ethane 0.4

LPG 0.7

Liquids, wt% 94.1

Gasoline (IBP-216) 11.7

Diesel (216-359) 56.7

Bottoms (359-FBP) 20.8

Water 5.0

Hydrocarbon liquid properties

Density @152C 0.8504

TAN of the product was below detection limit of the method used (0.1 mgKOH/g). 70 wt% of the oxygen in the feed was recollected as water and Carbon oxides. Nitrogen content was measured at 0.5 wt% in the organic liquid phase by Elemental Analysis. Example 8: Hydrocracking biooil distillate obtained from hydrothermal treatment of lignocellulosic biomass

The biooil was subjected to a pyrolysis distillation in batch that yielded a distillate material and a residual fraction. The biooil distillate had the properties listed in Table 14 below. Oxygen content was measured by Elemental Analysis. TAN was measured following ASTM D-664 guidelines. SIMDIS was measured following ASTM-D2887.

Table 14

Biocrude Distillate properties

C, wt%

H, wt%

N, wt%

S, wt%

0 (by difference) , wt%

Density @155C

TAN (mg KOH/g)

SIMDIS

lbp-216°C

216-3595C

>3595C

ASTM D-1160 correlation (SIMDIS)

10%

30%

50%

70%

90%

The biooil distillate was then hydrocracked in a fixed bed with a NiW-type catalyst supported on silica-alumina. The catalyst was presulphided at 400°C with a stream of 10% H₂S in H₂. Reactor temperature was 380°C, and total pressure was maintained at 120 bars. 4 g of catalysts were loaded to the reactor, and feed rate of the biooil distillate was 4 grams per hour, so space velocity was 1 h-1. Hydrogen fed to the reactor was 100 Nml/min, or approximately 13.4 wt% of feed or approximately 1600 scf per scf of feed. Gases were analyzed in a chromatograph so that Ci to C₄ yield could be determined. Liquids were weighted, and the aqueous fraction separated. The non-aqueous fraction was analyzed by Simulated Distillation and GCxGC technique so that boiling point distribution and aromatic distribution could be determined. Density was also measured following ASTM 5002 specifications. After 50 hours of operation, the yields at the output of the reactor were stable and are summarized in the Table 15 below. TAN of the hydroprocessed liquid was below detection limit of the method used (0.1 mgKOH/g).

Table 15

Hydrotreated Biocrude Distillate yields

Gases, wt% 2.6

C0₂ 0.2

Methane 0.7

Ethane 0.3

LPG 1.4

Liquids, wt% 97.4

Gasoline (IBP-216) 38.2

Diesel (216-359) 42.9

Bottoms (359-FBP) 2.2

Water 14.1

Hydrocarbon liquid properties

Density @152C 0.878

Saturates 55.6

Monoaromatics 42.7

Polyaromatics 1.4

Polars 0.2

The hydroprocessed liquid contained essentially gasoline and diesel-range molecules, in similar amounts, while the amount of high boiling point material reduced from 25wt% to 2wt%. Oxygen in the feed was eliminated essentially in the form of water, indicating that under these reaction conditions hydrodehydration was much favored over hydrodecarboxylation as principal mechanism for deoxygenation. The amount of poly- aromatic and polar components in the liquid product was lowered to lwt%, which is below the limits for fuel specifications such as jet kerosene or road diesel fuel. A kerosene cut was defined as the sum of components boiling between 126 and 287°C (corresponding to the boiling points of n-octane and n-hexadecane respectively). Yield of kerosene after 50 hours on stream was found stable at 54 wt% of the biooil Distillate fed. It contained approximately 67 wt% saturates with 33 wt% mono-aromatics compounds, while the total amount of poly-aromatics compounds and polar compounds remained below 0.2 wt%.

Example 9: Hydrocracking biooil distillate obtained from hydrothermal treatment of macroalgae

A biooil from macroalgae was produced through a hydrothermal process.

The biooil was subjected to a vacuum distillation that yielded a distillate material and a residual fraction. The biooil distillate had the properties listed in the Table 16 below. Oxygen content was measured by Elemental Analysis. SIMDIS was determined following ASTM D-2887 method. TAN was measured following ASTM D-664 guidelines.

Table 16

Biocrude Distillate properties

C, wt% 76.0

H, wt% 11.3

N, wt% 1.3

S, wt% 0.0

O (by difference) , wt% 11.4

Density @15^?C 0.9365

TAN (mg KOH/g) >100

SIMDIS (ASTM D-2887)

lbp-2165C 2.2

216-3592C 58.4

>359°C 39.4

This biooil distillate was then treated in an Autoclave at 120 bars total pressure, 380°C and 20 hours. 45. lg of biooil distillate were loaded together with 2.26g (5 wt% of biooil distillate) of a NiMo supported on alumina catalyst. The catalyst was previously sulphided using a gas mixture of 10% H₂S in H₂ for 4 hours at 400°C. After the test, gases were recovered in a gas bag and analyzed in a chromatograph so that Ci to C₄ yield could be determined. The mixture of liquids and solid catalyst was weighted, and then most of the oil was recovered. The remaining solid and liquid mixture was then separated through filtration and the solid was washed with hexane and methanol. Methanol/hexane filtrate was separated by decantation and water in methanol phase was determined by Karl Fisher. The non-aqueous oil fraction was analyzed by Simulated Distillation. Density of the oil fraction was also measured following ASTM 5002 specifications. Yields obtained from the hydrogenation are shown in the Table 17 below.

Hydrogen consumption was estimated at 3.6 wt% of the feed.

Table 17

Hydrotreated Biocrude Distillate yields

Gases, wt% 5.1

CO 0.2

C0₂ 3.0

methane 0.5

Ethane 0.5

LPG 0.9

Liquids, wt% 94.7

Gasoline (IBP-216) 17.0

Diesel (216-359) 56.6

Bottoms (359-FBP) 15.0

Water 6.1

Coke, wt% 0.2

Hydrocarbon liquid properties

Density @15^?C 0.8374

TAN of the product was below detection limit of the method used (0.1 mg KOH/g). 70wt% of the oxygen in the feed was recollected as water and Carbon oxides. Nitrogen content was measured at 0.1 wt% in the organic liquid phase by Elemental Analysis, which means a 95% denitrogenation ratio. The product density was found within the EN590 specifications for road diesel. Example 9: Catalytically cracking hydrotreated biooil distillate derived from hydrothermal treatment of lignocellulosic biomass

The biooil was subjected to a pyrolysis distillation in batch that yielded a distillate material and a residual fraction. The biooil distillate had the properties listed in the Table 18 below. Oxygen content was measured by Elemental Analysis. TAN was measured following ASTM D-664 guidelines.

Table 18

Biooil Distillate properties

C, wt% 78.5

H, wt% 8.9

N, wt% 0.2

S, wt% 0.0

O (by difference) , wt% 12.4

Density @152C 1.03

TAN (mg KOH/g) 9

The biooil distillate was then hydrotreated in a fixed bed with a NiMo catalyst supporter on alumina. The catalyst was presulphided with a stream of 10% ¾S in ¾. Reactor temperature was 350°C, and total pressure 40 bars. 4 g of catalysts were loaded to the reactor, and feed rate of the biooil distillate was 4 grams per hour, so space velocity was 1 h^"1. Hydrogen fed to the reactor was 122 Nml/min, or approximately 16 wt% of feed or approximately 1900 scf per scf of feed. Gases were analyzed in a chromatograph so that Ci to C₄ yield could be determined. Liquids were weighted, and the aqueous fraction separated. The non-aqueous fraction was analyzed by Simulated Distillation and GCxGC technique so that boiling point distribution and aromatic distribution could be determined. SIMDIS followed ASTM-D2887 specifications and cut points for the gasoline, LCO and Bottoms fractions are defined in the Table 19 below. Density was also measured following ASTM 5002 specifications. After 50 hours of operation, the yields at the output of the reactor were stable and were as follows: Table 19

Hydrotreated Biocrude Distillate yields

Gases, wt% 2.0

C0₂ 0.1

methane 0.7

Ethane 0.2

LPG 0.9

Liquids, wt% 98.0

Gasoline (IBP-216) 28.9

Diesel (216-359) 49.5

Bottoms (359-FBP) 8.2

Water 11.4

Hydrocarbon liquid properties

Density @15°C 0.9155

Saturates 40.1

Monoaromatics 44.6

Polyaromatics 10.7

Polars 4.6

After separating water, the hydroprocessed liquids were fractionated into a distillate 5 fraction (boiling point up to 340°C) and a biooil heavy fraction (Boiling point from 340°C). Biooil heavy fraction represented 16 wt% of the hydroprocessed liquids (excluding water) and its density was measured at 0.9948.

Catalytic cracking reactions were carried out in a Micro-Activity Test (MAT) unit using standard Vacuum Gas Oil (VGO) as reference feedstock. VGO properties are listed l o in the Table 20 below. Catalyst was a commercial Equilibrium catalyst.

