Patent Publication Number: US-2015080620-A1

Title: Methods and systems for supplying hydrogen to a hydrocatalytic reaction

Description:
RELATED APPLICATIONS 
     This application claims priority to U.S. Provisional Application No. 61/879,422, filed on Sep. 18, 2013, and U.S. Provisional Application No. 61/919,103, filed on Dec. 20, 2013, the disclosures of which are incorporated herein by reference in their entirety. 
    
    
     TECHNICAL FIELD 
     Embodiments of the present disclosure generally relate to a hydrocatalytic reaction and more specifically, to systems and methods supplying hydrogen to the hydrocatalytic reaction through gasification of a biomass material. 
     BACKGROUND 
     This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of any prior art. 
     In recent years, there have been significant concerns about greenhouse gas (“GHG”) emissions and their effect on climate. GHGs, especially carbon dioxide, but also methane and nitrous oxide, trap heat in the atmosphere and thus contribute to climate change. One of the largest sources of GHG emissions is the production and use of fossil fuels for transportation, heating and electricity generation. 
     Significant efforts have been devoted to reducing the GHG emissions that are associated with production and use of transportation fuels. Renewable fuels, for example, are being used to displace fossil fuels in the transportation sector. Cellulosic biomass has garnered particular attention in this regard due to its abundance and the versatility of the various constituents found therein, particularly cellulose and other carbohydrates. Despite promise and intense interest, the development and implementation of bio-based fuel technology has been slow. Existing technologies have heretofore produced fuels having a low energy density (e.g., bioethanol) and/or that are not fully compatible with existing engine designs and transportation infrastructure (e.g., methanol, biodiesel, Fischer-Tropsch diesel, hydrogen, and methane). Moreover, conventional bio-based processes have typically produced intermediates in dilute aqueous solutions (&gt;50% water by weight) that are difficult to further process. Energy- and cost-efficient processes for processing cellulosic biomass into fuel blends having similar compositions to fossil fuels would be highly desirable to address the foregoing issues and others. 
     The United States government, through the Energy Independence and Security Act (“EISA”) of 2007, has promoted the use of renewable fuels with reduced GHG emissions. Some of the purposes of the act are to increase the production of clean renewable fuels, to promote research on and deploy GHG capture and to reduce fossil fuels present in transportation fuels. The act sets out a Renewable Fuels Standard (“RFS”) with increasing annual targets for the renewable content of transportation fuel sold or introduced into commerce in the United States. The RFS mandated volumes are set by four nested fuel category groups, namely renewable biofuel, advanced biofuel, biomass-based diesel, and cellulosic biofuel, which require at least 20%, 50%, 50% and 60% GHG reductions relative to gasoline, respectively. The mandated annual targets of renewable content in transportation fuel under the RFS are implemented using a credit called a Renewable Identification Number, referred to herein as a “RIN,” to track and manage the production, distribution and use of renewable fuels for transportation purposes. RINs can be likened to a currency used by obligated parties to certify compliance with mandated renewable fuel volumes. The EPA is responsible for overseeing and enforcing blending mandates and developing regulations for the generation, trading and retirement of RINs. 
     In addition to EISA, numerous jurisdictions, such as the state of California, the province of British Columbia, Canada and the European Union, have set annual targets for reduction in average life cycle GHG emissions of transportation fuel. Such an approach is often referred to as a Low Carbon Fuel Standard (“LCFS”), where credits may be generated for the use of fuels that have lower life cycle GHG emissions than a specific baseline fuel. Such fuels are often referred to as having a lower “carbon intensity” or “CI”. 
     Accordingly, the efficient conversion of cellulosic biomass into fuel blends and other materials that meet certain government environmental regulations is a complex problem that presents immense engineering challenges. The present disclosure addresses these challenges and provides related advantages as well. 
     SUMMARY 
     The present disclosure describes systems and methods supplying hydrogen to a hydrocatalytic biomass conversion reaction through gasification—also known as partial combustion—of a biomass material, particularly hog fuel. 
     According to one aspect, the present disclosure provides a method comprising: (a) providing a biomass feedstock containing cellulose and water; (b) contacting the biomass feedstock with hydrogen in the presence of a catalyst capable of activating molecular hydrogen to form a hydrocatalytically treated mixture; (c) partially oxidizing at least a biomass material which does not comprise the hydrocatalytically treated mixture to produce a gas mixture comprising carbon monoxide and hydrogen; (d) subjecting at least a portion of the gas mixture to a water gas shift reaction to generate hydrogen and carbon dioxide; and (e) providing at least a portion of the hydrogen from step (d) for use in step (b). 
     In one embodiment, the hydrocatalytically treated mixture comprises a plurality of hydrocarbon and oxygenated hydrocarbon molecules, said method further comprising processing at least a portion of the plurality of hydrocarbon and oxygenated hydrocarbon molecules to form a fuel blend comprising a higher hydrocarbon. In another embodiment, the partially oxidizing step comprises using a gasifier. In one embodiment, the gasifier is selected from the group consisting of a moving-bed gasifier, a fluid-bed gasifier, an entrained-flow gasifier, and any combination thereof. 
     In one embodiment, the method further comprises routing the biomass material to the gasifier, wherein said portion can be a solid, liquid, or a combination thereof. In one embodiment, the gasifier comprises an entrained-flow gasifier and said portion of the first bottom fraction is routed as a liquid. 
     In one embodiment, the hydrocatalytic treatment occurs in liquid phase. In another embodiment, the hydrocatalytic treatment occurs in an aqueous phase solvent. In yet another embodiment, the hydrocatalytic treatment occurs in an organic phase solvent. 
     In one embodiment, the method further comprises processing the biomass feedstock to generate at least a portion of the biomass material subject to partial gasification. In one embodiment, at least a portion of the biomass feedstock comprises one or more wood logs and wherein processing of the biomass feedstock comprises removing an outer layer of one or more wood logs. 
     Other advantages and features of embodiments of the present invention will become apparent from the following detailed description. It should be understood, however, that the detailed description and the specific examples, while indicating preferred embodiments of the invention, are given by way of illustration only, since various changes and modifications within the spirit and scope of the invention will become apparent to those skilled in the art from this detailed description. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to one having ordinary skill in the art and the benefit of this disclosure. 
         FIG. 1  shows an illustrative schematic of one embodiment to supply hydrogen to a hydrocatalytic reaction through gasification of a biomass material. 
         FIG. 2  shows an illustrative schematic of another embodiment to supply hydrogen to a hydrocatalytic reaction through gasification of a biomass material. 
         FIG. 3  shows an illustrative schematic of an exemplary moving bed gasifier that can be used in one embodiment according to aspects of the invention. 
         FIG. 4  shows an illustrative schematic of an exemplary stationary fluid-bed gasifier that can be used in one embodiment according to aspects of the invention. 
         FIG. 5  shows an illustrative schematic of an exemplary circulating fluid-bed gasifier that can be used in one embodiment according to aspects of the invention. 
         FIG. 6  shows an illustrative schematic of an exemplary transport fluid-bed gasifier that can be used in one embodiment according to aspects of the invention. 
         FIG. 7  shows an illustrative schematic of an exemplary entrained-flow gasifier with a membrane wall and diametrically opposed burners that can be used in one embodiment according to aspects of the invention. 
         FIG. 8  shows an illustrative schematic of an exemplary entrained-flow gasifier with a refractory lined wall and a top burner that can be used in one embodiment according to aspects of the invention. 
         FIG. 9A  shows an illustrative schematic of an exemplary entrained-flow gasifier with a membrane wall and a top burner that can be used in one embodiment according to aspects of the invention. 
         FIG. 9B  is a cross-sectional view taken along the line A-A′ of  FIG. 9A . 
         FIG. 10  is shows an illustrative schematic of an exemplary cooling system that can be used in one embodiment according to aspects of the invention. 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments of the present invention relate to systems and methods supplying hydrogen to a hydrocatalytic reaction through gasification of a biomass material to produce a fuel product that complies with a fuel pathway specified in U.S. renewable fuel standard program (RFS) regulations. In a preferred embodiment, the biomass material comprises hog fuel. The hydrocatalytic reaction, such as catalytic reduction reactions, can necessitate the input of significant quantities of molecular hydrogen, particularly if the molecular hydrogen is being introduced under dynamic flow conditions. An advantage of embodiments of the invention may include reducing the carbon footprint of the fuels formed from the hydrocatalytic reaction because at least a portion of the hydrogen used in the hydrocatalytic reaction has low carbon footprint. A fuel with low carbon footprint can qualify for certain governmental status that provides certain benefits. 
     In particular, in 2005, the Environmental Protection Agency (EPA) released its Renewable Fuel Standards (RFS-I). Two years later, the program was expanded under the Energy Independence and Security Act of (EISA) of 2007, which calls for a certain amount of advanced biofuels that are non-ethanol. In 2010, the EPA submitted revisions—RFS-II—to the previous renewable fuel standards (RFS-I). The RFS-I and RFS-II can be collectively referred to as RFS. Part of the regulations include an incentive program that provides for an award of Renewable Identification Numbers (RIN) for the production of fuels in accordance with certain pathways that are designed to be environmentally less harmful than the traditional methods of producing fuels. Among the several approved pathways, there are some related to the use of cellulosic containing biomass (cellulosic biomass) that can earn Cellulosic Renewable Identification Numbers (C-RIN&#39;s). The use of cellulosic biomass can also aid fuel producers in meeting their Renewable Volume Obligations (RVO) as well. 
     The present disclosure provides, in certain embodiments, a fuel product (for example diesel fuel and/or gasoline) that complies with U.S. renewable fuel standard program (RFS) regulations for generating the cellulosic renewable identification number. In certain embodiments, the fuel product may be produced via a fuel pathway specified in U.S. RFS regulations for generating cellulosic renewable identification numbers. For example, the pathway may include a cellulosic fuel pathway, a cellulosic renewable identification number-compliant pathway, a pathway compliant in generating, producing, preparing, or making, a cellulosic renewable identification number-compliant fuel, or a pathway that complies with a fuel pathway specified in U.S. RFS regulations for generating the cellulosic renewable identification number. The present disclosure provides embodiments that also allow fuel producers to qualify for desired credits associated with reduced GHG life cycle emissions, including for example RINs under EISA associated with lower GHG emissions. 
     For example, to achieve cellulosic biofuel status, a 60% reduction from standard reference petroleum gasoline value of 91.6 grams CO 2  emitted/Megajoule of fuel (gCO 2 e/MJ). The target GHG emissions for cellulosic biofuels under RFS-II is about 36.6 gCO 2 e/MJ. Similarly, the target for advanced biofuels would be about 45.8 gCO 2 e/MJ. Reduction in the overall production process GHG emissions of the fuel produced is desired. One way for such reduction is to reduce the amount of fossil fuels, such as natural gas, used in the process. In one exemplary process, approximately every 43 kiloton per year of natural gas combusted contributes approximately 10 gCO 2 e/MJ of the fuel generated in such process. As such, reducing the amount of natural gas that needs to be combusted (e.g., to provide hydrogen) to produce a fuel reduces the amount of CO 2  that is added to the emissions in calculating which category the fuel would qualify in a certain government program, such as RFS-II. Eliminating CO 2  emissions by combusting less natural gas facilitates achievement of the highest valued category of fuel in a government program, such as biofuel, particularly cellulosic biofuel, in the RFS-II, which typically requires the lowest amount of CO 2  emitted per MJ of fuel. Natural gas used as a source of hydrogen through steam methane reforming also leads to higher GHG emissions. As such, gasification of a biomass material instead of use of natural gas as a source of hydrogen for embodiments provided herein eliminates carbon dioxide from being added to the emissions for the fuel being produced, which allows the fuel to potentially more readily meet the requirements for a more favorable fuel status under a particular government program. 
     In a particular embodiment where debarked wood logs are more preferable for a hydrocatalytic reaction, hog fuel generated from at least one outer layer (such as barks or small branches) of wood logs delivered to a facility running the hydrocatalytic reaction can be removed and used in a gasification process to generate hydrogen for the hydrocatalytic reaction as well as other related processes. Additionally, biomass pellets made from wood may also be used. Use of hog fuel generated from an outer layer of wood logs intended for the hydrocatalytic reaction can reduce transport costs, improves process efficiency, as well as reduce carbon dioxide amount associated with transportation of raw material used to generated the biofuel as compared to a process where the material for the hydrocatalytic reaction is transported to the facility separately from the material for gasification. 
     As used herein, the term “hydrocarbons” refers to compounds containing both carbon and hydrogen without reference to other elements that may be present. Thus, heteroatom-substituted compounds are also described herein by the term “hydrocarbons.” The term “hydrocatalytic treatment” refers to a type of thermocatalytic reaction where the reaction is with hydrogen in the presence of a catalyst capable of activating molecular hydrogen, preferably a metal catalyst. The term “credit” or “renewable fuel credit” means any rights, credits, revenues, offsets, greenhouse gas rights or similar rights related to carbon credits, rights to any greenhouse gas emission reductions, carbon-related credits or equivalent arising from emission reduction trading or any quantifiable benefits (including recognition, award or allocation of credits, allowances, permits or other tangible rights), whether created from or through a governmental authority, a private contract or otherwise. According to one embodiment of the invention, the renewable fuel credit is a certificate, record, serial number or guarantee, in any form, including electronic, which evidences production of a quantity of fuel meeting certain life cycle GHG emission reductions relative to a baseline set by a government authority. Preferably, the baseline is a gasoline baseline. Non-limiting examples of credits include RINs and LCFS credits. 
     Various exemplary embodiments of the invention are further described with reference to the drawings. When like elements are used in one or more figures, identical reference characters will be used in each figure, and a detailed description of the element will be provided only at its first occurrence. Some features of the embodiments may be omitted in certain depicted configurations in the interest of clarity. Moreover, certain features such as, but not limited to, pumps, valves, gas bleeds, gas inlets, fluid inlets, fluid outlets and the like have not necessarily been depicted in the figures, but their presence and function will be understood by one having ordinary skill in the art. 
     Referring to  FIG. 1 , biomass feedstock  11  is provided to hydrocatalytic treatment system  12  where biomass feedstock  11  is reacted with hydrogen in the presence of a metal catalyst capable of activating molecular hydrogen to produce hydrocatalytically treated mixture  13 . 