Table 20

Vacuum Gas Oil properties

ASTM D-1160 (SIMDIS correl

5% 319

10% 352

30% 414

50% 436

70% 459

90% 512

Density @152C 0.91728

MCRT, wt% 0.3

Sulphur, wt% 1,65 Pure hydroprocessed biooil heavy fraction as well as mixtures with VGO at 10wt% and 30wt% were used as feed. SIMDIS of pure feeds as well as mixture is detailed in the Table 21 below. Reaction conditions were the following: 500°C reaction temperature, catalyst weight 3 g, catalyst to oil ratio (CTO) was varied between 2.0 and 5.0 g/g by changing the amount of feed introduced. The time on stream (TOS) was maintained constant at 30s, and the feed was pre-heated at 80°C. Conversion was defined as the sum of gas, gasoline and coke products, while total conversion also incorporated LCO yield.

Table 21

Heavies VGO + 30 wt% VGO + 10 wt% VGO

Cut point / Mixture

Heavies Heavies (base case)

IBP - 151.0 0.0 0.0 0.0 0

151.0 - 216.1 0.0 0.0 0.0 0.3

216.1 - 359.0 47.1 25.4 18.9 15.2

359.0 - FBP 52.9 74.5 81.1 84.4

The effect of blending hydroprocessed biooil heavy fraction into Vacuum Gas Oil can be seen in the Activity and selectivity plots of Figures 4 to 6.

Figure 4 shows the conversion and total conversion obtained with the different feed mixture by varying the catalyst to oil ratio. Incorporation of increasing amounts of hydroprocessed biooil heavy fraction resulted into a decrease in conversion, nearly linear with the amount of biooil heavy fraction blended into VGO (Figure 4). Total conversion was, however, similar with the different feed mixtures. This indicates that the diesel fraction obtained or already present in the hydroprocessed biooil heavy fraction do not crack well, at least at a significantly lower rate than vacuum gas oil. This may be an indication of an increase in diesel fraction aromaticity.

Figure 5 shows the selectivity to the main product obtained with the different feed mixture by varying the catalyst to oil ratio. It was preferred to plot selectivity against total conversion instead of classical conversion because of the large difference in LCO yield observed when processing biooil heavy fraction that would distort the selectivity results if not taken into account. Gas and gasoline selectivity decreased upon incorporation of hydrotreated biooil heavy fraction to VGO. Meanwhile, LCO selectivity increased, approximately linearly with the content of hydroprocessed biooil heavy fraction in the blend. Finally, coke selectivity was found similar for all the blends, which means that operating conditions in the FCC plant, especially catalyst to oil ratio, will not vary much if hydroprocessed biooil heavy fraction are incorporated in the VGO feed.

Figure 6 shows isobutene to isobutane ratio, a well-known hydrogen transfer indicator, which experimented a large decrease with increasing amounts of biooil heavy fraction in the feed blend. Lower ratio traditionally indicates enhanced hydrogen transfer. As coke yield was not much affected by the amount of biooil heavy fraction in the feed, hydrogen was transferred from another source, so it is probable that gasoline and LCO products to have an increased aromaticity.

Example 10: Catalytic cracking of biooil distillate obtained from hydrothermal treatment of lignocellulosic biomass

The biooil was distilled yielding a distillate material and a residual fraction. The boiling point curve of the distillate by simulated distillation is shown in Figure 7.

Operating conditions

Catalytic cracking reactions were carried out in a Micro-Activity Test (MAT) unit using vacuum gas oil (VGO) as reference feedstock. Reaction conditions were the following: 500 °C reaction temperature, catalyst weight 3 g, catalyst to oil ratio (CTO) was varied between 2.0 and 5.0 g/g by changing the amount of feed. The time on stream (TOS) was 30s and the feed was pre-heated at 80°C. Catalytic Cracking reactions were carried out with pure distillate, as well as with mixtures of vacuum gas oil (VGO) with 10 wt% and 30 wt% of distilled biooil.

Table 22 shows a distillation curve of the distilled biooil. Less HCO (359.0-FBP) and more LCO (216.1-359.0) fractions, with no significant changes in gasoline (IBP- 216.1), are observed when increasing the amount of biooil into the prepared blends (see Table 22). Blends were maintained at 70°C overnight until the reaction time in order to ensure adequate mixing.

Table 22

Cut point / Distilled biooil VGO + 30wt% VGO + 10wt% VGO (base Mixture Distilled Biooil Distilled Biooil case)

IBP - 151.0 0.0 0.0 0.0 0.0

151.0 - 216.1 3.1 0.8 0.4 0.3

216.1 - 359.0 44.6 23.4 17.8 15.2

359.0 - FBP 52.3 75.8 81.7 84.4 Conversion and selectivity comparisons.

Conversion was defined as the sum of gas, gasoline and coke products, while total conversion also incorporated LCO yield. A significant decrease in conversion was observed when cracking pure biooil distillate in comparison with pure VGO feed. No significant change in conversion but a slight increase in total conversion was observed when a 10 wt% biooil is incorporated into the VGO. The increase in the LCO fraction with the biooil could explain these results.

Overall, gases selectivity increases when increasing the biooil distillate content. This increase of gases selectivity is mainly due to the increase of dry gases selectivity, while LPG selectivity practically does not change. On the other hand, CO and C0₂ are logically produced when processing blends incorporating biooil distillate. Table 23 shows oxygen removal as CO and C0₂ during M. A.T. tests of biooil distillate and VGO blends. The amount of oxygen removed in form of CO and C0₂ is small and represent around 7wt% (see Table 23). Surprisingly, higher selectivity to CO than to C0₂ was obtained. These results could be due to the nature of oxygenated compounds in biooil. Moreover, due to the very low amount of oxygen in the feed, it was not possible to quantify water in the liquids and therefore to estimate the overall deoxygenation ratio.

Table 23

The increase of the biooil distillate on feed causes a continuous decrease of the gasoline and H.C.O. selectivity and an increase of the LCO selectivity. Increasing the amount of biooil into the processed feedstock increases the coke selectivity. Hydrogen transfer rate, estimated by the iso-butene to iso-butane ratio, decreases sharply when processing pure biooil distillates, but no significant changes are observed when incorporating limited amounts of biooil distillates (i.e. up to 30 wt.-%), indicating that the biooil distillates incorporation has low impact on hydrogen transfer rate of the VGO. Figure 8 shows conversion and selectivity parameters for the feeds in this Example.

Lower conversion and increased coke-on-catalyst have been observed for biooil distillate and blends compared to the VGO feed, with maximum coke yield for the blends, indicating some negative synergy between the two feeds. At low blend levels, that is, less than or equal to about 10wt% biooil in VGO, the coke on catalyst is expected to remain in workable range for an industrial FCC unit and conversion is not expected to be substantially affected.

Example 11: Catalytic cracking of biooil distillate obtained from hydrothermal treatment of lignocellulosic biomass

A biooil was prepared from Pinus Radiata using a hydrothermal process, as per Example 1 above, and distilled under vacuum to give a distillate. The biooil distillate was blended at 10% wt with a paraffinic VGO.

Experimental

The biooil distillate blended very well with the VGO at a level of 10 wt% biooil in blend. Before blending, both components were heated at 70°C in an oven (the VGO is viscous at room temperature). It seems probable that more concentrated blends in biooil could still be prepared. Some physicochemical properties of the VGO are listed in Table 24 below. This feed is usually classified as a paraffinic feed, and is easy to process in FCCU.

From the simulated distillation data of the biooil sample shown in Table 25 and Figure 9, it can be inferred that this cut has a boiling range mainly within the diesel/LCO fraction (within the limitations of SIMDIS related to oxygenated feeds). The amount of 359+°C material lowered 5 percentage points in the VGO-biooil blend compared to the VGO alone.

Table 25

Catalytic cracking of VGO and VGO-Biooil mixtures

Catalytic cracking was performed in a fixed bed, modified MAT unit. Operating conditions were fixed at 500°C, 30 seconds Time-On-Stream and Catalyst-to-Oil ratio in the range of 1.5 to 5 for VGO and 3 to 5 for VGO-biooil blends. Liquid products are recovered in traps and gases in a gas bag. Pressure in the reactor during the reaction was between 1.1 and 1.2 bar. After the reaction, a 15 minutes stripping at 50 ml/min is performed. Catalyst is regenerated with air at 540°C during 3 hours. The catalyst used in this study was a laboratory deactivated FCC microsphere catalyst with 1% Rare Earth. Gas samples were analysed by GC (refinery gas configuration) to determine the distribution of hydrocarbons, CO, C0₂, nitrogen and hydrogen. Nitrogen was used as internal standard to determine the total amount of gas recovered. Gasoline fraction in the gas is quantified but not completely separated into individual components. Recovered liquids are analysed by standard SIMDIS (ASTM D-3887) for boiling point distribution. Cuts were made at 216°C for gasoline and 359°C for diesel. Conversion was defined as the sum of gases (including dry gas), gasoline and coke yield.