     Referring to  FIG. 1 , biomass material  16  is provided to gasification system  17  for partial oxidation. In one embodiment, oxidant stream  18  provides gasification system  17  with an oxidant suitable to gasify biomass material  16 . As used herein, the term “oxidant” includes any oxygen containing compound capable of contributing to the gasification of at least a portion of a carbonaceous material, such as biomass material  16 . Illustrative oxidants can include, but are not limited to, air, oxygen, essentially oxygen, oxygen-enriched air, mixtures of oxygen and air, mixtures of air and/or oxygen with steam, mixtures of oxygen and one or more inert gases, for example, nitrogen and/or argon, or any combination thereof. Oxidant stream  18  can contain about 20 vol % oxygen or more, about 30 vol % oxygen or more, about 40 vol % oxygen or more, about 50 vol % oxygen or more, about 60 vol % oxygen or more, about 65 vol % oxygen or more, about 70 vol % oxygen or more, about 75 vol % oxygen or more, about 80 vol % oxygen or more, about 85 vol % oxygen or more, about 90 vol % oxygen or more, about 95 vol % oxygen or more, or about 99 vol % oxygen or more. As used herein, the term “essentially oxygen” refers to an oxygen stream containing more than 50 vol % oxygen. As used herein, the term “oxygen-enriched air” refers to a gas mixture containing oxygen in a range of about 21 to 50 vol % oxygen. In one embodiment, oxygen enriched air or essentially oxygen can be supplied by one or more air separation units (“ASU”) or a pressure swing absorber. The ASU can provide a nitrogen-lean and oxygen-rich stream for oxidant stream  18 , thereby minimizing the nitrogen concentration in the system. The ASU can be a high-pressure, cryogenic type separator that can be supplemented with air. In one embodiment, up to about 50 vol %, or up to about 40 vol %, or up to about 30 vol %, or up to about 20 vol %, or up to about 10 vol % of the total oxidant fed to the gasifier can be supplied by the ASU. In a preferred embodiment, a moderator gas (not shown) can be supplied to gasification system  17 , separately or with oxidant stream  18 , to control the temperature of gasification system  17 . Non-limiting examples of suitable moderator gases include steam, carbon dioxide, or a combination thereof. Conditions for applying oxidant stream  18  and the moderator gas, if used, are known to those skilled in the art. 
     In another embodiment, oxidant stream  18  can also include steam and/or natural gas, which can be delivered to gasification system  17  separately or with the oxidant in stream  18 . The partial oxidation of biomass material  16  produces gas mixture  19  comprising hydrogen and carbon monoxide. Gas mixture  19  can be referred to as synthesis gas or syngas. As shown, gasification system  17  is coupled to water-gas shift reaction zone, WGS zone  20 , to provide gas mixture  19  to WGS zone  20 . As can be seen, WGS zone  20  is external to hydrocatalytic treatment system  12 . In one embodiment, gasification system  17  is preferably in fluid communication with WGS zone  20 . At least a portion of gas mixture  19  is subject to a water gas shift reaction in WGS zone  20 , which converts the carbon monoxide from gas mixture  19  to hydrogen rich shifted synthesis gas product comprising hydrogen and carbon dioxide, which is shown as stream  21 . WGS zone  20  is coupled to hydrocatalytic treatment system  12  to provide stream  21  to hydrocatalytic treatment system  12 . In one embodiment, WGS zone  20  is preferably in fluid communication with hydrocatalytic treatment system  12 . As shown, at least a portion of the hydrogen rich synthesis gas product generated in WGS zone  20  is routed to hydrocatalytic treatment system  12  via stream  21  for use in a hydrocatalytic reaction. 
     In a preferred embodiment, the hydrogen contained in stream  21  is provided to hydrocatalytic treatment system  12  at a pressure in a range of about 10-200 bar, more preferably about 20 to 100 bar, most preferably 30 to 80 bar, and a temperature in a range of 35-450 degrees C., more preferably about 50 to 250 degrees C., and most preferably about 100 to 200 degrees C. In another embodiment, gasification system  17  is coupled to hydrocatalytic treatment system  12  to provide hydrocatalytic treatment system  12  with steam generated in gasification system  17  via stream  27 . In a preferred embodiment, the steam contained in stream  27  is provided to hydrocatalytic treatment system  12  at a pressure in a range of about 20-120 bar, more preferably about 40 to 100 bar, most preferably 40 to 90 bar. The steam can be saturated or with superheat. In one embodiment, steam from another source can be provided to hydrocatalytic treatment system  12 . In such an embodiment, stream  27  can be combined with steam from the boiler and the mixture of both can be provided as one stream or steam from the boiler and steam from gasification system  17  can be provided separately. In addition or alternatively, steam from gasification system  17  can be routed to WGS zone  20  via stream  27  as shown in  FIGS. 1 and 2  to facilitate additional hydrogen generation. 
       FIG. 2  comprises similar processes and systems and  FIG. 1 , and further includes processing zone  22  for further processing of hydrocatalytically treated mixture  13 . In one embodiment, at least a portion of hydrocatalytically treated mixture  13  is subject to one or more reactions in processing zone  22  to produce product stream  23  comprising higher molecular weight compounds. 
     Referring to  FIGS. 1-2 , in practice of one embodiment, biomass feedstock  11  is introduced to hydrocatalytic treatment system  12  along with a predetermined amount of hydrogen or hydrogen containing gas, preferably from stream  21 . Additional hydrogen from an external source can also be provided to hydrocatalytic treatment system  12  as needed, for example, during start up when gasification system  17  may not yet generate a sufficient amount of hydrogen. In such circumstance, in one embodiment, natural gas can also be provided to gasification system  17 . Biomass feedstock  11  reacts with hydrogen in the presence of a metal catalyst capable of activating molecular hydrogen to form hydrocatalytically treated mixture  13 . Biomass material  16  is provided to gasification system  17  where it is partially oxidized with oxidant provided by stream  18  to generate gas mixture  19  comprising hydrogen and carbon monoxide, or synthesis gas. Gas mixture  19  is discharged and introduced to WGS zone  20  to generate stream  21  comprising a hydrogen rich shifted synthesis gas product. Stream  21  is discharged and routed to hydrocatalytic treatment system  12  for use in a hydrocatalytic reaction. Referring to  FIG. 2 , in one embodiment, at least a portion of hydrocatalytically treated mixture  13  passed to processing zone  22  to produce product stream  23  comprising higher molecular weight compounds. 
     Any suitable type of biomass can be used as biomass feedstock  11 . Suitable cellulosic biomass sources may include, for example, forestry residues, agricultural residues, herbaceous material, municipal solid wastes, waste and recycled paper, pulp and paper mill residues, and any combination thereof. Thus, in some embodiments, a suitable cellulosic biomass may include, for example, corn stover, straw, bagasse, miscanthus, sorghum residue, switch grass, bamboo, water hyacinth, hardwood, hardwood chips, hardwood pulp, softwood, softwood chips, softwood pulp, and any combination thereof. Leaves, roots, seeds, stalks, husks, and the like may be used as a source of the cellulosic biomass. Common sources of cellulosic biomass may include, for example, agricultural wastes (e.g., corn stalks, straw, seed hulls, sugarcane leavings, nut shells, and the like), wood materials (e.g., wood or bark, sawdust, timber slash, mill scrap, and the like), municipal waste (e.g., waste paper, yard clippings or debris, and the like), and energy crops (e.g., poplars, willows, switch grass, alfalfa, prairie bluestream, corn, soybeans, and the like). The cellulosic biomass may be chosen based upon considerations such as, for example, cellulose and/or hemicellulose content, lignin content, growing time/season, growing location/transportation cost, growing costs, harvesting costs, and the like. 
     Biomass feedstock  11  may be natively present in any sizes, shapes, or forms, or it may be further processed prior to entering hydrocatalytic treatment in system  12 . Examples of further processing include washing (such as, with water, an acid, a base, combinations thereof, and the like), torrefaction, liquefaction, such as pyrolysis, or reduction in size. In some embodiments, the reduction in size may include chopping, grounding, shredding, pulverizing, and the like to produce a desired size. Thus, in some embodiments, providing a biomass material can comprise harvesting a lignocelluloses-containing plant such as, for example, a hardwood or softwood tree. The tree can be subjected to debarking, chopping to wood chips of desirable thickness, and washing to remove any residual soil, dirt and the like. 
     Biomass feedstock  11  is preferably treated to convert the cellulose and other complex carbohydrates into a more usable form, which can be further transformed into compounds with one or more alcohol functional groups through downstream reactions. While suitable for further transformation, soluble carbohydrates can be very reactive and can rapidly degrade to produce caramelans and other degradation products, especially under higher temperature conditions, such as above about 150° C. One way to protect soluble carbohydrates from thermal degradation is to subject them to one or more catalytic reduction reactions, which may include hydrogenation and/or hydrogenolysis reactions. Depending on the reaction conditions and catalyst used, reaction products formed as a result of conducting one or more catalytic reduction reactions on soluble carbohydrates may comprise, as mentioned, one or more alcohol functional groups, particularly including triols, diols, monohydric alcohols, and any combination thereof, some of which may also include a residual carbonyl functionality (e.g., an aldehyde or a ketone). Such reaction products are typically more thermally stable than soluble carbohydrates and may be readily transformable into fuel blends and other materials through conducting one or more downstream further processing reactions. That is, soluble carbohydrates formed during hydrothermal digestion may be intercepted and converted into more stable compounds before they have an opportunity to significantly degrade, even under thermal conditions that otherwise promote their degradation. 
     In a preferred embodiment, a hydrocatalytic reaction that takes place in system  12  of  FIGS. 1 and 2  is conducted in the presence of hydrogen, specifically molecular hydrogen, with a catalyst that is capable of activating molecular hydrogen to participate in various reactions such as hydrothermal digestion; catalytic reduction reactions, including hydrogenation, hydrogenolysis, and/or hydrodeoxygenation; and optionally hydrodesulfurization and hydrodenitrification. Any suitable hydrocatalytic reaction can take place in system  12 . Exemplary hydrocatalytic reactions, including hydrogenation and hydrogenolysis, are described in U.S. Publication Application No. US2011/0154721, the disclosure of which is incorporated herein by reference in its entirety. 
     For example, in one embodiment, hydrocatalytic treatment system  12  can comprise a reaction as described in US2011/0154721, such as a hydrogenolysis reaction and/or a hydrogenation reaction, where soluble carbohydrate is catalytically reacted with hydrogen to produce desired reaction products. Examples of desired or suitable reactions products may include, but are not limited to, alcohols, polyols, aldehydes, ketones, other oxygenated intermediates, and any combination thereof. For instance, hydrocatalytic treatment system  12  can comprise hydrogenation reaction  104  and/or hydrogenolysis reaction  106  of FIGS. 1-3 of US2011/0154721. The descriptions corresponding to hydrogenation reaction  104  and hydrogenolysis reaction  106  are provided by US2011/0154721, which is incorporated by reference in its entirety, and thus need not be repeated. 
     In another embodiment, hydrocatalytic treatment system  12  further comprises a digestion process to convert cellulose and other complex carbohydrates contained in biomass feedstock  11  into a soluble carbohydrate. As used herein, the term “soluble carbohydrates” refers to monosaccharides or polysaccharides that become solubilized in a digestion process. Any suitable digestion process that forms a pretreated biomass containing soluble carbohydrates can be used. Examples of suitable digestion processes can be found in U.S. Application Publication Nos. US2012/0152836, and US2012/0156743, the disclosure of each is incorporated herein by reference in its entirety. 
     In one embodiment, hydrocatalytic treatment system  12  can comprise a reaction as described in US2012/0152836. For instance, hydrocatalytic treatment system  12  can comprise any combination of hydrogenolysis systems  126 ,  126 A,  126 B, and  126 C shown in FIGS. 1-5 of US2012/0152836. In another embodiment, hydrocatalytic treatment system  12  can further comprise digestion system  106  shown in FIGS. 1-5 of US2012/0152836. The descriptions corresponding to digestion system  106  and hydrogenolysis systems  126 ,  126 A,  126 B, and  126 C are provided by US2012/0152836, which is incorporated by reference in its entirety, and thus need not be repeated. 
     In another embodiment, hydrocatalytic treatment system  12  can comprise a reaction as described in US2012/0156743. For instance, hydrocatalytic treatment system  12  can comprise hydrogenolysis system  120  shown in FIGS. 1-2 of US2012/0156743. In another embodiment, hydrocatalytic treatment system  12  can further comprise pretreat system  104 , optionally along with digestive system  190 , and/or treatment system  110  of FIGS. 1-2 of US2012/0156743. 
     It is understood that the hydrocatalytic treatment that takes place in hydrocatalytic treatment system  12  can employ aqueous phase and/or organic phase solvents. For example, US2011/0154721, US2012/0152836, and US2012/0156743 provide examples of hydrocatalytic treatment that occurs in aqueous phase. Exemplary descriptions of a hydrocatalytic treatment that takes place in an organic phase can be found in U.S. Application Publication No. US2013/0109896, the disclosure of which is hereby incorporated by reference in its entirety. 
     In one embodiment, hydrocatalytic treatment system  12  can comprise a reaction as described in US2013/0109896. For example, hydrocatalytic treatment system  12  can comprise organic phase hydrocatalytic treatment system  20  shown in FIG. 1 of US2013/0109896. In another embodiment, hydrocatalytic treatment system  12  can further comprise digestive system  10  shown in FIG. 1 of US2013/0109896. The descriptions corresponding to digestive system  10  and organic phase hydrocatalytic treatment system  20  are provided by US2013/0109896, which is incorporated by reference in its entirety, and thus need not be repeated. 
     In yet another embodiment, if a digestion process is employed, the digestion process preferably comprises hydrothermal digestion, particularly as described in U.S. Application Publication Nos. 61/665,641, filed on Jun. 28, 2012, 61/720,757, filed on Oct. 31, 2012, and 61/817,996, filed on May 1, 2013, the disclosures of which are hereby incorporated by reference in their entirety. Hydrothermal digestion of biomass feedstock  11  is preferably conducted in the presence of molecular hydrogen and a slurry catalyst capable of activating the molecular hydrogen. In such particular embodiments, the hydrothermal digestion of cellulosic biomass and the catalytic reduction of soluble carbohydrates produced therefrom preferably take place in the same vessel, which can be referred to as “in situ catalytic reduction reaction processes.” As used herein, the term “slurry catalyst” will refer to a catalyst comprising fluidly mobile catalyst particles that can be at least partially suspended in a fluid phase via gas flow, liquid flow, mechanical agitation, or any combination thereof. 