The cracking activity and selectivity for the two feeds (as well as two additional feeds that were subjected to hydrotreating prior to catalytic cracking), and detailed gas composition, are shown in Figure 10. The hydrotreated samples were prepared by hydrotreating VGO and, separately a VGO plus 10 wt% biooil blend, in an autoclave using NiMo/alumina catalyst, 5 wt% catalyst in feed, at 350°C for 20h. From dark-brown feed, yellow, waxy products were recovered with both VGO and blend. Product density (0.86 g/ml) measured at 50°C was lower than that of the feeds (0.89 g/ml). VGO and VGO-biooil blend are represented by brown squares and purple triangles respectively. It could be observed that the blending of biooil into the VGO resulted in a slight decrease of the conversion. Yet the effect on the main product selectivity was more noticeable. Gasoline selectivity decreases significantly with the blending of Bio oil, while LCO, gas and coke yield increased correspondingly. This is a clear indication that the untreated biooil is more refractory to cracking than the VGO.

The blend also yielded higher yields of propylene, while butenes yields were similar. No significant amounts of C0₂ (<0.1 wt% or CO (<0.01 wt%) were produced during the processing of VGO-biooil blend, indicating that most of the deoxygenation occurs through dehydration or elimination of oxygenates though coking.

Example 12: Hydrotreating of biooil distillate obtained from hydrothermal treatment of lignocellulosic biomass as a mixture with straight run gas oil (SRGO)

A biooil was prepared by the hydrothermal treatment of Pinus Radiata as described in Example 1.

After separation by vacuum distillation, the resulting biooil distillate was extensively characterised. Elemental analysis of the biooil distillate (Table 26) showed a content of 0₂ around 12%, low N content, nearly zero S, and a C:H molar ratio of 1.36.

Table 26.

This product quality is much higher than common pyrolysis oil, where oxygen contents as high as 40% with H/C molar ratios close to 1.0 are commonly found. Simulated Distillation (SIMDIS) of this oily product was also performed. Although SIMDIS data of oxygen-containing streams cannot be compared directly with those of pure hydrocarbon streams, since the removal of oxygen will result in a shift to lower temperatures, it nevertheless gives an upper limit of the boiling point ranges in the sample. In our case this indicates that the biooil would be at least similar to a petroleum-based diesel stream, with 60% diesel-range products and 20% each of gasoline and heavy-range products. Consistent with the above discussion, it has to be noted that compared to a petroleum-based Vacuum Gas Oil (VGO), biooil heaviest components detected by chromatography are significantly lighter than the heavy end tail detected in VGO This biooil was subsequently hydrotreated in a fixed bed with a NiMo/alumina catalyst This type of catalyst is typically used for hydro-desulphurisation and/or hydrocracking of middle distillate and VGO feeds in petroleum industry. The catalyst was diluted with Silicon Carbide and presulphided before testing. Operating conditions were

5 350 °C and 70 bars total pressure. Space velocity was maintained at 1 h^"1 for the different runs. A sample of Straight Run Gas Oil (SRGO) was also treated for reference purposes and presented a stable yield behaviour after 5 Oh on stream. It generated very little gas and the product liquid contained essentially paraffins and naphthenes, with some monoaromatics (2%) and traces of poly-aromatics. The reference stock was then mixed l o with 20% of either an aromatic oil stream commonly co-treated with SRGO in refinery (Light Cycle Oil, LCO, from Fluid Catalytic Cracking), or 20% of the biooil. Results are shown in Table 27.

Table 27

Run Feed P Cat. Yields, wt% Liquid composition wt% bar C0₂ CH₄ total gases water Liquids, bp (°C) total oil density Sat. MonoAr PolyAr

<216 216-359 >359

1 SRGO 70 NiMo - <0.1 0.3 - 12.2 78.8 8.7 99.7 0.817 97.6 1.8 0.5

2 SRGO-LCO¹ 70 NiMo - <0.1 0.2 - 16.9 75.8 7.0 99.8 0.836 87.1 12.5 0.4

3 SRGO-BIOOIL 70 NiMo - 0.2 0.7 2.2 17.4 72.8 7.0 97.8 0.831 95.9 3.7 0.5

LCO addition resulted in an increase in oil product density straightforwardly related to an increase in aromatics concentration. The rather mild operating conditions (70 bars) did not allow to fully hydrogenate the aromatics in the LCO, but were sufficient to largely reduce poly-aromatics, maintaining its levels well below road diesel specifications (11 wt% maximum in EN590). The processing of a similar amount of Biooil (Run 3) gave even better results, with a lower product density and a composition closer to that of the reference stock. The amount of C0₂ produced was negligible, and the amount of water produced was in accordance with the oxygen content in the feed.

Thus, it has been convincingly demonstrated that amounts of at least 20 wt% of biooil can be co-treated with standard diesel, and that this gives better results than co-treating 20 wt% LCO as is commonly done in the refinery.

Example 13: Production of high quality syncrude from lignocellulosic biomass

- Summary

Wood chips were hydrothermally treated near critical point of water in the presence of a catalyst to yield a raw biooil, containing a wide range of organic products. This was subsequently distilled to remove the heaviest part of the raw biooil, which tended to yield chary products upon heating above 350°C. The biooil obtained had an oxygen content of 14- 18 wt%, and was subsequently hydrotreated to obtain a hydrocarbon stream. Varying the hydrotreatment operating conditions and catalyst allowed tuning product quality, ranging from a deoxygenated syncrude to be further upgraded in refinery under very mild conditions to a diesel additive that can be mixed with conventional diesel upon more severe hydrotreatment. This proof of concept was demonstrated with commercial hydrotreating catalysts, operating between 320 and 380°C, 40 to 120 bars pressure and 1 h^"1 contact time.

Materials and Methods

Hydrotreatment: The fixed bed system was constituted by a feeding tank, an HPLC pump, gas system (H₂, H₂S/H₂ for pretreatment, N₂ purge), reactor, liquid collector, pressure control through a BPR and gas exhaust. The feed tank was gently heated (60°C) and stirred to maintain the Biooil Distillate fairly liquid. 4 grams of catalyst were mixed with Carborundum (Silicon Carbide, CSi) to adjust the total bed volume to 8 ml (approx 6 grams). An additional 1 ml C Si was added on the top of the bed to act as a small preheater. Catalyst was crushed into 0.2 to 0.8 mm particles to avoid any diffusion limitation. Once loaded, the catalyst was presulphided at 400°C with a stream of 10% H₂S in H₂ (120 ml/min) for at least 12 hours. Then, reactor was set to operating temperature, system was pressurized with hydrogen. Once the pressure was stabilized, feed injection began. Hydrogen feeding rate was adjusted to 100 Nml/min, which represents 13.3 wt% of the feed. This is a large excess compared to the amount of hydrogen consumed for HDS (below 1 wt%) or even HDO of Biooil Distillate (3-6 wt % range), that will ensure that hydrogen partial pressure remain high at every point in the reactor.

Mass balances were performed at regular intervals. Liquid recovered is weighed. For each liquid sample at least one gas sample is analyzed online. Gas samples are taken downstream the BPR valve. CO, C0₂ and Ci-C₆ gas concentrations are determined. Coke yield was considered very low for mass balance (below 1%), as confirmed later by the analysis of coke on the catalyst. An aqueous phase usually forms a well-defined layer at the bottoms of the liquids, and can be easily extracted by pipetting. Water is determined by Karl- Fisher after extraction of the aqueous phase from the liquids. It was checked that the water content of the oily phase was negligible. A conversion was defined as the sum of gas and gasoline, to which the amount of gasoline in the feed was subtracted. Bottoms conversion is the conversion calculated only on the 359+°C fraction of the liquid product. These two "conversions" will give an idea of how lighter the liquid gets after hydrotreating.

GCxGC configuration: An Agilent 5890 Gas Chromatograph coupled with an Agilent 5877 A MS detector was used for this analysis. System configuration is known as reverse GCxGC as the first column (HP-INNOWAX, 30m x 0.25mm x 0.25 μιη) is a polar one, while the second one (DB5, 5m x 0. 25mm x 0.25 μιη) is apolar. Injector temperature was set at 200°C. Samples of 1 μΐ were injected with a split ratio of 100. Hydrogen carrier flows were 0.3 ml/min in the first column and 24 ml/min in the second one. A flow modulator was used. The modulation period was 4.5 s. Oven temperature was maintained at 50°C for 5 minutes, then ramped at 2°C/min ramp up to 250°C, followed by a plateau for 60 minutes. The second oven followed the first oven program with a 10°C offset. FID temperature was at 300°C, acquisition frequency 100Hz. MS acquisition frequency was set at 14 spectra/s in a mass range of 40-360 amu.