     In one embodiment, hydrocatalytic treatment system  12  can comprise a reaction as described in U.S. Application No. 61/665,641. For example, hydrocatalytic treatment system  12  can comprise at least one of hydrothermal digestion unit  2  and catalytic reduction reactor unit  4  shown in FIG. 1 of U.S. Application No. 61/665,641. In another embodiment, hydrocatalytic treatment system  12  can further comprise solids separation mechanism  24  also shown in FIG. 1 of U.S. Application No. 61/665,641. Solids separation mechanism  24  can comprise any suitable mechanism that can remove at least a solid contained in a product stream exiting catalytic reduction reactor unit  4 , such as reaction product takeoff line  18  shown in FIG. 1 of U.S. Application No. 61/665,641. Non-limiting examples of suitable solids separation mechanisms may include, for example, any number and combination of filters, hydroclones, centrifuges, membranes, and settling tanks. The descriptions corresponding to hydrothermal digestion unit  2 , catalytic reduction reactor unit  4 , and solids separation mechanism  24  are provided by U.S. Application No. 61/665,641, which is incorporated by reference in its entirety, and thus need not be repeated. 
     In another embodiment, hydrocatalytic treatment system  12  can comprise a reaction as described in U.S. Application No. 61/720,757. For example, hydrocatalytic treatment system  12  can comprise at least one of hydrothermal digestion unit  2  and polishing reactor  16  shown in FIG. 1 of U.S. Application No. 61/720,757. If employed, polishing reactor  16  shown in FIG. 1 of U.S. Application No. 61/720,757 is where one or more catalytic reduction reactions can further take place to protect soluble carbohydrates from thermal degradation as described. The descriptions corresponding to hydrothermal digestion unit  2  and polishing reactor  16  are provided by U.S. Application No. 61/720,757, which is incorporated by reference in its entirety, and thus need not be repeated. 
     In yet another embodiment, hydrocatalytic treatment system  12  can comprise a reaction as described in U.S. Application No. 61/817,996. For example, hydrocatalytic treatment system  12  can comprise at least one of hydrothermal digestion unit  2  and polishing reactor  16  shown in FIGS. 1-12 of U.S. Application No. 61/817,996. If employed, polishing reactor  16  shown in FIGS. 1-12 of U.S. Application No. 61/817,996 is where one or more catalytic reduction reactions can further take place to protect soluble carbohydrates from thermal degradation as described. The descriptions corresponding to hydrothermal digestion unit  2  and polishing reactor  16  are provided by U.S. Application No. 61/817,996, which is incorporated by reference in its entirety, and thus need not be repeated. 
     Hydrocatalytically treated mixture  13  is preferably subject to further processing to produce a higher molecular weight compound. In one embodiment, the further processing takes place in processing zone  22  shown in  FIG. 2 . Non-limiting exemplary further processing methods include (i) reforming reactor  38  shown in FIGS. 1-12 of U.S. Application No. 61/817,996, (ii) reforming reactor  28  shown in FIG. 1 of U.S. Application No. 61/720,757, (iii) processing system  130  shown in FIGS. 1-2 of US2012/0156743, (iv) processing step  136  shown in FIGS. 1-5 of US2012/0152836; and processing reaction  110  shown in FIGS. 1-3 of US2011/0154721. In general, suitable further processing reactions include, but are not limited to, hydrogenolysis reactions, hydrogenation reactions, condensation reactions, isomerization reactions, oligomerization reactions, hydrotreating reactions, alkylation reactions, and any combination thereof. 
     The further processing can comprise one or more reactions that may be catalytic or non-catalytic. It is to be understood that any number of reactors may be employed to carry out the further processing, such as that in processing zone  22 . In some embodiments, a first further processing reaction may comprise a condensation reaction. Additional further processing reactions may comprise any combination of further catalytic reduction reactions (e.g., hydrogenation reactions, hydrogenolysis reactions, hydrotreating reactions, and the like), further condensation reactions, isomerization reactions, desulfurization reactions, dehydration reactions, oligomerization reactions, alkylation reactions, and the like. Such reactions may be used to convert the initially produced soluble carbohydrates into a biofuel, including, for example, gasoline hydrocarbons, diesel fuels, jet fuels, and the like. As used herein, the term “gasoline hydrocarbons” refers to substances comprising predominantly C 5 -C 9  hydrocarbons and having a boiling point of about 32 to 204 degrees C. More generally, any fuel blend meeting the requirements of ASTM D2887 may be classified as a gasoline hydrocarbon. Suitable gasoline hydrocarbons may include, for example, straight run gasoline, naphtha, fluidized or thermally catalytically cracked gasoline, VB gasoline, and coker gasoline. As used herein, the term “diesel fuel” refers to substances comprising paraffinic hydrocarbons and having a boiling point in a range of about 187 to 417 degrees C., which is suitable for use in a compression ignition engine. More generally, any fuel blend meeting the requirements of ASTM D975 may also be defined as a diesel fuel. As used herein, the term “jet fuel” refers to substances meeting the requirements of ASTM D1655. In some embodiments, jet fuels may comprise a kerosene-type fuel having substantially C 8 -C 16  hydrocarbons (Jet A and Jet A-1 fuels). In other embodiments, jet fuels may comprise a wide-cut or naphtha-type fuel having substantially C 5 -C 15  hydrocarbons present therein (Jet B fuels). 
     Any suitable type of biomass can be used as biomass material  16  for gasification. Suitable biomass material may include, for example, forestry residues, agricultural residues, herbaceous material, municipal solid wastes, waste and recycled paper, pulp and paper mill residues, and any combination thereof. In some embodiments, a suitable biomass material may include, for example, corn stover, straw, bagasse, miscanthus, sorghum residue, switch grass, bamboo, water hyacinth, hardwood, hardwood chips, hardwood pulp, softwood, softwood chips, softwood pulp, and any combination thereof. Leaves, roots, seeds, stalks, husks, and the like may be used as a source of the biomass material. Common sources of biomass material may include, for example, agricultural wastes (e.g., corn stalks, straw, seed hulls, sugarcane leavings, nut shells, and the like), wood materials (e.g., wood or bark, sawdust, timber slash, mill scrap, and the like), municipal waste (e.g., waste paper, yard clippings or debris, and the like), and energy crops (e.g., poplars, willows, switch grass, alfalfa, prairie bluestream, corn, soybeans, and the like). As shown in  FIGS. 1 and 2 , it is understood that biomass material  16  does not comprise hydrocatalytically treated mixture  13 . In one embodiment, biomass material  16  has not been catalytically treated. 
     In one particular embodiment, biomass material  16  comprises hog fuel, which includes but is not limited to outer layers of logs, mainly bark but also small branches and leaves, also sawdust. In one embodiment, biomass feedstock  11  and biomass material  16  can comprise the same or similar material, where efficiency can be improved because the same supply chain can provide both biomass feedstock  11  and biomass material  16 . Hog fuel is generally sawmill refuse that has been fed through a disintegrator or hog by which the various sizes and forms are reduced to a practically uniform size of chips or shreds. Hog fuels generally contain approximately 70% to 95% bark with the residue being primarily wood. In another embodiment biomass material  16  comprises wood residues. 
     In a particular embodiment where debarked wood logs are more preferable as biomass feedstock  11  for hydrocatalytic treatment system  12 , biomass material  16  can be generated from at least one outer layer (such as barks or small branches) of biomass feedstock  16  comprising wood logs delivered to a facility running hydrocatalytic treatment system, where an outer layer can be removed and routed to gasification system  17  to generate hydrogen for hydrocatalytic treatment system  12  as well as other related processes. Biomass feedstock  11  can be further processed to render the wood logs into a more preferred format as discussed herein. Use of biomass material  16  generated from biomass feedstock  11  allows for co-processing of biomass material, which can reduce transport costs, improves process efficiency, as well as reduce carbon dioxide amount associated with transportation of raw material used to generated the biofuel as compared to a process where the material for the hydrocatalytic reaction is transported to the facility separately from the material for gasification. 
     In a particular embodiment, forest material such as wood logs delivered to a facility running hydrocatalytic treatment system  12  can have the outer bark layer of the logs removed to produce debarked wood more preferable in certain embodiments for hydrocatalytic treatment system  12 . The outer layers removed can then be routed to gasification system  17  for gasification to provide hydrogen for hydrocatalytic treatment system  12  as well as other related processes. In certain embodiments, fuel products generated using hydrogen from hog fuels instead of natural gas as a hydrogen source can allow for reaching cellulosic biofuel status under a government program, such as the RFS-II. 
     In gasification system  17 , biomass material  16  is partially oxidized to produce gas mixture  19  which comprises hydrogen (H 2 ) and carbon monoxide (CO). Biomass material  16  can enter gasification system  17  in any form, such as a dry feed or a wet feed, including a solid, a liquid, or a solid coated with a liquid. The term “liquid” used in context of biomass material  16  refers to a carbonaceous feed that is a liquid, an emulsion, or a pumpable slurry at the feed pressure and temperature into gasification system  17 . 
     Gasification system  17  can comprise any suitable gasification system that can partially oxidize biomass material  16  to generate gas mixture  19 . For example, in one embodiment, if biomass material  16  enters gasification system  17  as a solid, any suitable dry feed gasification system can be used to partially oxidize biomass material  16  to produce gas mixture  19 . In another embodiment, if biomass material  16  enters gasification system  17  as a liquid, any suitable wet feed gasification system can be used to partially oxidize biomass material  16  to produce gas mixture  19 . Dry feed and wet feed gasification systems are known to those of ordinary skill in the art. 
     The gasification process is well known in the art and can be employed using solid and liquid carbonaceous sources. The gasification process uses partial oxidation or incomplete combustion to convert carbonaceous materials at high temperature into synthesis gas (“syngas”), which comprises carbon monoxide and hydrogen. This is in contrast to a full combustion or complete oxidation reaction where primarily steam and carbon dioxide are produced by the reaction of a fuel, such as a carbonaceous material, and an oxidant, such as oxygen. A complete oxidation typically take place under conditions that have excess oxygen according to the following equation: 
       C n H m +( n +¼ m )O 2 →½ m H 2 O+ n CO 2   Equation (1)
 
     For gasification processes, oxygen is restricted to less than a stoichiometric concentration of oxygen relative to fuel where process generates primarily hydrogen and carbon monoxide through incomplete combustion or partial oxidation of the fuel, as represented by the equation below: 
       C n H m +¼ n O 2 →½ m H 2   +n CO  Equation (2)
 
     The operating conditions, including temperature, vary with the gasifier and feed type as described further below. Gasification system  17  can comprise a single gasifier, which can also be referred to as gasification reactor vessel, or two or more gasifiers of differ rent or the same type arranged in series and/or parallel. One or more oxidants and one or more feed, i.e. biomass material  16  can be directed, fed, or otherwise introduced to one or more particular gasifier of gasification system  17 . The one or more oxidants and one or more feed can be introduced to gasification system  17  continuously, intermittently, interspersingly, simultaneously, separately, sequentially, or a combination thereof. Any number of oxidants can be directed, fed, or otherwise introduced to gasification system  17 . For example, the number of oxidants introduced to gasification system  17  can be 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more. It is understood that conditions for partial oxidation or incomplete combustions may be provided at least by limiting the amount of oxygen available in recovery and gasification system  100  to less than what is required for full oxidation or combustion. For example, this can be done by controlling the amount of oxidant stream  18  entering recovery and gasification system  100  and/or by the amount of oxygen in oxidant stream  18  itself. 
     Various types of gasifiers can be utilized as discussed and described herein. In general, the gasifier types can be grouped into three principal categories: moving-bed gasifiers, fluid-bed gasifiers, and entrained-flow gasifiers. Each of the three types can be used with solid carbonaceous material. The entrained-flow gasifier can particularly process liquid carbonaceous material efficiently. Exemplary commercial gasification providers include GE Energy, Conoco Philips E-Gas, Shell, Siemens, KBR Transport, and British Gas Lurgi (BGL). For example, gasification system  17  can entail one or more circulating solids or transport gasifiers, one or more fixed bed gasifiers, one or more fluidized bed gasifiers, one or more entrained flow gasifiers, or a combination thereof. An exemplary gasifier suitable for use according to one or more embodiments discussed and described herein, particularly when biomass material  16  enters gasification system  17  as a liquid, can be a gasifier configured according to the Shell Gasification Process (SGP) as known to those skilled in the art. 
     In general, moving-bed gasifiers, which can also be called fixed-bed gasifiers in certain instances, have a bed on which the dry or solid feed moves downward under gravity as it is gasified by a flow of oxidant to generate synthesis gas. In one embodiment, the oxidant flow is counter-current to the movement of the feed. In such an embodiment, the hot synthesis gas generated is preferably used to preheat and pyrolyse the downward flowing coal. In one embodiment, the size of feed entering a moving-bed gasifier, if one is used, is in a range of about 6 to 50 mm. In another embodiment, the outlet gas temperature of a moving-bed gasifier is in a range of about 425 to 650 degrees C. 
       FIG. 3  provides one non-limiting exemplary embodiment of a moving-bed or fixed-bed gasifier with reference numeral  300 , such as a Sasol-Lurgi gasifer. Gasifier  300  includes feed lock  302 , reactor vessel  304 , grate  306 , and ash lock  308 . In operation of one embodiment, a sized solid feed  310  comprising biomass material  16  (shown in  FIGS. 1 and 2 ) with particles preferably greater than about 4 mm, preferably in a range of about 6 to 50 mm, enters reactor vessel  304  through feed lock  302  and moves down through a bed formed inside reactor vessel  304 . Oxygen stream  312  and steam  314  enter at a bottom of the bed, through grate  306 . In a preferred embodiment, oxygen stream  312  and steam  314  corresponds to oxidant stream  18  of  FIGS. 1 and 2 . In the embodiment shown, oxygen stream  312  and steam  314  combine with each other before entering reactor vessel  304 . In one embodiment, gasifier  300  can be a pressurized gasifier, where oxygen stream  312  and steam  314  have a pressure of about 20 bar or more. 
     In one embodiment, reactor vessel  304  has different reaction zones distinguishable from top to bottom, starting with a drying zone where moisture is released, below which is a devolatization zone where pyrolysis takes place, below which is a reduction zone or gasification zone where mainly endothermic reactions occur, below which is an exothermic oxidation or combustion zone, and an ash bed at the bottom of reactor vessel  304 . It is understood that the transition from one zone to the next is gradual. As shown in  FIG. 3 , gasifier  300  is operated in a counter-current mode where oxygen stream  312 , steam  314 , and syngas flow upwards counter-current to the movement of feed  310 . In such an embodiment, higher temperature ash exchanges heat with lower temperature incoming reagents, such as oxygen stream  312 , steam  314 , or air, while at the same time higher temperature synthesis gas exchanges heat with lower temperature incoming feed  310 . As shown in  FIG. 3 , synthesis gas stream  320  exits gasifier  300  near a top of reactor vessel  304 . Ash generated in reactor vessel  304  passes through grate  306  and the ash lock  308  before it exits gasifier  300  as ash stream  316 . 