Results and Discussion

A reactor allowing continuous hydrothermal treatment was developed. The lignocellulose (for example chips of pine wood) was suspended in water, and the slurry pumped into a vertically oriented, serpentine tubular reactor (which may be continuous or batch). Operating conditions for the hydrothermal treatment were close to the critical point of water (e.g. 330-350°C temperature and 200-250 bar which is subcritical for water) although higher temperatures/pressures above the critical point of water may also be used in the hydrothermal processing. The slurry reacted for some hours before being discharged. The raw biooil obtained through this treatment contained large amounts of water and a certain amount of solid material, remains of catalyst or unconverted feedstock. Thus, this stream was directly flashed at the output of the high pressure hydrothermal reactor, ensuring a rapid and efficient separation of oily products and water phase. Catalyst and a number of water organics were eliminated with the water phase. These included products such as ketones, acids and phenols that may be recovered from the aqueous stream for further valorization. The oily phase recovered may represent about 30-35 wt% of the dry biomass fed to the hydrothermal reactor. This dewatered oil was further distilled in order to remove the heaviest part, constituted of a material that may to transform into char when exposed to temperature above 350°C (see Figure 11). This fraction represents 20-40% of the dewatered raw biooil, depending on the hydrothermal processing conditions. The analysis shows an amount of 35 wt% solid remained after TG analysis.

After the separation, the remaining oily biooil was extensively characterized. Elemental analysis showed a content of oxygen around 12%, low nitrogen content, nearly zero sulphur and a Carbon to hydrogen molar ratio of 1.36 (see Table 28 below). able 28

This product quality is much higher than common pyrolysis oil where oxygen contents as high as 40% with H/C molar ratio close to 1.0 are commonly found. Oxygen content and C/H ratio are indeed not too far from fats that are commercially hydrogenated today. Simulated Distillation (SIMDIS) of this oily product was also performed. Although SIMDIS of oxygen-containing stream may present important deviation from real distillation, it nevertheless gives a rough indication of the boiling point range of the sample, indicating in our case that the biooil would be similar to a petroleum-based diesel stream, with 60% diesel- range products and 20%> each of gasoline and heavy-range products. It has to be noted that compared to a petroleum-based Vacuum Gas Oil, biooil heaviest components detected by chromatography are significantly lighter than the heavy end tail detected in VGO (Figure 13).

This biooil was subsequently hydrotreated in a fixed bed with commercial NiMo/alumina and NiW/silica alumina catalysts. Physico-Chemical characteristics of the hydrotreating catalysts are listed in Table 29 below.

Table 29

This type of catalyst is typically used for hydro-desulfuration and/or hydrocracking of middle distillate and Vacuum Gas Oil feeds in petroleum industry. It should be noted that more specialized catalysts have been developed for biomass containing feeds, in particular fats hydrogenation to diesel. The catalyst was diluted with Silicon Carbide and presulfided before testing. Operating conditions ranged from 350 to 380°C, 40 to 120 bars total pressure. Space velocity was maintained at 1 h-1 for the different runs. A sample of Straight Run Gas Oil was also treated as reference stock. This feed was easily hydrotreated, presenting a stable yield behaviour after 5 Oh on stream. It generated very little gas and the product liquid contained essentially paraffins and naphthenes, with some monoaromatics (2%) and traces of poly-aromatics. The reference stock was then mixed with 20% of either an aromatic oil stream commonly co-treated with SRGO in refinery (Light Cycle Oil from Fluid catalytic Cracking) and 20% of the biooil oil. LCO addition resulted in an increase in oil product density related to an increase in aromatic concentration. The rather mild operating conditions (70 bars) did not allow to fully hydrogenate the aromatics in the LCO, but were sufficient to largely reduce poly-aromatics, maintaining its levels well below road diesel specifications (1 1 wt% maximum in EN590). The processing of a similar amount of Biooil (Run 3) gave better results, with a lower product density and a composition closer to the reference stock. The amount of C0₂ produced was negligible, and the amount of water produced was in accordance with the oxygen content in the feed. It was then demonstrated that amounts of at least 20 wt% of biooil could be co-treated with standard diesel, giving better results than treating LCO which is commonly done in the refinery.

Biooil was further treated as pure feed under a variety of conditions. Pressure was varied from 40 to 120 bars with a NiMo catalyst (Run 4-6), resulting in nearly complete deoxygenation whatever the operating pressure. No hydrotreated oil product showed an oxygen amount above 1 wt% (lower amounts could not be measured accurately). While some oxygenated compounds were detected operating at 40 bars, no oxygenated compounds could be detected by GCxGC at pressures of 70 to 120 bars. Increasing the hydrotreating pressure allowed reducing heavy ends in the diesel and minimizing aromatic content, yielding products with lower density at higher processing pressure. Water yield was close to the oxygen content of the biooil feed, confirming near complete deoxygenation. Gas was produced in yields of 2 wt%, with a minor contribution of C0₂ and a significant contribution of methane. The use of a mild hydrocracking catalyst at 350°C and 120 bars gave similar results to those obtained with NiMo. Raising reactor temperature to reach operating conditions more typical of hydrocracking (380°C, Run 8) allowed decreasing further product density by reducing heavy ends and increasing the amount of light, gasoline-range products.

It has to be noted that at this temperature monoaromatics yield in the oil tended to increase, a well-known effect for the refiner. By the contrary, poly-aromatics were reduced to minimums (below 1 wt%). While the density of the product is slightly outside road diesel specifications (0.82 - 0.845), it would be an excellent feedstock for diesel blending especially for very paraffinic feedstocks obtained from the hydroprocessing of triglycerides (vegetable oils and others), which tends to have a low density. It has also to be noted that the oil product obtained in the syncrude has a significant amount of polycyclic saturated products of the decaline families. The hydrogenated skeleton of terpene products of the family of resin acids, typically found in pine woods and main constituents of pine resins were also observed. Also, in the aromatics, a predominance of hydro-aromatic structures of the tetrahydronaphthalene family is also found. All these compounds have a rather high density compared to paraffins and thus explain the high product density of the oil in spite of low levels of polyaromatics, and a significantly higher content of low molecular weight compounds in the streams produced from the 100% biooil hydrogenation.

Operating conditions and yields for the hydrogenation of biooil, compared to some petroleum-based middle distillates, are shown below in Table 30 below. Table 30

Run Feed P Cat. Yields, wt% Liquid composition wt%

bar C0₂ CH₄ total water Liquids, bp (°C) total oil density Sat. MonoA PolyA gases <216 216-359 >359 r r

1 SRGO^[bl 70 NiMo - <0.1 0.3 - 12.2 78.8 8.7 99.7 0.817 97.6 1.8 0.5

2 SRGO-LCO^[cl 70 NiMo - <0.1 0.2 - 16.9 75.8 7.0 99.8 0.836 87.1 12.5 0.4

3 SRGO-BIO^|dl 70 NiMo - 0.2 0.7 2.2 17.4 72.8 7.0 97.8 0.831 95.9 3.7 0.5

4 BIO^|el 40 NiMo 0.1 0.7 1.9 11.3 28.9 49.8 8.1 86.8 0.916 42.0 44.1 13.9^[gl

5 BIO 70 NiMo 0.1 0.8 2.1 11.2 28.1 49.9 8.7 86.7 0.901 50.5 43.7 5.8

6 BIO 120 NiMo 0.1 0.7 1.9 9.6 33.7 49.8 4.9 88.5 0.891 64.9 32.7 2.4

7 BIO 120 NiW 0.2 0.6 1.6 11.3 32.6 49.3 5.1 86.1 0.892 65.6 30.5 3.9

8 BIO 120 NiW™ 0.2 0.7 2.6 14.4 38.2 42.9 2.2 83.0 0.877 61.8 35.3 0.8

Catalysts after the hydrotreating runs were recovered, washed and analyzed by Elemental Analysis to check for the amount of coke formed (see Table 31 below).

Table 31

Operating with biooil at pressure of 70 bars or lower increased substantially the coke on catalyst, which may cause accelerated deactivation. Note that under the most severe hydroprocessing conditions (Run 8, NiW, 120 bars 380°C) the coke on catalyst was only slightly higher than operating with SRGO. Indeed very stable yields and product compositions were obtained over the nearly 60 h of operation as shown in Figure 12. For lower pressure, although very noticeable catalyst deactivation over the run length (60h) was not observed, optimized catalysts may be used to ensure long term operation.

In conclusion, it was demonstrated that a high quality, deoxygenated stream of hydrocarbons could be obtained from lignocellulose in three steps. The biooil obtained after hydrothermal liquefaction of the pine wood, followed by separation and distillation, was successfully deoxygenated under refinery hydrotreating conditions. The quality of the final syncrude stream can be modulated depending on its final destination: selling to refinery for further upgrading may require only soft hydrotreatment (40 bars), while obtaining a finished product of enough quality for direct blending as transportation fuel use may require severe hydrotreatment (120 bars, higher temperature).

Example 14: Upgrading fossil and biomass opportunity crudes

Biooil from hydrothermal liquefaction

1. Overview

A multistep process was implemented to convert pine woodchips into fuels (Figure 14). In the first step, Pine woodchips were hydrothermally processed in the presence of a catalyst, yielding a raw biooil. One of the hurdles of such process development is the low productivity associated with batch treatment. Thus, a reactor allowing continuous treatment at 10,000 tonnes per year nameplate capacity was developed. The lignocellulose (e.g. pine woodchips) is reduced in particle size to suit the type of slurry pump being used. In these experiments the feedstock was reduced to about 500 microns diameter, however particle diameters of up to 2 mm have successfully been employed with the same pump and reactor configuration. The lignocellulose is suspended in water, and raised to the operating reaction temperature by a combination of electrical heating, heat exchangers and supercritical steam injection. Homogeneous base catalyst is added in solution by means of a high pressure dosing pump and the slurry is pumped into a vertically oriented, serpentine tubular reactor. Operating conditions were close to the critical point of water, optimally sub-critical in the 330-350°C temperature range and 200- 250 bar, although higher temperatures/pressures above the critical point of water may also be used in the hydrothermal processing. The residence time in the reactor was typically around 20-30 minutes for woody biomass. At this stage the processing stream was an oil- water emulsion and contains a small amount of solid material, i.e. mostly ash from the feedstock. In the next step the stream was partially cooled and then directly flashed at the output of the high-pressure hydrothermal reactor, splitting the emulsion and ensuring a rapid and efficient separation of oily products and water phase. Catalyst and a number of water-soluble organics were removed with the water phase. These include products such as small ketones, acids and phenols that may be recovered from the aqueous stream for further valorization. On a dry basis the oily phase recovered may represent about 30-35 wt% of the dry biomass fed to the hydrothermal reactor. This now already dewatered oil was further distilled in order to remove the heaviest part, constituted of a material that tends to transform into char when exposed to temperature above 350°C (see Figure 14). This heavy fraction represented 20-30% of raw biooil, depending on the hydrothermal processing conditions.

Due to its characteristics, the resulting biooil is not straightforwardly suitable for use as transportation fuel, so a final upgrading step is necessary. For that purpose two options were investigated. The simplest one is mixing the biooil with Vacuum Gas Oil (VGO) and crack the mixture in a Fluid Catalytic Cracking Unit (Figure 15). In a second option involves hydrotreating the biooil first, yielding a number of distillate range products, while the remaining heavy fraction is cracked in fluid catalytic cracking. 2. Materials and Methods

Biooil characterization

The biooil obtained after flash separation and distillation was extensively characterized. Elemental analysis showed a content of oxygen around 12%, a low nitrogen content of 0.2%, no detectable sulphur (<0.1%) and a Carbon to hydrogen molar ratio of 1.36. Table 32 shows an elemental analysis of the biocrude.

Table 32

This product quality is much better than common pyrolysis oil where oxygen contents as high as 40% with H/C molar ratio close to 1.0 are commonly found. Oxygen content and C/H ratio are indeed not too far from the triglycerides present in plant oils or animal fats that are commercially hydrogenated today. Simulated Distillation (SIMDIS) of this oily product was also performed. Although SIMDIS data of oxygen-containing streams cannot be compared directly with those of pure hydrocarbon streams, since the removal of oxygen will result in a shift to lower temperatures, it nevertheless gives an upper limit of the boiling point ranges in the sample. In our case this indicates that the biooil would be at least similar to a petroleum-based diesel stream, with 60% diesel-range products and 20% each of gasoline and heavy-range products. Consistent with the above discussion, it has to be noted that compared to a petroleum-based Vacuum Gas Oil, biooil heaviest components detected by chromatography are significantly lighter than the heavy end tail detected in VGO (Figure 16).

Catalyst characterization

The hydrotreating catalysts were a NiMo supported on alumina and a NiW supported on silica-alumina. General hydrotreatment catalyst properties are summarized in Table 33. Table 33

It was used without further treatment and sulphided in-situ during the start-up of the experimental runs. Catalytic cracking catalyst is a standard commercial grade containing 3wt% Rare Earth. It was steam deactivated at 816°C for 4 hours with 100% steam. The main properties of the catalytic cracking catalysts are summarized in Table 34.

Table 34

Hydrotreating and cracking units

The fixed bed system (Figure 15) comprised a feeding tank, an HPLC pump, gas system (H₂, H₂S/H₂ for pretreatment, N₂ purge), reactor, liquid collector, pressure control through a BPR valve and gas exhaust. The feed tank was gently heated (60°C) and stirred to maintain the Biooil Distillate at low viscosity. 4 grams of catalyst were mixed with Silicon Carbide (CSi) to adjust the total bed volume to 8 ml (approx 6 grams). An additional 1 ml CSi was added on the top of the bed to act as a small preheater. The catalysts were crushed into 0.2 to 0.8 mm particles to avoid any diffusion limitation. Once loaded, the catalysts were sulphided at 400°C with a stream of 10% H₂S in H₂ (120 ml/min) for at least 12 hours.

Then, reactor was set to operating temperature, system was pressurized with hydrogen. Once the pressure was stabilized, feed injection began. Hydrogen feeding rate was adjusted to 100 Nml/min, which represents 13.3 wt% of the feed. This is a large excess compared to the amount of hydrogen consumed for HDS (below 1 wt%) or even HDO of Biooil Distillate (3-6 wt % range), that will ensure that hydrogen partial pressure remain high at every point in the reactor.

Mass balances were performed at regular intervals. The liquids recovered are weighed. For each liquid sample at least one gas sample is analyzed online. Gas samples are taken downstream the BPR valve. CO, C0₂ and Ci-C₆ gas concentrations were determined. Coke yield was considered very low from the mass balance (below 1%), as confirmed later by the analysis of coke on the catalyst. An aqueous phase formed a well- defined layer at the bottoms of the liquids, and could be easily extracted by pipetting. Water was determined by Karl-Fisher after extraction of the aqueous phase from the liquids. It was checked that the water content of the oily phase was negligible. This phase was analyzed by SIMDIS (ASTM-D-2887), and upper cut point was set at 216°C for gasoline fraction and 359°C for diesel fraction. Some of the liquid products were also analyzed through GCxGC-MS technique, using a system configuration known as reverse GCxGC as the first column (INNOWAX, 30m x 0.25mm x 0.25 μιη) is a polar one, while the second one (DB5, 5m x 0. 25mm x 0.25 μιη) is apolar. A flow modulator was used, with a modulation period of 4.5 s. The oven temperature was maintained at 50°C for 5 minutes, then ramped at 2°C/min ramp up to 250°C, followed by a plateau for 60 minutes. The second oven followed the first oven program with a 10°C offset. FID temperature was at 300°C, acquisition frequency 100Hz. MS acquisition frequency was set at 14 spectra/s in a mass range of 40-360 amu.

Cracking was performed on a fixed bed Micro Activity Test unit modified from ASTM-3907. Operating conditions were 500°C reaction temperature, 30 seconds Time- On-Stream and Catalyst-to-Oil ratio in the range of 2 to 5. These conditions were elected to maximize middle distillates yield. Liquids products were recovered in glass receivers and gases were recovered in a water burette or a gas bag when biooil was present in the feed, as CO/C0₂ and some of the oxygenated products would have been lost in the water. Pressure during the test remained close to atmospheric. After the reaction, a 15 minutes stripping at 50 ml/min is performed. Catalyst is regenerated with air at 550°C during 3 hours. Gas and liquid samples were analyzed as described in the former paragraph. Nitrogen was used as internal standard to determine the total volume of gas recovered in the case of using a gas bag. C5+ components and oxygenates in the gas were fully quantified and their weight added to the gasoline fraction in the mass balance. In the case biooil was present in the feed, experiments were duplicated and the water was extracted from the liquid product using methanol. The extract was then analyzed by Karl-Fisher titration to determine water content. Coke yield was determined by combustion and integration of the C0₂ signal in flue gas measured with an IR. Conversion was calculated as the sum of gas, gasoline, diesel and coke products. The mass balances performed were 95% or higher in all series.