     In one embodiment, the temperature profile in gasifier  300  can vary between about 800 and 1200 degrees C., such as at least 1000 degrees C., as feed  310  moves through the different zones in reactor vessel  304 . In another embodiment, the temperature profile in gasifier  300  can be up to about 1700 degrees C. In one embodiment, synthesis gas stream  30  leaves gasifier  300  at a temperature in the range of 375 to 650 degrees C. It is understood by one of ordinary skill in the art that it is typically difficult for a moving-bed or fixed-bed gasifier, such as gasifier  300 , to handle high melting ash. In one embodiment, the operating conditions can be adjusted accordingly. 
     With respect to the second type of gasifier, fluid-bed gasifiers, in general, provide conditions that promote mixing between feed and oxidant, thereby ensuring an even distribution of material in the bed. Fluid-bed gasifier technology is generally based on the velocity of the flow of gas (oxidant and syngas) through the reactor. The lower range of gas velocity includes a stationary or bubbling fluid bed reactor where the gas velocity is low enough to provide a distinction between the dense phase or bed and the freeboard where the solid particles from the feed disengage from the flow of gas. As the gas velocity increases, the higher range of gas velocity includes a transport reactor where all the solid particles are carried with the gas and full pneumatic transport is achieved. The region between the two ends of the gas velocities spectrum includes a circulating fluid bed reactor where the differential velocity between gas and solids reaches a maximum at intermediate gas velocities. In general, operation of a fluid-bed gasifier depends on the size of feed, which should be in a range where the particles of feed can be lifted by the flow of gas. In one embodiment, the size of feed entering a fluid-bed gasifier, if one is used, is in a range of about 6 to 10 mm. In another embodiment, the operating temperature of a fluid-bed gasifier is below the softening point of ash, which is typically, in one embodiment, in a range between about 800 to 1100 degrees C., such as about 1000 degrees C. In another embodiment, the operating temperature is up to about 1700 degrees C. In yet another embodiment, the outlet gas temperature of a fluid-bed gasifier is in a range of about 750 to 1050 degrees C. It is understood by one of ordinary skill in the art that it is typically difficult for a fluidized-bed gasifier, such as gasifiers  400 ,  500 , or  600 , to handle high melting ash. In one embodiment, the operating conditions can be adjusted accordingly. 
       FIG. 4  provides one non-limiting exemplary embodiment of a bubbling or stationary fluidized bed gasification gasifier with numeral reference  400 . As shown, gasifier  400  comprises reactor vessel  402 , having product gas outlet  403  disposed at or near its upper portion, feed inlet  404 , reagent inlet  405  at or near a lower portion of reactor vessel  402 , and fluidized bed  406  having a bed height  407  extending from a bottom of reactor vessel  402  to a position in reactor vessel  402 , and ash discharge  409  at or near a bottom of reactor vessel  402 . 
     During operation of gasifier  400 , feed material  410  comprising biomass material  16  (shown in  FIGS. 1 and 2 ) enters reactor vessel  402  through feed inlet  404 , which preferably comprises a fluidizing nozzle to produce particles having an appropriate or desired size. In one embodiment, feed particles that enter reactor vessel  402  have a size in a range of about 6 to 10 mm, Oxidant, such as, air, oxygen, or steam enters reactor vessel  402  through reagent inlet  405 . In addition to or as an alternative, feed material  410  can also enter reactor vessel  402  through reagent inlet  405 . In one embodiment, reagent inlet  405  corresponds to oxidant stream  18  of  FIGS. 1 and 2 . Introduction of feed material  410  and oxidant creates fluidized bed  407  in reactor vessel  402 . Ash created in the gasification process is discharged through ash discharge  409 , and synthesis gas generated in the gasification process is discharged through product gas outlet  403 . The height of fluidized bed  407  will vary, depending on such factors as reactor vessel temperature and pressure and input rates of feed inlet  404  and reagent inlet  405 , and discharge rates of ash discharge  409  and product gas outlet  403 . In one embodiment, the flow of gas through reactor vessel  402  is configured to allow fluidized bed  407  to form. 
     In one embodiment, a circulating fluid bed comprises a centrifugal separator, generally a cyclone separator to separate and recirculate a portion of the solid particles, which are contained in the gas exiting a reactor vessel, back to the reactor vessel where feed material is gasified. In a preferred embodiment, the separated solid particles are fluidized prior to their recirculation into the reactor vessel to promote even distribution over the width of the fluidized bed in the reactor vessel.  FIG. 5  provides one non-limiting exemplary embodiment of circulating fluidized bed gasifier with numeral reference  500 . Gasifier  500  comprises reactor vessel  502 , oxidant inlet  506  and feed inlet  532 , which are disposed near a bottom portion of reactor vessel  502 , and separator  508  coupled with an upper portion of reactor vessel  502  via opening  510 . There can be one or more separators. Separator  508  preferably comprises a cyclone separator. As shown, separator  508  comprises chamber  512 , which is coupled to standpipe  514 , which itself is coupled to riser  516  through horizontal channel  518 . As shown, riser  516  is coupled to riser  520  through inclined channel  522 , and riser  520  in turn is coupled to reactor chamber  502  through inclined channel  524 . Standpipe  514 , riser  516 , and horizontal channel  518  form a siphon-trap-like gas seal. In an alternative embodiment, inclined channel  522  and riser  520  can be omitted so that riser  516  can be coupled directly to reactor vessel  502  through inclined channel  524 . 
     During operation, oxidant  504  enters reactor vessel  502  via oxidant inlet  506 . Feed  530  comprising biomass material  16  (shown in  FIGS. 1 and 2 ) enters reactor vessel  502  through feed inlet  532 . Gasification of feed  530  takes place in reactor vessel  502  when oxidant  504  and feed  530  mix with one another. Gas comprising syngas and other reactants and products and entrained with solid particles in reactor vessel  502  move upward toward and through opening  510  and into separator  508 . Separator  508  separates gas exiting reactor vessel  502  from the solid particles, Separated gas  536  exits gasifier  500  through outlet  538 , The remaining solid particles are moved through standpipe  514 , risers  516  and  520 , horizontal channel  518 , and inclined channels  522  and  524 . The arrangement of standpipe  514 , risers  516  and  520 , horizontal channel  518 , and inclined channels  522  and  524  allows solid particles to return to reactor chamber  502  and prevents unwanted escape of gas from reactor vessel  502  through opening  526  in the direction of cyclone separator  508 . 
     To ensure that solids collected in the region of the gas seal formed by standpipe  514 , riser  516 , and horizontal channel  518  do not become compacted and deposited, fluidizing gas or air is supplied by means of fluidizing device  528  providing flow essentially from beneath horizontal channel  518 . Ash  534  formed during gasification is discharged from gasifier  500  through or near a bottom portion of reactor vessel  502 . 
     In one embodiment, the velocity of gas flowing through gasifier  500  is in a range of about 5 to 8 m/s or another other suitable velocity that can ensure most of the solid particles in reactor vessel  502  are entrained and flow upward to leave reactor vessel  502 . In one embodiment, oxidant  504  can be fed as primary air into reactor vessel  502  below nozzle grate  540 . 
       FIG. 6  provides one non-limiting exemplary embodiment of a transport fluid bed gasifier with numeral reference  600 . Gasifier  600  comprises a riser  602  above mixing zone  604 . As shown, mixing zone  604  includes partial oxidation zone  606  wherein recirculating particulates are oxidized to form a high velocity stream of products (primarily carbon monoxide) and finely divided particles. 
     Oxidant is introduced to partial oxidation zone  606  through inlet  608 . Oxidant is generally fed at a rate suitable to control the temperature of partial oxidation zone  606  and riser  602 , Gasifier  600  further comprises feed injection zone  610 , which is preferably disposed in mixing zone  604  above partial oxidation zone  606 . Feed comprising biomass material  16  (shown in  FIGS. 1 and 2 ) is injected through feed stream  612  into feed injection zone  610  and mixed with the high velocity stream of effluents and particles from partial oxidation zone  606 . 
     Feed stream  612  can be introduced as a solution, slurry, emulsion, suspension, etc. of solids, liquids or gases depending on the state of biomass material to be converted. Typically, solid can be dissolved and/or suspended in a hydrocarbon carrier liquid for ease of handling and pumping. Feed in feed stream  612  can be introduced to feed injection zone  610  and/or mixing zone  604  in stages as desired depending, in part, on the composition of the feed, composition of the reaction effluent gas and process parameters of gasifier  600  to ensure suitable operation thereof. 
     Steam is preferably injected into mixing zone  604  above feed injection zone  610  via inlet  616 , Alternatively and/or additionally, steam can be injected with the feed, Steam can also be injected with oxidant in stream  608 . The effluents of mixing zone  604  are passed under reducing conditions through the riser  602  where steam reacts with carbon and the feed to form hydrogen and carbon monoxide. 
     The high velocity partial oxidation products induce a rapid internal recirculation flow of carrier particles in riser  602  which act like a thermal flywheel to efficiently transfer heat from partial oxidation zone  606  to adiabatic pyrolysis zone  620  in riser  602  to supply heat for the endothermic gasification. Materials suitable for use as carrier particles circulating in gasifier  600  are finely divided refractory materials which have a large surface area and are generally inert at the reaction conditions of the present process. Examples are particulated alumina and silica, and spent catalyst from a fluidized catalytic cracking (FCC) reactor. 
     The reaction effluent from riser  602  passes into separation zone  622  where carrier particles are recovered from the reaction effluent to give gas stream  636  that is essentially free of particulates. Separation zone  622  preferably comprises one or more high efficiency cyclone separation stages. Particle-laden reaction effluent from riser  602  is fed to cyclone  624  through line  626 . Additional secondary cyclone separators (not shown) can be used if required. 
     Cyclone  624  is coupled to dipleg  628  having particles holdup zone  630  for increasing the residence time of the carrier particles, if desired, and transfer line  632  for conveying the particles to partial oxidation zone  606  at a rate sufficient to sustain continuous operation of the partial oxidation zone  606  and feed injection zone  610 . Separation zone  622  further comprises bleed line  634  through which a portion of the solids from holdup zone  630  can be bled from gasifier  600  to maintain a desired maximum concentration of metals on the solids. 
     Depending on the design operating pressure, gasifier  600  can operate at a temperature suitable for promoting gasification without the need for any catalytic activity of the circulating carrier particles. Gasification can typically commence at a temperature as low as about 650 degrees C. Preferably, gasifier  600  operates in a temperature range of about 750 to 1050 degrees C., measured at an outlet of riser  602 . The operating temperature range is generally controlled by specifying the rate of oxidant supply to partial oxidation zone  606  and the rate of carrier recirculation. Gasifier  600  can be designed to operate at an elevated pressure, up to about 4.0 MPa (about 600 psig), to increase handling capacity per unit reactor cross-sectional area. 
     With respect to the third type of gasifier, in general, entrained-flow gasifiers operate with the flow of feed and flow of thermal energy in a co-current manner. In a preferred embodiment, the residence time when the feed and thermal energy flow contact one another is in a range of about 0.1 to 20 seconds. If the feed is solid, it is formatted to a size of about less than 100 μm to promote mass transfer and allow transport in the gas. Entrained-flow gasifiers can handle a wide range of feed materials. The gasification usually takes place in a combustion chamber which operates at a temperature in the range of about 800 to 1700 degrees C., preferably about 1000 to 1.700 degrees C., and at a pressure in the range of about 20 to 70 bar. In another embodiment, the outlet gas temperature of an entrained-flow gasifier is in a range of about 1250 to 1600 degrees C. 
     In general, entrained-flow gasifiers can have various configurations based on a combination of the location of the burner(s) and the lining of the gasifier. An entrained-flow gasifier can have one or more burners preferably located in the top portion or near a bottom portion of a reactor chamber. Further, an entrained-flow gasifier can comprise a refractory lined wall or a membrane wall. The refractory lined wall is configured to protect a reactor vessel from corrosive slag, thermal cycling. The membrane wall performs a similar function using a cooling screen protected by a layer of refractory material to provide a surface on which the molten slag solidifies and flows downwardly to the quench zone at the bottom of the reactor. In one embodiment, if biomass material  16  is fed to gasification system  17  as a dry feed, at least one gasifier in accordance with Shell Coal Gasification Process (SCGP) can be used. In another embodiment, if biomass material  16  is fed to gasification system  17  as a liquid feed, at least one gasifier in accordance with Shell Gasification Process (SGP) can be used. It is understood that the choice between a refractory lined gasifier and a membrane wall gasifier is determined by the ash properties of the feed as known to those skilled in the art. That is, a dry feed can be gasified using a gasifier in accordance with Shell Gasification Process (SGP), and a liquid feed can be gasified using a gasifier in accordance with Shell Coal Gasification Process (SCGP). 
       FIG. 7  provides one non-limiting exemplary embodiment an entrained flow gasifier having numeral reference  700 . Gasifier  700  has a similar configuration to that of a gasifier that can be used in the Shell Coal Gasification Process (SCGP). As shown, gasifier  700  has pressure shell  702 , membrane wall  704  and reaction zone  706 . In one embodiment, membrane wall  704  is composed of vertical conduits through which cooling fluid flows. The cooling fluid is preferably water. The cooling fluid is supplied to membrane wall  704  via supply line  708  to distributor  710 . The used cooling fluid is discharged from gasifier  700  via common header  712  and discharge line  714 . Gasifier  700  is further provided with quench gas supply  716 , discharge line  718  for the product gas mixture, including syngas, generated in reaction zone  706 , and discharge line  720  for slag. Gasifier  700  further comprises a layer of refractory material coupled to membrane wall  704  to further protect pressure shell  702  from the high temperature of reaction zone  706 . Pressure shell  702  may comprise any suitable material, such as, for example, steel. Non-limiting examples of a suitable refractory material can include alloys of silica, alumina, iron, chromium, zirconium, and/or other high temperature materials. 
     As shown, gasifier  700  comprises at least two diametrically opposed burners  722  through which feed comprising biomass material  16  (shown in  FIGS. 1 and 2 ) is introduced to reaction zone  706 . Gasifier  700  can comprise any number of pairs of burners  722 , for example, two or more pairs of such burners at the same elevation, or alternatively at different elevations. In a preferred embodiment, burners  722  are disposed near a bottom portion of gasifier  700 . Any suitable burner can be used. Non-limiting exemplary suitable burners for a solid feed are, for example, described in U.S. Pat. No. 4,523,529 and U.S. Pat. No. 4,510,874. As shown, burners  722  are fed by feed supply line  724  and oxidant supply line  726 , which are preferably mixed before being fed to burners  722 . As shown, feed supply line  724  is mixed with oxidant supply line  726  near a nozzle of burners  722 . Syngas formed from the gasification process can exit gasifier  700  through discharge line  718 , and slag formed from the gasification process can exit gasifier  700  through discharge line  720 . 
     In one embodiment, feed can be pulverized to a desired size and transported through feed supply line  724  as a dense phase in an inert gas (such as nitrogen or carbon dioxide), acting as a carrier gas. In another embodiment, viscous liquid feed can also be used. 
     During operation, feed mixed with oxidant is introduced to reaction zone  706  through burners  722 . The reactions taking place in reaction zone  706  occurs rapidly, in a range of about 0.5 to 4 seconds. Product gas leaves gasifier  700  through discharge line  718 , and slag leaves through discharge line  720  at or near the bottom of gasifier  700  where it is quenched in a water bath. In one embodiment, the operating temperature of gasifier  700  is about at least about 1000 degrees C. and the operating pressure of gasifier  700  is in a range of about 15 to 80 bar, preferably in a range of about 25 to 45 bar. 
       FIG. 8  provides one non-limiting exemplary embodiment an entrained flow gasifier having numeral reference  800 . Gasifier  800  has a similar configuration to that of a gasifier that can be used in the Shell Gasification Process (SGP). As shown, gasifier  800  comprises pressure shell  802 , refractory liner  804  and reaction zone  806 . Pressure shell  802  may comprise any suitable material, such as, for example, steel. Non-limiting examples of a suitable refractory material for use as refractory liner  804  can include alloys of silica, alumina, iron, chromium, zirconium, and/or other high temperature materials. 
     As shown, gasifier  800  comprises burner  808  disposed at or near a top portion of gasifier  800  preferably with its outlet directed downwardly. Feed  810  comprising biomass material  16  (shown in  FIGS. 1 and 2 ) is introduced to reaction zone  806  through burner  808 . In a preferred embodiment, gasifier  800  comprises one burner. Any suitable burner can be used. Non-limiting exemplary suitable burners for a solid feed are, for example, described in U.S. Pat. No. 4,523,529 and U.S. Pat. No. 4,510,874. As shown, oxidant  812  and moderator gas  814  are also fed to burner  808  along with feed  810 . The gasification product mixture is discharged from gasifier  800  via discharge line  816 . 
     During operation, feed  810  preferably mixed with oxidant  812  and optionally moderator gas  814  is introduced to reaction zone  806  through burner  808 . The reactions taking place in reaction zone  806  occurs rapidly, in a range of about 0.5 to 4 seconds. The product mixture is discharged from gasifier  800  through discharge line  816 . In one embodiment, the operating temperature of gasifier  800  is about at least about 1300 degrees C. and the operating pressure of gasifier  800  is in a range of about 30 to 70 bar, preferably in a range of about 35 to 65 bar. 
       FIG. 9A  provides a cross sectional view of one non-limiting exemplary embodiment an entrained flow gasifier having numeral reference  900 . Like gasifier  700  of  FIG. 7 , gasifier  900  has a membrane lined wall: but unlike gasifier  700 , the burner of gasifier  900  is located at or near a top portion of the gasifier. As shown, gasifier  900  comprises burner  902  disposed at or near a top portion of gasifier  900 , and burner  902  is preferably with its outlet directed downwardly. In a preferred embodiment, burner  902  is provided with oxidant supply conduit  904 , feed supply conduit  906 , and moderator gas supply conduit  908 . Gasifier  900  preferably comprises combustion chamber  910  in the upper half of gasifier  900 . As shown, combustion chamber  910  is provided with product gas outlet  912  at the bottom end and an opening for the outlet of the burner at its top end. Between combustion chamber  910  and the inner wall of pressure shell  912  is annular space  914 . Combustion chamber  910  comprises refractory layer  916  configured to reduce the heat transfer to pressure shell  912 . Refractory layer  916  is preferably coupled to cooling conduit  918  configured to cool refractory layer  916  by allowing water to flow therethrough. In the embodiment shown, cooling conduit  918  is arranged as a plurality of vertical tubes surrounding refractory layer  916 .  FIG. 9B  is a cross-sectional view taken along the line A-A′ of  FIG. 9A , which further depicts the vertical tubes of cooling conduit  918 . In another embodiment, conduits  918  may be arranged spirally wound around refractory layer  916 . Cooling conduit  918  can be coupled to the inner wall or outer wall of refractory layer  918 . As shown, the vertical tubes of cooling conduit  918  may optionally have common header  920  disposed at a top portion and common distributor  922  at a bottom portion for discharging water from and supplying water to cooling conduit  918 , respectively. Common header  920  is in fluid communication with steam discharge conduit  924  and common distributor  922  is in fluid communication with water supply conduit  926 . Annular space  914 , refractory layer  916 , and conduits  918  are configured to protect pressure shell  912  against the high temperatures of combustion chamber  910 . The vertical tubes of cooling conduit  918  shown in  FIGS. 1 and 2  can also be referred to as a membrane wall. 
     Cooling of refractory layer  916  by cooling conduit  918  may be achieved by heat exchange with water of a lower temperature entering common distributor  922  and flowing through cooling conduit  918 . Coupled to product gas outlet  912  is passage  928  configured to direct product mixture exiting combustion chamber  910  toward quenching zone  940 , which is disposed at or near a bottom portion of gasifier  900 . Passage  928  further comprises outlet  930  that allows the addition of a quenching medium to the product mixture leaving combustion chamber  910 . 
     As shown, gasifier  900  further comprises pathway  932  that allows the product mixture to flow upward to exit gasifier  900  through outlet  934 . Pathway  932  is preferably an annular space between passage  928  and intermediate wall  936 . In  FIG. 9A , space  938  between intermediate wall  936  and pressure shell  912  holds water at level  938 . Outlet  934  is located above water level  938 . Referring to  FIG. 9A , quenching zone  940  is contained in the space below the end of passage  928  and between intermediate wall  936  and a bottom portion of pressure shell  912 . Quenching zone  940  also comprises slag generated from the gasification process, which can be discharged from gasifier  900  via outlet  942 . 
     In one embodiment where an entrained-flow gasifier is used, oxidant is preheated and mixed with a moderator gas before the mixture is combined with feed prior to being fed to the burners of the gasifier. In one embodiment, the burners of an entrained-flow gasifier comprise a pressure atomizing burner. In another embodiment, the burner of an entrained-flow gasifier comprises a co-annular or multi-orifice burner comprising blast atomization. Exemplary descriptions of a multi-orifice burner are provided by U.S. Pat. No. 5,273,212 and U.K. Patent Application Publication No. GB2034456, the disclosures of which are incorporated herein by reference. 
     In general, in an exemplary embodiment, a multi-orifice burner comprises a number of slits at the burner outlet and hollow wall members with internal cooling fluid passages. The passages may or may not converge at the burner outlet. Instead of comprising internal cooling fluid passages, the burner may be provided with a suitable ceramic or refractory lining applied onto or suspended adjacent to an outer surface of the burner (front) wall for resisting the heat load during operation of the burner. In certain embodiments, an exit of one or more passages may be retracted or protruded. The burner preferably has 4, 5, 6 or 7 passages. A particular exemplary process to gasify liquid feed using an entrained flow gasifier equipped with a multi-orifice burner is provided by EPO Application Publication No. EP759886, the disclosure of which is incorporated herein by reference. In general, EP759886 describes a process for partial oxidation of a liquid carbonaceous feed where an oxidant and a liquid carbonaceous feed are supplied to a gasification zone through a multi-orifice (co-annular) burner, such as those disclosed by U.S. Pat. No. 5,273,212 and GB2034456, comprising a concentric arrangement of n passages or channels coaxial with the longitudinal axis of the burner. As disclosed by EP759886, in a particular embodiment, the oxidant, liquid carbonaceous feed, and a moderator gas are each supplied through separate channels of a multi-orifice (co-annular) burner having 6 passages. In one embodiment, either the oxidant or moderator gas is passed through the outermost passage. In another embodiment where n is greater than or equal to 4, either the oxidant or moderator gas is also passed through the innermost passage. In a non-limiting exemplary embodiment, the carbonaceous feed has a viscosity in a range of about 1 to 1000 cP and passes through one or more passages at a velocity in a range of about 2 to 30 m/s; the oxidant passes through one or more of the other passages at a velocity in a range of about 20 to 140 m/s; and the moderator gas passes through one or more of the remaining passages at a velocity in a range of about 5 to 140 m/s. In instances where viscous feed has a high content of volatile components, the gasification process described in U.S. Pat. No. 7,569,156 can be used. The disclosure of U.S. Pat. No. 7,569,156 is incorporated herein by reference. 
     In one embodiment, if a multi-orifice burner is used with a gasifier similar to gasifier  700  of  FIG. 7 , the number of passages is preferably 2. In another embodiment, if a multi-orifice burner is used with a gasifier similar to gasifier  800  or  900 , the number of passages is preferably 2 to 6. 
     It is understood that one of ordinary skill in the art can select the appropriate gasifier(s) and operating conditions associated with the particular gasifier(s) based on properties of biomass material  16  entering gasification system  17 . Vice versa, properties of biomass material  16  can be adjusted to a certain extent to match the desired operating conditions of selected gasifier(s). A combination of both is also possible where properties of biomass material  16  as well as type and operating conditions of selected gasifier(s) can be modified to achieve desired or optimal results, such as cost, efficiency, product quality, etc. 
     For example, if biomass material  16  is sufficiently fluid to be pumped, the slurry can be introduced into gasification system  17  alone, or as a suspension using a carrier fluid (not shown), such as air, nitrogen, carbon dioxide, carbon monoxide, syngas, hydrogen, steam, nitrogen-free gas, low-oxygen gas, oxygen-free gas, and/or a combination of these carrier fluids. In embodiments where biomass material  16  are sufficiently fluid to be pumped, gasification system  17  preferably comprises at least one entrained-flow gasifier. 
     In embodiments where biomass material  16  and/or bottom fraction are introduced to gasification system  17  as a solid, gasification system  17  can preferably comprise any of the three types of gasifier: moving-bed, fluid-bed, or entrained flow. The size of the solid particles fed to the gasifier is preferably formatted to suit the operating conditions of the selected gasifier(s). 
     In one embodiment, one or more sorbents can also be introduced to gasification system  17 . The sorbents can capture one or more contaminants from the syngas, such as sodium vapor in the gas phase within a gasifier. 
     In one embodiment, gas mixture  19  discharged from gasification system  17  can be routed to WGS zone  20 . In one embodiment, at least a portion of gas mixture  19  can be further processed before it is introduced to reaction zone  20 . Further processing can be part of gasification system  17 . For example, in certain embodiments, gasification system  17  can further comprise one or more particulate removal systems (not shown) and/or one or more cooling zones (not shown). In other embodiments, gasification system  17  can also include one or more hydrogen separators (not shown). 
     One or more particulate removal systems can be used to partially or completely remove any particulates from the syngas to provide the particulates or particulate-containing fluid and a separated syngas. The particulate removal system can include a separation device for example conventional disengagers and/or cyclones. Particulate control devices (“PCD”) capable of providing an outlet particulate concentration below the detectable limit of about 0.1 parts per million by weight (ppmw) can also be used. Examples of suitable PCDs can include, but are not limited to, sintered metal filters, metal filter candles, and ceramic filter candles (for example, iron alum inide filter material). The particulates, for example, fine ash, coarse ash, and combinations thereof, can be recycled to the gasifier, purged from the system, utilized as the particulates, or any combination thereof. 
     If desired or necessary, the separated syngas can be cooled in one or more syngas coolers in one or more cooling zones. For example, the syngas can be cooled to about 540 degrees C. or less, such as about 300 degrees C., using a suitable heat exchange system known to those skilled in the art. If a cooling zone is used, an exemplary non-limiting embodiment of a cooling zone is depicted in  FIG. 10 , with numeral reference  1000 . Cooling system  1000  comprises gasification product inlet  1002 , cooling chamber  1004 , cooled gasification product outlet  1006 , cooling fluid inlet  1008 , and heated fluid outlet  1010 . Cooling chamber  1004  comprises one or more conduits  1012  that wraps around cooling passage  1014 . In a preferred embodiment, cooling chamber  1004  comprises two conduits  1012 . The inlet of one or more conduits  1012  is disposed at or near gasification product inlet  1006  and is arranged such that an outlet of a gasifier is coupled to inlet  1006  so gasification product  1020  exiting a gasifier and enters one or more conduits  1012 . Cooling fluid inlet  1008  is coupled to cooling passage  1014  such that cooling fluid  1016  entering inlet  1008  flows through passage  1014  and exits cooling system  1000  as heated fluid  1018  through outlet  1010 . It is understood that the location and/or position of various inlets and outlets with respect to a top or bottom portion of cooling system  1000  can be modified as appropriate. 
     During operation of the embodiment shown in  FIG. 10 , gasification product  1020  enters cooling system  1000  through inlet  1002  and flows through one or more conduits  1012  upward and exits cooling system  1000  through outlet  1006  at a temperature that is lower than the temperature when it entered cooling system  1000 . Cooling fluid  1016  enters cooling system  1000  through inlet  1008  and flows through passage  1014  and exits cooling system  1000  as heated fluid  1018  through outlet  1010 . Heated fluid  1018  has a higher temperature than cooling fluid  1016 . The flow of gasification product  1020  around the flow of cooling fluid  1016  through passage  1014  allows for heat exchange between gasification product  1020  and cooling fluid  1016 , thereby cooling gasification product  1020  while heating up cooling fluid  1016 . 
     In certain embodiments, the separated and/or cooled syngas can be treated within a gas purification system to remove contaminants. The gas purification system can include a system, a process, or a device to remove sulfur and/or sulfur-containing compounds from the syngas. Examples of a suitable catalytic gas purification system include, but are not limited to, systems using zinc titanate, zinc ferrite, tin oxide, zinc oxide, iron oxide, copper oxide, cerium oxide, or mixtures thereof. Examples of a suitable process-based gas purification system include, but are not limited to, the SELEXOL® process, the RECTISOL® process, the CRYSTASULF® process, and the Sulfinol gas treatment process. 