3. Results and discussion

Direct catalytic cracking

Direct cracking of the Biooil was carried out, either alone or mixed at 10 or 30 wt% with a standard Vacuum Gas Oil, and compared with the cracking of VGO alone. Conversion in catalytic cracking is often defined as a convention as the sum of gas, gasoline and coke products. However, in the present case, owing to the unconventional nature of the crude treated, it was preferred to define the conversion as the sum of gases, gasoline, diesel and coke products, sometimes referred as total conversion in catalytic cracking conventionalism. As can be seen in Figure 16, (total) conversion did not vary much with the incorporation of increasing amounts of biooil in the VGO. Dry gas selectivity increased with the presence of biooil, while LPG selectivity decreased. Gasoline selectivity decreases and LCO selectivity increases with the increase of biooil in the feed mix, with such an amplitude that by the traditional definition the conversion as the sum of gas, gasoline and coke would have decreased largely when biooil is added, giving the misleading impression the biooil do not convert well. Instead, the amount of (unwanted) bottoms remaining after cracking varies only slightly when biooil is added. Finally coke selectivity increases with the presence of biooil, as does coke-on-catalyst. This last point will strongly limit the direct processability of Biooil in the FCCU, as coke yield is determined by the thermal balance of the unit. Incorporating biooil to the VGO feed will then make the catalyst to oil ratio lower in the unit, thus indirectly decreasing the conversion of the processed mixture.

The Propylene to propane ratio increases with high levels of biooil in VGO, as does isobutene to iso-butane ratio. This implies that hydrogen transfer reactions are suppressed with higher levels of biooil, which is a direct consequence of higher coke-on-catalyst. Also, the higher amounts of poly-aromatics generated in the cracking of the biooil plays a role in catalyst deactivation. The analysis of the diesel fraction, which yield increased sharply with biooil, revealed that it was very aromatic in nature (see Table 35 which shows diesel yield and composition, CTO=5, increasing amount of distilled biocrude in VGO). Table 35

Also, a significant amount of oxygenated compounds, essentially phenols and derivates, were detected in the diesel range when biooil was present in the feed. The aromaticity of the diesel fraction also explains why such high yields of diesel could be maintained even at higher catalyst to oil ratio (higher conversion), as these kind of aromatics crack to a very little extent to yield gasoline and /or gaseous fragments.

Oxygen in the feed was converted mainly into water, with a yield in the 40-60% range, independently of the biooil content in the feed. CO and CO₂ were also produced, totalling less than 10 wt% of the feed oxygen, with more CO than CO₂. This indicates that there are little acids to decarboxylate in the feed. Oxygen balance implies that 30 to 50 wt% of the feed oxygen was still retained in the liquid products or the coke. The amount of oxygenates found in the diesel products is thus consistent with the former observations.

Direct catalytic cracking of the biooil, while being a straightforward and very cheap option, will then be limited to low amounts in co-processing with VGO, presumably below 10 wt%. Note that a 5% share of a 30,000 bpd FCC unit still represent around 200 tons per day of biooil to be treated.

Hydroprocessing followed by bottoms cracking

The biooil was then hydrotreated with a commercial desulphuration-deoxigenation catalyst (NiMo-based) in order to improve its quality. While these catalysts are primarily optimized for use with petroleum stocks and a quite different process, they also present an appreciable activity towards deoxygenation. Two runs were conducted, one under soft hydrotreating conditions and the second one under mild hydrocracking conditions.

Results are reported in Table 36 which shows operating conditions, yields and hydrocarbon product characteristics for the hydroprocessing of biooil. Table 36

In both cases, deoxygenation was nearly complete, with a recovered water yield similar to the oxygen content in the feed. Elemental analysis of the recovered oil (separated from the water phase) confirmed that the oxygen content was below 1 wt% in each case, even at 40 bars hydroprocessing pressure. The amount of carbon oxides in the gas remained very low, and contained less than 5 wt% of the oxygen in the feed. Oxygen was thus removed essentially through hydrogenation-dehydration mechanism. Gas yield increased moderately with the hydroprocessing severity, and is significantly higher than what is commonly found for hydrocarbon processing under these conditions, with gas yield generally below 1 wt%. The obtained oil has a boiling range lower than the feed, with the heavy fraction (bp>359°C) reduced by half at low pressure processing and reduced 90% at higher pressure. The density of the oil product was found to be high compared with the specifications for a road diesel, in spite of a significant light fraction in the product (30-40% gasoline-range products). The composition determined by GCxGC for the hydroprocessed oil showed an important amount of aromatics and poly-aromatics (PAH) in the oil obtained at 40 bars. Some oxygenated compounds, essentially substituted phenols, were also detected and totalled approximately 1.5 wt% respect to the feed in accordance with Elemental Analysis observations. These compounds were lumped with PAH in Table 36. At 120 bars hydrotreatment, aromatic content was substantially lowered, and especially PAH content at 1.2 wt%, well below the 11% threshold value for road diesel. Oxygenated compounds were not detected anymore under these processing conditions. The Saturate fraction increased to approximately 60%, but the oil density remained surprisingly high in view of this composition. GCxGC chromatogram revealed that Saturate fraction included a large amount of poly-cyclic naphthenic products of the decalin family, which have a substantially higher density than the corresponding paraffins of the same carbon number (decane density is 0.730 g/cm3 while decalin - decahydronaphthalene - density is 0.896). As well, the aromatic fraction contained numerous isomers of the tetralin family, which are also denser than the corresponding decalins. It may then be interesting to treat further these streams with a dearomatization/ring opening catalyst to lower further product density. Little pre- treatment would be needed as the hydroprocessed product is sulphur and nitrogen free and has very low oxygen remaining, if any.

The oil product from the hydroprocessing at 40 bars was further fractionated using an equipment and operating conditions similar to those described in ASTM-D-1160 method, The operation yielded a gasoline-range fraction (30 wt%), a diesel-range fraction (54 wt% and a heavy fraction (16 wt%). This Hydrotreated Biooil Heavies (HBH) fraction had a density of 0.995, and was further processed in catalytic cracking. The same protocol than in section 2.3.1 was used, that is mixing with a VGO at 10 and 30 wt% level as well as comparing with 100% HBH cracking.

For the same reason as with biooil, it is reported here the selectivity calculated for a conversion defined as the sum of gases, gasoline, LCO (diesel) and coke yields. The (total) conversion of HBH offers some similarity with that of biooil in the aspect that the conversion does not change much with the incorporation of biomass-based stream into VGO, and that the selectivity largely shifts from gasoline to diesel range products. Yet the large difference lies in dry gas and coke selectivity, which are now similar for VGO and HBH. Then, contrary to biooil, HBH could be processed even at high blending levels in VGO, with no penalty in conversion. LPG selectivity decreased slightly with the incorporation of HBH, and olefinicity of the LPG decreased, indicating that more hydrogen transfer took place with HBH. This is due to the nature of HBH, which contain a significant amount of hydro-aromatics. Indeed, these compounds could be detected through GCxGC-MS analysis, an image of which is shown in . Apart from some linear paraffins, the main components of the highlighted groups of peaks in this figure included structures with 3 fused rings of the anthacene or phenanthrene family with varying degree of saturations, from saturated 3 rings naphthenes to tri-aromatics. 3 -ring saturated systems may crack yielding gas and gasoline components, but hydro-aromatics will be prone to hydrogen transfer, yielding poly-aromatics with 2 or 3 fused aromatic rings that belong to LCO fraction. Table 37 shows catalytic cracking conversion and selectivity of Hydrotreated biocrude heavies, VGO and their mixtures (500°C, TOS = 30s). The composition of diesel fraction of the cracked liquid in Table 37, determined by GCxGC, shows very clearly the increase of poly-aromatics correlated with the increase of biooil in the feed. The poly-aromatics formed after hydrogen transfer will accumulate mainly in the LCO fraction, which partially explains the higher selectivity to this fraction at the expense of gasoline and gases. As oxygen content in HBH was very low (<1 wt%), no CO/C0₂ or water could be detected in the products. Traces of phenolic and benzofuranes compounds could be observed in the diesel fraction but always with an amount lower than 0.5 wt% and thus were grouped with poly-aromatic fraction. Taking into account the amount of oxygen in phenol-like compounds, it can be assumed that the cracked diesel has a content of oxygen below 0.1 wt%.

Table 37

% biooil 0 10 30 100

Diesel, wt% 24.7 25.9 31.0 43.2

Composition

Saturates 19.0 16.7 13.2 4.3

Mono-aromatics 24.2 23.0 21.3 17.0

Poly-aromatics 56.8 60.3 65.6 78.7

Claims

1. A method for producing an upgraded biooil product, the method comprising: hydrotreating a biooil or a distillate thereof with hydrogen in the presence of hydrotreating catalysts;

to thereby produce an upgraded biooil product, wherein:

prior to the hydrotreating the biooil comprises any one or more of:

an oxygen content on a dry basis of 5wt% db -25wt% db,

a Total Acid Number (TAN, ASTM D664) of 1-50 mg KOH/g, a water content of 0.% 1-5% (e.g. 0.5%-5%);

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

2. The method of claim 1, wherein the method comprises said hydrocracking after the hydrotreating,

optionally wherein the biooil or biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof is hydrocracked in a mixture with a second oil selected from any one or more of gas oil, vacuum gas oil, atmospheric residue, atmospheric gas oil, vacuum residue, coker gas oil, and/or heavy gas oil, and

optionally wherein the mixture subjected to the hydrocracking comprises:

at least 3wt% of the biooil or biodistillate thereof and at least 67% of the second oil, at least 5wt% of the biooil or biodistillate thereof and at least 65% of the second oil, at least 7wt% of the biooil or biodistillate thereof and at least 63% of the second oil, at least 10wt% of the biooil or biodistillate thereof and at least 50% of the second oil, at least 15wt% of the biooil or biodistillate thereof and at least 55% of the second oil,

at least 60wt% of the biooil or biodistillate thereof and at least 10%) of the second oil,

at least 70wt%o of the biooil or biodistillate thereof and at least 5%> of the second oil, or

at least 80wt%> of the biooil or biodistillate thereof and at least 10% of the second oil.

3. The method of claim 2, wherein the hydrocracking comprises:

fractionating the biooil or biodistillate thereof after said hydrotreating into an aqueous fraction comprising substantially water and a minor proportion of dissolved organic products (e.g. less than 5%>wt, less than 10%wt), and a non-aqueous fraction, and hydrocracking the non-aqueous fraction; and/or

4. A method for producing an upgraded biooil product, the method comprising hydrocracking a biooil or a biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof, with hydrogen using hydrocracking catalysts to thereby produce the upgraded biooil product, wherein:

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil;

5. The method of claim 4, wherein the hydrocracking comprises:

hydrocrackmg the entire biooil or biodistillate thereof; and/or

6. The method of any one of claims 1 to 5, wherein the hydrocracking comprises treating the biooil or distillate thereof in the presence of hydrogen at:

a temperature of 350 °C to 450°C, or 380 °C to 425°C; and/or

a space velocity may range from 0.1 to 10 h^"1, or 0.3 to 1 h^"1 ; and/or

a pressure of 80 to 250 bar or 100 to 150 bar.

7. The method of any one of claims 1 to 6, wherein the hydrocracking is performed under conditions selected to:

minimise the amount of material boiling above the nonnal boiling range of diesel fuel in the upgraded fuel product; and/or

8. The method according to any one of claims 1 to 7, wherein the hydrocracking comprises:

9. A method for producing an upgraded biooil product, the method comprising the steps of:

wherein:

prior to the hydrotreating the biooil comprises any one or more of: an oxygen content on a dry basis of 5wt% db -25wt% db,

a Total Acid Number (TAN, ASTM D664) of 1 -50 mg KOH/g, a water content of 0.% 1-5% (e.g. 0.5%-5%),

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

10. The method of claim 9, wherein the hydrotreated intermediate (e.g. heavy oil fraction) is mixed with mineral oil (e.g. a gas oil, vacuum gas oil, atmospheric residue atmospheric gas oil, vacuum residue, coker gas oil, heavy gas oil, or any combination thereof) prior to or during the catalytic cracking of step (ii), and optionally wherein the mineral oil has a boiling point that is no more than 20%, no more than 15%, no more than 10%, no more than 5%, or no more than 3%, higher or lower than the boiling point of the hydrotreated intermediate.

1 1. The method of claim 10, wherein the hydrotreated intermediate is subjected to the catalytic cracking within a mixture comprising:

the hydrotreated intermediate and mineral oil,

12. The method according to any one of claims 9 to 1 1, wherein the hydrotreated intermediate is fractionated into a distillate fraction and a heavy oil fraction, and the heavy oil fraction is subjected to the catalytic cracking of step (ii).

13. The method according to any one of claims 1 to 12, wherein the hydrotreating comprises:

treating the biooil or distillate thereof at a temperature of between 280°C and 380°C (e.g. 320°C and 380°C, 350°C and 380°C) and at a pressure of between 10 bar and 150 bar in the presence of hydrogen with hydrotreating catalysts capable of removing any one or more of sulphur, nitrogen, and metals from the biooil or distillate thereof.

14. The method according to any one of claims 1 to 13, wherein the biooil or distillate thereof subjected to hydrotreating is a component fractionated from the biooil or distillate thereof prior to the hydrotreating.

15. The method according to any one of claims 1 to 14, wherein the hydroprocessing is perfomied at a space velocity in the range of:

(i) 10 to 0.1 h^"1,

(ii) 2 to 0.3 h^"1.

16. The method according to any one of claims 1 to 15, wherein the hydrotreating and/or hydrocracking comprises using several reactors sequentially in a cascade.

17. The method according to claim 16, wherein one or more components (e.g. water) is/are removed from the biooil under treatment between the reactors.

18. The method according to any one of claims 1 to 17, wherein the hydrotreating and/or hydrocracking catalysts are selected from the group consisting of: Ni, W, Co, Mo, and any combination thereof.

19. The method according to claim 18, wherein the hydrotreating and/or hydrocracking catalysts further comprise any one or more of: P, B, Fe, Cu, V, Cr, Zn, Mn.

20. The method according to claim 17 or claim 18, wherein the hydrotreating and/or hydrocracking catalysts are supported on an inorganic oxide selected from the group consisting of: silica, alumina, silica-alumina, zirconia, titania, magnesia, magnesia- alumina of hydrotalcite, spinel structure, molecular sieves, and any combination thereof.

21. The method according to any one of claims 18 to 20, wherein the hydrotreating and/or hydrocracking catalysts are supported on an inorganic oxide having an acid function selected from the group consisting of: silica-alumina, a zeolite, a zeotype, beta zeolite, Y zeolite, X zeolite, omega zeolite, L zeolite, ITQ-21 zeolite and any combination thereof.

22. A method for producing an upgraded biooil product, the method comprising: catalytically cracking a biooil or a distillate thereof with cracking catalysts at a temperature suitable to cleave hydrocarbon chains within the biooil or distillate to thereby produce an upgraded fuel product,

wherein:

prior to the catalytic cracking the biooil comprises any one or more of:

an oxygen content on a dry basis of 5wt% db -25 wt% db, a Total Acid Number (TAN, ASTM D664) of 1-50 mg KOH/g, a water content of 0.% 1-5% (e.g. 0.5%-5%);

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of: reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

23. The method of claim 22, wherein

the biooil or distillate thereof is a component of a feedstock subjected to said catalytic cracking, and

24. The method of claim 23, wherein:

the feedstock comprises the biooil or distillate thereof mixed with mineral oil (e.g. a gas oil, vacuum gas oil, atmospheric residue, atmospheric gas oil, vacuum residue, coker gas oil, heavy gas oil, or any combination thereof).

25. The method of claim 24, wherein the mineral oil has a boiling point that is no more than 20%, no more than 15%, no more than 10%, no more than 5%, or no more than 3%), higher or lower than the boiling point of the biooil or a distillate thereof.

26. The method of claim 24 or claim 25, wherein the biooil or distillate thereof is subjected to the catalytic cracking within a mixture comprising:

the biooil or distillate thereof, and mineral oil,

between about 1 % and 99% of the biooil or distillate thereof by weight and a remaining portion comprising or consisting of mineral oil, and/or

between 1 % and 5% of the biooil or distillate thereof by weight and between about 95% - 99% by weight mineral oil.

27. The method of any one of claims 22 to 26, wherein the catalytic cracking is performed at a temperature of:

(i) between 450°C and 650°C, or

(ii) between 480°C and 550°C.

28. The method of any one of claims 22 to 27, wherein the catalytic cracking is performed at a pressure of:

(i) between 0.05 MPa and 1 Mpa, or

(ii) between 0.01 MPa and 0.3 MPa.

29. The method of any one of claims 22 to 28, wherein the catalytic cracking is performed in a Fluid Catalytic Cracking Unit (FCCU) suitable for upgrading of conventional crude oil.

30. The method of any one of claims 22 to 29, wherein:

31. The method of any one of claims 22 to 30, wherein feed subjected to catalytic cracking is preheated to temperatures of 150°C to 300°C.

32. The method of any one of claims 22 to 31, wherein the catalytic cracking comprises using catalysts comprising any one or more of: zeolites, large pore zeolites, Y zeolites, X zeolites, beta zeolites, L zeolites, Omega zeolites, offretites, ITQ 21 zeolites, ZSM5, ZSM 12, ferrierite, SAPOl 1 , platinum, or any combination thereof.

33. The method of any one of claims 22 to 32, wherein the catalytic cracking comprises using a matrix for the catalysts and a binder.

34. The method according to any one of claims 1 to 33, wherein the biooil comprises any one or more of:

an energy content of 30-40 (GCV/HH V MJ/kg db)

a carbon content of 76-82 wt% db

a sulphur content of 0.01 -0.2 wt% db

a hydrogen content of 6-9 wt% db

kinematic viscosity of 100 to 2000 centiStokes at 40°C

a specific gravity of 0.98- 1.1.