     In one embodiment, one or more amine solvents such as methyl-diethanolamine (MDEA) can be used to remove acid gas from the syngas. Physical solvents, for example SELEXOL® (dimethyl ethers of polyethylene glycol) or RECTISOL® (cold methanol), can also be used. If the syngas contains carbonyl sulfide (COS), the carbonyl sulfide can be converted by hydrolysis to hydrogen sulfide by reaction with water over a catalyst and then absorbed using the methods described above. If the syngas contains mercury, the mercury can be removed using a bed of sulfur-impregnated activated carbon. 
     One or more catalysts, such as a cobalt-molybdenum (“Co—Mo”) catalyst can be incorporated into the gas purification system to perform a sour shift conversion of the syngas. The Co—Mo catalyst can operate at a temperature of about 288° C. in the presence of H 2 S, for example, about 100 parts per million by weight (ppmw) H 2 S. If a Co—Mo catalyst is used to perform a sour shift, subsequent downstream removal of sulfur can be accomplished using any of the above described sulfur removal methods and/or techniques. 
     Gasification system  17  can also discharge ash or slag material (not shown), such as that described above. The slag material is optionally recycled back to gasification system  17  to increase the content of solid ash-forming materials. 
     In WGS zone  20 , carbon monoxide is converted to hydrogen in the presence of steam through the water-gas shift reaction represented by CO+H 2 O→CO 2 +H 2 . In one embodiment, steam generated by gasification system  17  and/or a heat exchanger, if used, can provide at least a portion of the steam for the water-gas shift reaction. The water-gas shift process is well established as a means to increase the hydrogen content and/or reduce the carbon monoxide content of synthesis gases produced by gasification of carbonaceous material. In GS zone  20 , carbon monoxide reacts with steam at high temperature, and optionally in the presence of one or more catalysts, to yield carbon dioxide and hydrogen. A mixture of hydrogen, carbon dioxide, unreacted carbon monoxide and other impurities is discharged from WGS zone  20  as shifted synthesis gas. At least a portion of the hydrogen generated in WGS zone  20  is provided to hydrocatalytic treatment system  12  via hydrogen stream  21  for use in hydrocatalytic reactions. 
     In a preferred embodiment, WGS zone  20  can comprise one or more shift reactors to adjust the hydrogen to carbon monoxide ratio (H 2 :CO) of the syngas by converting CO to CO 2 . Within a shift reactor, a water-gas shift reaction reacts at least a portion of the carbon monoxide in the syngas with water in the presence of a catalyst and a high temperature to produce hydrogen and carbon dioxide. Examples of a suitable shift reactor can include, but are not limited to, single stage adiabatic fixed bed reactors, multiple-stage adiabatic fixed bed reactors with interstage cooling, steam generation or cold quench reactors, tubular fixed bed reactors with steam generation or cooling, fluidized bed reactors, or any combination thereof. A sorption enhanced water-gas shift (SEWGS) process, utilizing a pressure swing adsorption unit having multiple fixed bed reactors packed with shift catalyst and at high temperature, e.g. a carbon dioxide adsorbent at about 480° C., can be used. Various shift catalysts can be employed. 
     In one embodiment, the shift reactor can include two reactors arranged in series. A first reactor can be operated at high temperature (about 340° C. to about 400° C.) to convert a majority of the CO present in the syngas to CO, at a relatively high reaction rate using an iron-chrome catalyst. A second reactor can be operated at a relatively low temperature (about 145° C. to about 205° C.) to complete the conversion of CO to CO 2  using a mixture of copper oxide and zinc oxide. 
     In one embodiment, at least a portion of gas mixture  19  can be directed to a hydrogen separator (not shown) before it is routed to WGS zone  20 . In another embodiment, which is not shown, at least a portion of gas mixture  19  can bypass WGS zone  20  and can be fed directly to the hydrogen separator. At least a portion of the hydrogen separated by the hydrogen separator can be fed to hydrocatalytic treatment system  12 . 
     The hydrogen separator can include any system or device to selectively separate hydrogen from syngas to provide a purified hydrogen stream and a waste gas stream. The hydrogen separator can provide a carbon dioxide rich fluid and a hydrogen rich fluid. The hydrogen separator can utilize pressure swing absorption, cryogenic distillation, and/or semi-permeable membranes. Examples of suitable absorbents include, but are not limited to, caustic soda, potassium carbonate or other inorganic bases, and/or alanolamines. 
     In one embodiment, the hydrogen generated in WGS zone  20  and/or separately by a hydrogen separator can be routed to processing zone  22  for use in hydrocatalytic reactions including further catalytic reduction reactions (e.g., hydrogenation reactions, hydrogenolysis reactions, hydrotreating reactions, and the like), further condensation reactions, isomerization reactions, oligomerization reactions, and any combination thereof. 
     Accordingly, the hydrogen used in a hydrocatalytic reaction of system  12  can include external hydrogen, recycled hydrogen, in situ generated hydrogen, and any combination thereof. The term “in situ generated hydrogen” as used herein refers to hydrogen that is produced within the overall process; it is not limited to a particular reactor for production or use and is therefore synonymous with an in process generated hydrogen. As explained, at least one source of the hydrogen used in hydrocatalytic treatment system  12  comes from gasification of biomass material  16 . 
     Descriptions of exemplary suitable hydrocatalytic reactions that can take place in hydrocatalytic treatment system  12  are known to those skilled in the art and/or provided by U.S. Application Publication Nos. US2011/0154721, US2012/0152836, US2012/0156743, and US2013/0109896, and U.S. Application Nos. 61/665,641, filed on Jun. 28, 2012, and 61/720,757, filed on Oct. 31, 2012, and 61/817,996, where each disclosure is incorporated herein by reference. Likewise, descriptions of exemplary suitable further processing reactions that can take place in processing zone  22  are known to those skilled in the art and/or provided by the materials that have been incorporated by reference in their entirety. Accordingly, the details of hydrocatalytic reactions and further processing reactions need not be repeated. 
     Nevertheless, the descriptions below highlight some aspects of certain hydrocatalytic reactions, such as hydrothermal digestion and catalytic reduction reactions, and further processing reactions. It is understood that hydrocatalytic treatment system  12  can comprise any number, combination, and type of reactors to perform one or more hydrocatalytic reactions. 
     In certain embodiments where hydrocatalytic treatment system  12  comprises hydrothermal digestion and one or more catalytic reduction reactions, the hydrothermal digestion and one or more catalytic reduction reactions take place in the same vessel, which can provide an effective stabilization of soluble carbohydrates. The foregoing may be accomplished by including a slurry catalyst capable of activating molecular hydrogen within a hydrothermal digestion unit containing cellulosic biomass solids. That is, the catalyst that is capable of activating molecular hydrogen may comprise a slurry catalyst. As used herein, the term “slurry catalyst” refers to a catalyst comprising fluidly mobile catalyst particles that can be at least partially suspended in a fluid phase via gas flow, liquid flow, mechanical agitation, or any combination thereof. Formation of the reaction product may reduce the amount of thermal decomposition that occurs during hydrothermal digestion, thereby enabling high yield conversion of cellulosic biomass solids into a desired reaction product to take place in a timely manner. 
     Once the soluble carbohydrates have been at least partially transformed into a more stable reaction product during hydrothermal digestion, completion of the conversion of the soluble carbohydrates into the reaction product may take place in a separate catalytic reduction reactor unit that also employs the slurry catalyst or a different catalyst that is capable of activating molecular hydrogen. The transformation that takes place in the catalytic reduction reactor unit may comprise a further reduction in the degree of oxidation of the initial reaction product, an increased conversion of soluble carbohydrates into oxygenated intermediates, or both. As used herein, the term “oxygenated intermediates” refers to alcohols, polyols, ketones, aldehydes, and mixtures thereof that are produced from a catalytic reduction reaction of soluble carbohydrates. 
     Continuous, high temperature hydrothermal digestion may be accomplished by configuring the biomass conversion systems such that fresh biomass may be continuously or semi-continuously supplied to the hydrothermal digestion unit, while it operates in a pressurized state. As used herein, the term “continuous addition” and grammatical equivalents thereof will refer to a process in which cellulosic biomass is added to a hydrothermal digestion unit in an uninterrupted manner without fully depressurizing the hydrothermal digestion unit. As used herein, the term “semi-continuous addition” and grammatical equivalents thereof will refer to a discontinuous, but as-needed, addition of biomass to a hydrothermal digestion unit without fully depressurizing the hydrothermal digestion unit. 
     In some embodiments described herein, a slurry catalyst may be used both in the hydrothermal digestion unit and in the catalytic reduction reactor unit to mediate the catalytic reduction reaction of soluble carbohydrates into a reaction product. Retention of the slurry catalyst in the hydrothermal digestion unit may also be aided by the low recycle ratios that may be used in the biomass conversion systems described herein. In any event, circulation of the slurry catalyst through the cellulosic biomass charge within the hydrothermal digestion unit can provide good catalyst distribution within the biomass, thereby allowing soluble carbohydrates to be effectively stabilized via a catalytic reduction reaction as soon as possible following their formation. 
     Since a slurry catalyst can be fluidly mobile, hydrogen sparge, solvent recycle, or any combination thereof may be used to distribute the slurry catalyst throughout the cellulosic biomass charge in the hydrothermal digestion unit. Good catalyst distribution in the cellulosic biomass may improve yields by intercepting soluble carbohydrates before they have an opportunity to degrade. Furthermore, use of a slurry catalyst may allow a fixed bed digestion unit to be more successfully used, since mechanical stirring or like mechanical agitation is not needed to affect catalyst distribution. This can allow higher biomass to solvent ratios to be utilized per unit volume of the digestion unit than would be possible in stirred tank or like digestion unit configurations. Furthermore, since stiffing is not necessary, there is no express need to alter the size of the biomass solids prior to digestion taking place. 
     In one embodiment, poison-tolerant slurry catalyst is used. Use of a poison-tolerant catalyst may be particularly desirable, since catalyst poisons are not removed from the cellulosic biomass solids before hydrothermal digestion and integrated catalytic reduction take place. As used herein, a “poison-tolerant catalyst” is defined as a catalyst that is capable of activating molecular hydrogen without needing to be regenerated or replaced due to low catalytic activity for at least about 12 hours of continuous operation. 
     In some embodiments, suitable poison-tolerant catalysts may include, for example, sulfided catalysts. In some or other embodiments, nitrided catalysts may be used as poison-tolerant catalysts. Sulfided catalysts suitable for activating molecular hydrogen are described in commonly owned U.S. application Ser. No. 13/495,785, filed on Jun. 13, 2012, and 61/553,591, filed on Oct. 31, 2011, each of which is incorporated herein by reference in its entirety. Sulfiding may take place by treating the catalyst with hydrogen sulfide or an alternative sulfiding agent, optionally while the catalyst is disposed on a solid support. In more particular embodiments, the poison-tolerant catalyst may comprise a sulfided cobalt-molybdate catalyst, such as a catalyst comprising about 1-10 wt. % cobalt oxide and up to about 30 wt. % molybdenum trioxide prior to sulfidation. In other embodiments, catalysts containing Pt or Pd may also be effective poison-tolerant catalysts for use in the techniques described herein. When mediating in situ catalytic reduction reaction processes, sulfided catalysts may be particularly well suited to form reaction products comprising a substantial fraction of glycols (e.g., C 2 -C 6  glycols) without producing excessive amounts of the corresponding monohydric alcohols. Although poison-tolerant catalysts, particularly sulfided catalysts, may be well suited for forming glycols from soluble carbohydrates, it is to be recognized that other types of catalysts, which may not necessarily be poison-tolerant, may also be used to achieve a like result in alternative embodiments. As will be recognized by one having ordinary skill in the art, various reaction parameters (e.g., temperature, pressure, catalyst composition, introduction of other components, and the like) may be modified to favor the formation of a desired reaction product. Given the benefit of the present disclosure, one having ordinary skill in the art will be able to alter various reaction parameters to change the product distribution obtained from a particular catalyst and set of reactants. 
     Catalysts that are not particularly poison-tolerant may also be used in conjunction with the techniques described herein. Such catalysts may include, for example, Ru, Pt, Pd, or compounds thereof disposed on a solid support such as, for example, Ru on titanium dioxide or Ru on carbon. Although such catalysts may not have particular poison tolerance, they may be regenerable, such as through exposure of the catalyst to water at elevated temperatures, which may be in either a subcritical state or a supercritical state. 
     In some embodiments, slurry catalysts suitable for use in the methods described herein may be sulfided by dispersing a slurry catalyst in a fluid phase and adding a sulfiding agent thereto. Suitable sulfiding agents may include, for example, organic sulfoxides (e.g., dimethyl sulfoxide), hydrogen sulfide, salts of hydrogen sulfide (e.g., NaSH), and the like. In some embodiments, the slurry catalyst may be concentrated in the fluid phase after sulfiding and then added to the hydrothermal digestion unit. 
     In some embodiments, the slurry catalyst may be operable to generate molecular hydrogen. For example, in some embodiments, catalysts suitable for aqueous phase reforming (i.e., APR catalysts) may be used. Suitable APR catalysts may include, for example, catalysts comprising platinum, palladium, ruthenium, nickel, cobalt, or other Group VIII metals alloyed or modified with rhenium, molybdenum, tin, or other metals, or sulfided. However, in other embodiments, an external hydrogen feed may be used, optionally in combination with internally generated hydrogen. 
     In various embodiments, slurry catalysts used in embodiments described herein may have a particulate size of about 250 microns or less. In some embodiments, the slurry catalyst may have a particulate size of about 100 microns or less, or about 10 microns or less. In some embodiments, the minimum particulate size of the slurry catalyst may be about 1 micron. 
     In general, digestion in the hydrothermal digestion unit may be conducted in a liquor phase. In some embodiments, the liquor phase may comprise a digestion solvent that comprises water. In some embodiments, the liquor phase may further comprise an organic solvent. Although any organic solvent that is at least partially miscible with water may be used as a digestion solvent, particularly advantageous organic solvents are those that can be directly converted into fuel blends and other materials without being separated from hydrocatalytically treated mixture  13 . That is, particularly advantageous organic solvents are those that may be co-processed along with hydrocatalytically treated mixture  13  into fuel blends and other materials during further processing reactions. Suitable organic solvents in this regard may include, for example, ethanol, ethylene glycol, propylene glycol, glycerol, and any combination thereof. In some embodiments, the organic solvent may comprise oxygenated intermediates produced from a catalytic reduction reaction of soluble carbohydrates. For example, in some embodiments, a digestion solvent may comprise oxygenated intermediates produced by a hydrogenolysis reaction or other catalytic reduction reaction of soluble carbohydrates. In some embodiments, the oxygenated intermediates may include those produced from an in situ catalytic reduction reaction and/or from the catalytic reduction reactor unit. 