35. The method according to any one of claims 1 to 34, wherein the biooil was produced by hydrothermal treatment of lignocellulosic material with an aqueous solvent at a temperature of between 280°C and 420°C, 280°C and 370°C, or 300°C and 350°C, and at a pressure of between 100 bar and 300 bar.

36. The method according to any one of claims 1 to 35, wherein the biooil was produced by hydrothermal treatment of organic matter comprising any of softwood biomass, bagasse, wheat straw, oil palm, biomass used for oil production, spruce, pine, fir, microalgae, macroalgae, wheat straw, bagasse, eucalypt and any combination thereof.

37. The method of any one of claims 1 to 36, wherein the upgraded fuel product has an oxygen content below 1 wt%, an aromatic content below 40 wt%, and a polyaromatic content below 3 wt%.

38. The method of any one of claims 1 to 37, wherein the oxygen content of the upgraded fuel product is reduced compared to the oxygen content of the biooil by more than 50%, more than 60%, more than 70%, more than 75%, more than 80%, more than 85%, more than 90%, more than 95%, more than 96%, more than 97%, more than 98%, or more than 99%.

39. The method of any one of claims 1 to 38, wherein the Total Acid Number (TAN, ASTM D664) of the upgraded fuel product is reduced compared to the Total Acid Number (TAN, ASTM D664) of the biooil by more than 50%, more than 60%, more than 70%, more than 75%, more than 80%, more than 85%, more than 90%, more than 95%, more than 96%, more than 97%, more than 98%, or more than 99%.

40. The method of any one of claims 1 to 39, wherein the water content of the upgraded fuel product is reduced compared to the water content of the biooil by more than 5%, more than 10%, more than 15%, more that 20%, more than 25%, more than 30%, more than 40%, more than 50%, more than 60%, or more than 75%.

41. The method of any one of claims 1 to 21 , wherein the hydrotreating is conducted on a mixture comprising:

the biooil or biodistillate thereof, and a second oil selected from any one or more of crude oil, light gas oil, gas oil, straight run gas oil, atmospheric gas oil, heavy gas oil, light cycle oil, and/or mineral oil; wherein the mixture is optionally distilled (e.g. in an atmospheric distillation unit and/or a vacuum distillation unit) and/or optionally fractionated into different boiling ranges before said hydrotreating.

42. The method of claim 41 , wherein the mixture comprises:

at least 1 wt% of the biooil or biodistillate thereof and at least 69% of the second oil at least 3wt% of the biooil or biodistillate thereof and at least 67% of the second oil, at least 5wt% of the biooil or biodistillate thereof and at least 65% of the second oil, at least 7wt% of the biooil or biodistillate thereof and at least 63% of the second oil, at least 10wt% of the biooil or biodistillate thereof and at least 50% of the second oil,

at least 20wt% of the biooil or biodistillate thereof and at least 50%) of the second oil,

at least 30wt%> of the biooil or biodistillate thereof and at least 40%) of the second oil,

at least 40wt%> of the biooil or biodistillate thereof and at least 30%) of the second oil,

at least 50wt%> of the biooil or biodistillate thereof and at least 20%> of the second oil,

at least 60wt%> of the biooil or biodistillate thereof and at least 10%> of the second oil,

at least 70wt%> of the biooil or biodistillate thereof and at least 5% of the second oil, or

at least 80wt%> of the biooil or biodistillate thereof and at least 10%> of the second oil.

43. The method of any one of claims 4 to 8, wherein the hydrocracking is conducted on a mixture comprising:

the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and a second oil selected from any one or more of crude oil, gas oil, , heavy gas oil, atmospheric residue, vacuum gas oil, vacuum residue, and/or mineral oil;

44. The method of claim 43, wherein the hydrocracking is conducted on a mixture comprising:

at least 3wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 67% of the second oil,

at least 5wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 65% of the second oil,

at least 7wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 63% of the second oil,

at least 10wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 50% of the second oil,

at least 15wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 55%) of the second oil,

at least 20wt%> of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 50%o of the second oil,

at least 30wt%o of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 40%) of the second oil,

at least 40wt%> of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 30% of the second oil,

at least 50wt%> of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 20%) of the second oil, at least 60wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 10% of the second oil,

at least 70wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 5% of the second oil, or

at least 80wt% of the hydrotreated biooil or biodistillate thereof or separated fraction/s of the hydrotreated biooil or biodistillate thereof, and at least 10% of the second oil.

45. The method of any one of claims 22 to 40, wherein the catalytic cracking is conducted on a mixture comprising:

the biooil or distillate thereof; and

a second oil selected from any one or more of crude oil, gas oil, , heavy gas oil, atmospheric residue, vacuum gas oil, vacuum residue, and/or mineral oil;

wherein the mixture is optionally distilled (e.g. in an atmospheric distillation unit and/or a vacuum distillation unit) and/or optionally fractionated into different boiling ranges before said catalytic cracking.

46. The method of claim 45, wherein the catalytic cracking is conducted on a mixture comprising:

at least 3wt% of the biooil or biodistillate thereof and at least 67% of the second oil, at least 5wt% of the biooil or biodistillate thereof and at least 65% of the second oil, at least 7wt% of the biooil or biodistillate thereof and at least 63% of the second oil, at least 10wt% of the biooil or biodistillate thereof and at least 50% of the second oil,

at least 40wt% of the biooil or biodistillate thereof and at least 30%) of the second oil, at least 50wt% of the biooil or biodistillate thereof and at least 20% of the second oil,

at least 80wt% of the biooil or biodistillate thereof and at least 10% of the second oil.

47. The method of any one of claims 41 to 46, wherein the mixture further comprises mineral oil.

48. The method of claim 47, wherein the mineral oil constitutes:

at least 3wt% of the mixture,

at least 5wt% of the mixture,

at least 7wt% of the mixture,

at least 10wt% of the mixture,

at least 15wt% of the mixture,

at least 20wt% of the mixture,

at least 30wt% of the mixture,

at least 40wt% of the mixture,

at least 50wt% of the mixture,

at least 60wt% of the mixture,

at least 70wt% of the mixture, or

at least 80wt% of the mixture.

49. The method of any one of claims 1 to 48, wherein the biooil or a distillate thereof used as a starting material in the method is provided in combination with an oil comprising at least 20%, at least 30%, at least 40% or at least 50% of any one or more of: free fatty acids, triglycerides, diglycerides, monoglycerides, or any combination thereof.

50. A method for producing an upgraded biooil product, the method comprising the steps of: (i) hydrocracking a biooil or a biodistillate thereof, or separated fraction/s of the biooil or biodistillate thereof, with hydrogen using hydrocracking catalysts to thereby produce a hydrocracked intermediate; and

(ii) catalytically cracking the hydrocracked intermediate with cracking catalysts at a temperature suitable to cleave hydrocarbon chains within the hydrotreated intermediate to thereby produce an upgraded fuel product,

wherein:

a Total Acid Number (TAN, ASTM D664) of 1 -200 mg KOH/g (e.g. 1- 50 mg KOH/g),

a water content of 0.1%-5% (e.g. 0.5%-5%);

a gross calorific value on a dry basis of 30-40 MJ/kg;

the upgraded biooil product comprises any one or more of:

reduced oxygen content,

reduced Total Acid Number (TAN, ASTM D664),

reduced water content,

increased gross calorific value;

as compared to the biooil.

51. The method of claim 50, wherein the method does not comprise a stage of hydrotreating the biooil, biodistillate thereof, or separated fraction/s.

52. The method of claim 50 or claim 51 , wherein the hydrocracking comprises:

hydrocracking the entire biooil or biodistillate thereof; and/or

53. The method of any one of claims 50 to 52, wherein the hydrocracking comprises treating the biooil or distillate thereof in the presence of hydrogen at:

a temperature of 350 °C to 450°C, or 380 °C to 425°C; and/or

a space velocity may range from 0.1 to 10 h^"1, or 0.3 to 1 h^"1; and/or

a pressure of 80 to 250 bar or 100 to 150 bar.

54. The method of any one of claims 50 to 53, wherein the hydrocracked intermediate is subjected to the catalytic cracking within a mixture comprising:

the hydrocracked intermediate and mineral oil,

55. The method of any one of claims 50 to 54, wherein the hydrocracked intermediate is fractionated into a distillate fraction and a heavy oil fraction, and the heavy oil fraction is subjected to the catalytic cracking of step (ii).

56. The method of claim 1, wherein the method:

does not comprise hydrocracking the biooil or biodistiUate thereof, or separated fraction/s of the biooil or biodistiUate thereof, before or after said hydrotreating; and

comprises dearomatizing the biooil or biodistiUate thereof, or separated fraction/s of the biooil or biodistiUate thereof after said hydrotreating; and

the upgraded biooil product is kerosene.

57. The method of claim 56, wherein the kerosene comprises a polyaromatics content of polyaromatics of less than 3 wt% and an aromatic content less than 25 wt%.