     In some embodiments employing hydrothermal digestion, the digestion solvent may further comprise a small amount of a monohydric alcohol. The presence of at least some monohydric alcohols in the fluid phase digestion medium may desirably enhance the hydrothermal digestion and/or the catalytic reduction reactions being conducted therein. For example, inclusion of about 1% to about 5% by weight monohydric alcohols in the fluid phase digestion medium may desirably maintain catalyst activity due to a surface cleaning effect. Monohydric alcohols present in the digestion solvent may arise from any source. In some embodiments, the monohydric alcohols may be formed via the in situ catalytic reduction reaction process being conducted therein. In some or other embodiments, the monohydric alcohols may be formed during further chemical transformations of the initially formed hydrocatalytically treated mixture  13 . In still other embodiments, the monohydric alcohols may be sourced from an external feed that is in flow communication with the cellulosic biomass solids. 
     In some embodiments, the digestion solvent may comprise between about 1% water and about 99% water. Although higher percentages of water may be more favorable from an environmental standpoint, higher quantities of organic solvent may more effectively promote hydrothermal digestion due to the organic solvent&#39;s greater propensity to solubilize carbohydrates and promote catalytic reduction of the soluble carbohydrates. In some embodiments, the digestion solvent may comprise about 90% or less water by weight. In other embodiments, the digestion solvent may comprise about 80% or less water by weight, or about 70% or less water by weight, or about 60% or less water by weight, or about 50% or less water by weight, or about 40% or less water by weight, or about 30% or less water by weight, or about 20% or less water by weight, or about 10% or less water by weight, or about 5% or less water by weight. 
     In some embodiments, the digestion solvent may comprise an organic solvent comprising oxygenated intermediates resulting from a catalytic reduction reaction of soluble carbohydrates. The catalytic reduction reaction may take place in the hydrothermal digestion unit and/or in the catalytic reduction reactor unit. In some embodiments, the organic solvent may comprise at least one alcohol, ketone, or polyol. In alternative embodiments, the digestion solvent may be at least partially supplied from an external source. For example, in some embodiments, bio-ethanol may be used to supplement the organic solvent. Other water-miscible organic solvents may be used as well. In some embodiments, the digestion solvent may be separated, stored, or selectively injected into the hydrothermal digestion unit so as to maintain a desired concentration of soluble carbohydrates or to provide temperature regulation in the hydrothermal digestion unit. 
     In various embodiments, digestion may take place over a period of time at elevated temperatures and pressures. In some embodiments, digestion may take place at a temperature ranging between about 100 to about 240 degrees C. for a period of time. In some embodiments, the period of time may range of about 0.25 to 24 hours. In some embodiments, the digestion to produce soluble carbohydrates may occur at a pressure ranging between about 1 bar (absolute) and about 100 bar. In general, the higher the temperature, the shorter the amount of time needed for hydrothermal digestion steps to take place. As an example, hydrothermal digestion may take place for about 1 hour to about 10 hours at a temperature of about 180 to about 270 degrees C., most typically from about 190 to 250 degrees C. 
     In various embodiments, suitable biomass digestion techniques may include, for example, acid digestion, alkaline digestion, enzymatic digestion, and digestion using hot-compressed water. In some embodiments, the methods may further comprise withdrawing at least a portion of the reaction product from the biomass conversion system (e.g., from the outlet of the catalytic reduction reactor unit or from the fluid circulation loop). In some embodiments, the methods may further comprise converting the reaction product into a biofuel, as described in further detail hereinafter. In some embodiments, the methods may further comprise separating solids (e.g., slurry catalyst, biomass fines, and the like) from the reaction product after its withdrawal from the biomass conversion system, as described above. 
     In some embodiments, the methods may further comprise recirculating at least a portion of the liquor phase from the catalytic reduction reactor unit to the hydrothermal digestion unit. As set forth above, the biomass conversion systems described herein are particularly advantageous in being capable of rapidly at least partially transforming soluble carbohydrates into a reaction product comprising oxygenated intermediates by performing an in situ catalytic reduction reaction in the hydrothermal digestion unit. As also noted above, the liquor phase containing the reaction product may be recirculated from the catalytic reduction reactor unit to the hydrothermal digestion unit, where the liquor phase may, for example, help regulate temperature therein, serve as a digestion solvent, and the like. Recirculation from the catalytic reduction reactor unit to the hydrothermal digestion unit may take place at various recycle ratios. As used herein, the term “recycle ratio” refers to the amount of liquor phase that is recirculated to the hydrothermal digestion unit (e.g., within the fluid circulation loop) relative to the amount of liquor phase that is withdrawn from the biomass conversion system (e.g., by a reaction product takeoff line). 
     In some embodiments, the catalytic reduction reactions carried out in the hydrothermal digestion unit and the catalytic reduction reactor unit may be hydrogenolysis reactions. In some embodiments, the catalytic reduction reaction used to produce an alcoholic component in hydrocatalytically treated mixture  13  may take place at a temperature ranging between about 110° C. and about 300° C., or between about 170° C. and about 300° C., or between about 180° C. and about 290° C., or between about 150° C. and about 250° C. In some embodiments, the catalytic reduction reaction may take place at a pH ranging between about 7 and about 13, or between about 10 and about 12. In other embodiments, the catalytic reduction reaction may take place under acidic conditions, such as at a pH of about 5 to about 7. Acids, bases, and buffers may be introduced as necessary to achieve a desired pH level. In some embodiments, the catalytic reduction reaction may be conducted under a hydrogen partial pressure ranging between about 1 bar (absolute) and about 150 bar, or between about 15 bar and about 140 bar, or between about 30 bar and about 130 bar, or between about 50 bar and about 110 bar. 
     In some embodiments, catalysts capable of activating molecular hydrogen and conducting a catalytic reduction reaction may comprise a metal such as, for example, Cr, Mo, W, Re, Mn, Cu, Cd, Fe, Co, Ni, Pt, Pd, Rh, Ru, Ir, Os, and alloys or any combination thereof, either alone or with promoters such as Au, Ag, Cr, Zn, Mn, Sn, Bi, B, O, and alloys or any combination thereof. In some embodiments, the catalysts and promoters may allow for hydrogenation and hydrogenolysis reactions to occur at the same time or in succession of one another. In some embodiments, such catalysts may also comprise a carbonaceous pyropolymer catalyst containing transition metals (e.g., Cr, Mo, W, Re, Mn, Cu, and Cd) or Group VIII metals (e.g., Fe, Co, Ni, Pt, Pd, Rh, Ru, Ir, and Os). In some embodiments, the foregoing catalysts may be combined with an alkaline earth metal oxide or adhered to a catalytically active support. In some or other embodiments, the catalyst capable of activating molecular hydrogen may be deposited on a catalyst support that is not itself catalytically active. 
     In some embodiments, slurry catalysts suitable for use in the methods described herein may be sulfided by dispersing a slurry catalyst in a fluid phase and adding a sulfiding agent thereto. Suitable sulfiding agents may include, for example, organic sulfoxides (e.g., dimethyl sulfoxide), hydrogen sulfide, salts of hydrogen sulfide (e.g., NaSH), amino acids derived from proteins present in biomass feedstock  11  and the like. In some embodiments, the slurry catalyst may be concentrated in the fluid phase after sulfiding, and the concentrated slurry may then be distributed in the cellulosic biomass solids using fluid flow. Illustrative techniques for catalyst sulfiding that may be used in conjunction with the methods described herein are described in U.S. application Ser. No. 12/407,479 (U.S. Application Publication No. 20100236988), filed on Mar. 19, 2009 and incorporated herein by reference in its entirety. 
     In some embodiments, as mentioned above, hydrocatalytically treated mixture  13 , preferably overhead fraction  15 , may be further processed into a biofuel. Further processing of hydrocatalytically treated mixture  13  into a biofuel or other material may comprise any combination and sequence of further hydrogenolysis reactions and/or hydrogenation reactions, condensation reactions, isomerization reactions, oligomerization reactions, hydrotreating reactions, alkylation reactions, dehydration reactions, desulfurization reactions, and the like. The subsequent further processing reactions may be catalytic or non-catalytic. In some embodiments, an initial operation of downstream further processing may comprise a condensation reaction, often conducted in the presence of a condensation catalyst, in which hydrocatalytically treated mixture  13  or a product derived therefrom is condensed with another molecule to form a higher molecular weight compound. As used herein, the term “condensation reaction” will refer to a chemical transformation in which two or more molecules are coupled with one another to form a carbon-carbon bond in a higher molecular weight compound, usually accompanied by the loss of a small molecule such as water or an alcohol. An illustrative condensation reaction is the Aldol condensation reaction, which will be familiar to one having ordinary skill in the art. Additional disclosure regarding condensation reactions and catalysts suitable for promoting condensation reactions is provided hereinbelow. 
     In some embodiments, methods described herein may further comprise performing a condensation reaction on hydrocatalytically treated mixture  13  or a product derived therefrom. In various embodiments, the condensation reaction may take place at a temperature ranging between about 5° C. and about 500° C. The condensation reaction may take place in a condensed phase (e.g., a liquor phase) or in a vapor phase. For condensation reactions taking place in a vapor phase, the temperature may range between about 75° C. and about 500° C., or between about 125° C. and about 450° C. For condensation reactions taking place in a condensed phase, the temperature may range between about 5° C. and about 475° C., or between about 15° C. and about 300° C., or between about 20° C. and about 250° C. 
     In various embodiments, the higher molecular weight compound produced by the condensation reaction may comprise ≧C 4  hydrocarbons. In some or other embodiments, the higher molecular weight compound produced by the condensation reaction may comprise ≧C 6  hydrocarbons. In some embodiments, the higher molecular weight compound produced by the condensation reaction may comprise C 4 -C 30  hydrocarbons. In some embodiments, the higher molecular weight compound produced by the condensation reaction may comprise C 6 -C 30  hydrocarbons. In still other embodiments, the higher molecular weight compound produced by the condensation reaction may comprise C 4 -C 24  hydrocarbons, or C 6 -C 24  hydrocarbons, or C 4 -C 18  hydrocarbons, or C 6 -C 18  hydrocarbons, or C 4 -C 12  hydrocarbons, or C 6 -C 12  hydrocarbons. As used herein, the term “hydrocarbons” refers to compounds containing both carbon and hydrogen without reference to other elements that may be present. Thus, heteroatom-substituted compounds are also described herein by the term “hydrocarbons.” 
     The particular composition of the higher molecular weight compound produced by the condensation reaction may vary depending on the catalyst(s) and temperatures used for both the catalytic reduction reaction and the condensation reaction, as well as other parameters such as pressure. For example, in some embodiments, the product of the condensation reaction may comprise ≧C 4  alcohols and/or ketones that are produced concurrently with or in lieu of ≧C 4  hydrocarbons. In some embodiments, the ≧C 4  hydrocarbons produced by the condensation reaction may contain various olefins in addition to alkanes of various sizes, typically branched alkanes. In still other embodiments, the ≧C 4  hydrocarbons produced by the condensation reaction may also comprise cyclic hydrocarbons and/or aromatic compounds. In some embodiments, the higher molecular weight compound produced by the condensation reaction may be further subjected to a catalytic reduction reaction to transform a carbonyl functionality therein to an alcohol and/or a hydrocarbon and to convert olefins into alkanes. 
     Exemplary compounds that may be produced by a condensation reaction include, for example, ≧C 4  alkanes, ≧C 4  alkenes, ≧C 5  cycloalkanes, ≧C 5  cycloalkenes, aryls, fused aryls, ≧C 4  alcohols, ≧C 4  ketones, and mixtures thereof. The ≧C 4  alkanes and ≧C 4  alkenes may range from 4 to about 30 carbon atoms (i.e. C 4 -C 30  alkanes and C 4 -C 30  alkenes) and may be branched or straight chain alkanes or alkenes. The ≧C 4  alkanes and ≧C 4  alkenes may also include fractions of C 7 -C 14 , C 12 -C 24  alkanes and alkenes, respectively, with the C 7 -C 14  fraction directed to jet fuel blends, and the C 12 -C 24  fraction directed to diesel fuel blends and other industrial applications. Examples of various ≧C 4  alkanes and ≧C 4  alkenes that may be produced by the condensation reaction include, without limitation, butane, butene, pentane, pentene, 2-methylbutane, hexane, hexene, 2-methylpentane, 3-methylpentane, 2,2-dimethylbutane, 2,3-dimethylbutane, heptane, heptene, octane, octene, 2,2,4,-trimethylpentane, 2,3-dimethylhexane, 2,3,4-trimethylpentane, 2,3-dimethylpentane, nonane, nonene, decane, decene, undecane, undecene, dodecane, dodecene, tridecane, tridecene, tetradecane, tetradecene, pentadecane, pentadecene, hexadecane, hexadecene, heptyldecane, heptyldecene, octyldecane, octyldecene, nonyldecane, nonyldecene, eicosane, eicosene, uneicosane, uneicosene, doeicosane, doeicosene, trieicosane, trieicosene, tetraeicosane, tetraeicosene, and isomers thereof. 
     The ≧C 5  cycloalkanes and ≧C 5  cycloalkenes may have from 5 to about 30 carbon atoms and may be unsubstituted, mono-substituted or multi-substituted. In the case of mono-substituted and multi-substituted compounds, the substituted group may include a branched ≧C 3  alkyl, a straight chain ≧C 1  alkyl, a branched ≧C 3  alkylene, a straight chain ≧C 1  alkylene, a straight chain ≧C 2  alkylene, an aryl group, or a combination thereof. In some embodiments, at least one of the substituted groups may include a branched C 3 -C 12  alkyl, a straight chain C 1 -C 12  alkyl, a branched C 3 -C 12  alkylene, a straight chain C 1 -C 12  alkylene, a straight chain C 2 -C 12  alkylene, an aryl group, or a combination thereof. In yet other embodiments, at least one of the substituted groups may include a branched C 3 -C 4  alkyl, a straight chain C 1 -C 4  alkyl, a branched C 3 -C 4  alkylene, a straight chain C 1 -C 4  alkylene, a straight chain C 2 -C 4  alkylene, an aryl group, or any combination thereof. Examples of ≧C 5  cycloalkanes and ≧C 5  cycloalkenes that may be produced by the condensation reaction include, without limitation, cyclopentane, cyclopentene, cyclohexane, cyclohexene, methylcyclopentane, methylcyclopentene, ethylcyclopentane, ethylcyclopentene, ethylcyclohexane, ethylcyclohexene, and isomers thereof. 
     The moderate fractions of the condensation reaction, such as C 7 -C 14 , may be separated for jet fuel, while heavier fractions, such as C 12 -C 24 , may be separated for diesel use. The heaviest fractions may be used as lubricants or cracked to produce additional gasoline and/or diesel fractions. The ≧C 4  compounds may also find use as industrial chemicals, whether as an intermediate or an end product. For example, the aryl compounds toluene, xylene, ethylbenzene, para-xylene, meta-xylene, and ortho-xylene may find use as chemical intermediates for the production of plastics and other products. Meanwhile, C 9  aromatic compounds and fused aryl compounds, such as naphthalene, anthracene, tetrahydronaphthalene, and decahydronaphthalene, may find use as solvents or additives in industrial processes. 
     In some embodiments, a single catalyst may mediate the transformation of hydrocatalytically treated mixture  13  into a form suitable for undergoing a condensation reaction as well as mediating the condensation reaction itself. In other embodiments, a first catalyst may be used to mediate the transformation of hydrocatalytically treated mixture  13  into a form suitable for undergoing a condensation reaction, and a second catalyst may be used to mediate the condensation reaction. Unless otherwise specified, it is to be understood that reference herein to a condensation reaction and condensation catalyst refers to either type of condensation process. Further disclosure of suitable condensation catalysts now follows. 
     In some embodiments, a single catalyst may be used to form a higher molecular weight compound via a condensation reaction. Without being bound by any theory or mechanism, it is believed that such catalysts may mediate an initial dehydrogenation of hydrocatalytically treated mixture  13 , followed by a condensation reaction of the dehydrogenated alcoholic component. Zeolite catalysts are one type of catalyst suitable for directly converting alcohols to condensation products in such a manner. A particularly suitable zeolite catalyst in this regard may be ZSM-5, although other zeolite catalysts may also be suitable. 
     In some embodiments, two catalysts may be used to form a higher molecular weight compound via a condensation reaction. Without being bound by any theory or mechanism, it is believed that the first catalyst may mediate an initial dehydrogenation of hydrocatalytically treated mixture  13 , and the second catalyst may mediate a condensation reaction of the dehydrogenated hydrocatalytically treated mixture  13 . Like the single-catalyst embodiments discussed previously above, in some embodiments, zeolite catalysts may be used as either the first catalyst or the second catalyst. Again, a particularly suitable zeolite catalyst in this regard may be ZSM-5, although other zeolite catalysts may also be suitable. 
     Various catalytic processes may be used to form higher molecular weight compounds by a condensation reaction. In some embodiments, the catalyst used for mediating a condensation reaction may comprise a basic site, or both an acidic site and a basic site. Catalysts comprising both an acidic site and a basic site will be referred to herein as multi-functional catalysts. In some or other embodiments, a catalyst used for mediating a condensation reaction may comprise one or more metal atoms. Any of the condensation catalysts may also optionally be disposed on a solid support, if desired. 
     In some embodiments, the condensation catalyst may comprise a basic catalyst comprising Li, Na, K, Cs, B, Rb, Mg, Ca, Sr, Si, Ba, Al, Zn, Ce, La, Y, Sc, Y, Zr, Ti, hydrotalcite, zinc-aluminate, phosphate, base-treated aluminosilicate zeolite, a basic resin, basic nitride, alloys or any combination thereof. In some embodiments, the basic catalyst may also comprise an oxide of Ti, Zr, V, Nb, Ta, Mo, Cr, W, Mn, Re, Al, Ga, In, Co, Ni, Si, Cu, Zn, Sn, Cd, Mg, P, Fe, or any combination thereof. In some embodiments, the basic catalyst may comprise a mixed-oxide basic catalyst. Suitable mixed-oxide basic catalysts may comprise, for example, Si—Mg—O, Mg—Ti—O, Y—Mg—O, Y—Zr—O, Ti—Zr—O, Ce—Zr—O, Ce—Mg—O, Ca—Zr—O, La—Zr—O, B—Zr—O, La—Ti—O, B—Ti—O, and any combination thereof. In some embodiments, the condensation catalyst may further include a metal or alloys comprising metals such as, for example, Cu, Ag, Au, Pt, Ni, Fe, Co, Ru, Zn, Cd, Ga, In, Rh, Pd, Ir, Re, Mn, Cr, Mo, W, Sn, Bi, Pb, Os, alloys and combinations thereof. Use of metals in the condensation catalyst may be desirable when a dehydrogenation reaction is to be carried out in concert with the condensation reaction. Basic resins may include resins that exhibit basic functionality. The basic catalyst may be self-supporting or adhered to a support containing a material such as, for example, carbon, silica, alumina, zirconia, titania, vanadia, ceria, nitride, boron nitride, a heteropolyacid, alloys and mixtures thereof. 
     In some embodiments, the condensation catalyst may comprise a hydrotalcite material derived from a combination of MgO and Al 2 O 3 . In some embodiments, the condensation catalyst may comprise a zinc aluminate spinel formed from a combination of ZnO and Al 2 O 3 . In still other embodiments, the condensation catalyst may comprise a combination of ZnO, Al 2 O 3 , and CuO. Each of these materials may also contain an additional metal or alloy, including those more generally referenced above for basic condensation catalysts. In more particular embodiments, the additional metal or alloy may comprise a Group 10 metal such Pd, Pt, or any combination thereof. 
     In some embodiments, the condensation catalyst may comprise a basic catalyst comprising a metal oxide containing, for example, Cu, Ni, Zn, V, Zr, or any mixture thereof. In some or other embodiments, the condensation catalyst may comprise a zinc aluminate containing, for example, Pt, Pd, Cu, Ni, or any mixture thereof. 
     In some embodiments, the condensation catalyst may comprise a multi-functional catalyst having both an acidic functionality and a basic functionality. Such condensation catalysts may comprise a hydrotalcite, a zinc-aluminate, a phosphate, Li, Na, K, Cs, B, Rb, Mg, Si, Ca, Sr, Ba, Al, Ce, La, Sc, Y, Zr, Ti, Zn, Cr, or any combination thereof. In further embodiments, the multi-functional catalyst may also include one or more oxides from the group of Ti, Zr, V, Nb, Ta, Mo, Cr, W, Mn, Re, Al, Ga, In, Fe, Co, Ir, Ni, Si, Cu, Zn, Sn, Cd, P, and any combination thereof. In some embodiments, the multi-functional catalyst may include a metal such as, for example, Cu, Ag, Au, Pt, Ni, Fe, Co, Ru, Zn, Cd, Ga, In, Rh, Pd, Ir, Re, Mn, Cr, Mo, W, Sn, Os, alloys or combinations thereof. The basic catalyst may be self-supporting or adhered to a support containing a material such as, for example, carbon, silica, alumina, zirconia, titania, vanadia, ceria, nitride, boron nitride, a heteropolyacid, alloys and mixtures thereof. 
     In some embodiments, the condensation catalyst may comprise a metal oxide containing Pd, Pt, Cu or Ni. In still other embodiments, the condensation catalyst may comprise an aluminate or a zirconium metal oxide containing Mg and Cu, Pt, Pd or Ni. In still other embodiments, a multi-functional catalyst may comprise a hydroxyapatite (HAP) combined with one or more of the above metals. 
     In some embodiments, the condensation catalyst may also include a zeolite and other microporous supports that contain Group IA compounds, such as Li, Na, K, Cs and Rb. Preferably, the Group IA material may be present in an amount less than that required to neutralize the acidic nature of the support. A metal function may also be provided by the addition of group VIIIB metals, or Cu, Ga, In, Zn or Sn. In some embodiments, the condensation catalyst may be derived from the combination of MgO and Al 2 O 3  to form a hydrotalcite material. Another condensation catalyst may comprise a combination of MgO and ZrO 2 , or a combination of ZnO and Al 2 O 3 . Each of these materials may also contain an additional metal function provided by copper or a Group VIIIB metal, such as Ni, Pd, Pt, or combinations of the foregoing. 
     The condensation reaction mediated by the condensation catalyst may be carried out in any reactor of suitable design, including continuous-flow, batch, semi-batch or multi-system reactors, without limitation as to design, size, geometry, flow rates, and the like. The reactor system may also use a fluidized catalytic bed system, a swing bed system, fixed bed system, a moving bed system, or a combination of the above. In some embodiments, bi-phasic (e.g., liquid-liquid) and tri-phasic (e.g., liquid-liquid-solid) reactors may be used to carry out the condensation reaction. 
     In some embodiments, an acid catalyst may be used to optionally dehydrate at least a portion of the reaction product. Suitable acid catalysts for use in the dehydration reaction may include, but are not limited to, mineral acids (e.g., HCl, H 2 SO 4 ), solid acids (e.g., zeolites, ion-exchange resins) and acid salts (e.g., LaCl 3 ). Additional acid catalysts may include, without limitation, zeolites, carbides, nitrides, zirconia, alumina, silica, aluminosilicates, phosphates, titanium oxides, zinc oxides, vanadium oxides, lanthanum oxides, yttrium oxides, scandium oxides, magnesium oxides, cerium oxides, barium oxides, calcium oxides, hydroxides, heteropolyacids, inorganic acids, acid modified resins, base modified resins, and any combination thereof. In some embodiments, the dehydration catalyst may also include a modifier. Suitable modifiers may include, for example, La, Y, Sc, P, B, Bi, Li, Na, K, Rb, Cs, Mg, Ca, Sr, Ba, and any combination thereof. The modifiers may be useful, inter alia, to carry out a concerted hydrogenation/dehydrogenation reaction with the dehydration reaction. In some embodiments, the dehydration catalyst may also include a metal. Suitable metals may include, for example, Cu, Ag, Au, Pt, Ni, Fe, Co, Ru, Zn, Cd, Ga, In, Rh, Pd, Ir, Re, Mn, Cr, Mo, W, Sn, Os, alloys, and any combination thereof. The dehydration catalyst may be self supporting, supported on an inert support or resin, or it may be dissolved in a fluid. 
     Various operations may optionally be performed on hydrocatalytically treated mixture  13  prior to conducting a condensation reaction. In addition, various operations may optionally be performed on a fluid phase containing hydrocatalytically treated mixture  13 , thereby further transforming hydrocatalytically treated mixture  13  or placing it in a form more suitable for taking part in a condensation reaction. These optional operations are now described in more detail below. 
     As described above, one or more liquid phases may be present when digesting cellulosic biomass solids. Particularly when cellulosic biomass solids are fed continuously or semi-continuously to the hydrothermal digestion unit, digestion of the cellulosic biomass solids may produce multiple liquid phases in the hydrothermal digestion unit. The liquid phases may be immiscible with one another, or they may be at least partially miscible with one another. In some embodiments, the one or more liquid phases contained in hydrocatalytically treated mixture  13  may comprise a phenolics liquid phase comprising lignin or a product formed therefrom, an aqueous phase comprising an alcoholic component, a light organics phase, or any combination thereof. 
     In some embodiments, heating of biomass feedstock  11  and the fluid phase digestion medium to form soluble carbohydrates and a phenolics liquid phase may take place while biomass feedstock  11  is in a pressurized state. As used herein, the term “pressurized state” refers to a pressure that is greater than atmospheric pressure (1 bar). Heating a fluid phase digestion medium in a pressurized state may allow the normal boiling point of the digestion solvent to be exceeded, thereby allowing the rate of hydrothermal digestion to be increased relative to lower temperature digestion processes. In some embodiments, heating biomass feedstock  11  and the fluid phase digestion medium may take place at a pressure of at least about 30 bar. In some embodiments, heating biomass feedstock  11  and the fluid phase digestion medium may take place at a pressure of at least about 60 bar, or at a pressure of at least about 90 bar. In some embodiments, heating biomass feedstock  11  and the fluid phase digestion medium may take place at a pressure ranging between about 30 bar and about 430 bar. In some embodiments, heating biomass feedstock  11  and the fluid phase digestion medium may take place at a pressure ranging between about 50 bar and about 330 bar, or at a pressure ranging between about 70 bar and about 130 bar, or at a pressure ranging between about 30 bar and about 130 bar. 
     To facilitate a better understanding of the present invention, the following examples of preferred embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the invention. 
     EXAMPLES 
     To facilitate a better understanding of the present invention, the following examples of preferred embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the invention. 
     Example 1 
     A 100-ml Parr reactor was charged with 60.18 grams of deionized water solvent, and 0.754 grams of nickel-oxide promoted cobalt molybdate catalyst (DC-2534, containing 1-10% cobalt oxide and molybdenum trioxide (up to 30 wt %) on alumina, and less than 2% nickel), obtained from Criterion Catalyst &amp; Technologies L.P. The catalyst was sulfided by the method described in Example 5 of U.S. Application Publication No. 2010/0236988. The reactor was charged with about 5.05 grams of southern pine mini-chips (39% moisture, having a nominal size of about 3 mm×5 mm×5 mm in dimension), and about 0.195 grams of potassium carbonate buffer, before pressuring with 54 bar of hydrogen under magnetic stirring. The stirred reactor was heated to 190° C. for 1 hour. Subsequently, the reactor was heated to 250° C. for 5 hours, which was the end of a cycle. A sample of about 1-2 grams of mixed product was removed via a 0.5 micron sintered metal dip tube at the end of the cycle, while the reactor was still at reaction temperature and stirred. At the end of a cycle, the reactor was cooled, depressurized, and opened for additional wood to be added. Wood addition for cycles  2  through  5  entailed addition of 4.91, 5.09, 5.84, and 5.59 grams of wood. For cycle 6, 2.5 grams of glycerol were added to assess kinetics. For cycle 7, 5.9 grams of nominal 39% moisture ground pine chips were added. For cycle 8, 6.5 grams of pine chips were added. Following the addition of material (wood or glycerol) at the beginning of each cycle, the reactor was repressurized with hydrogen, and again reheated to initiate another cycle. After eight cycles of adding wood or glycerol, the 0.5 micron sintered metal dip tube plugged, and it was not possible to sample the mixed reaction phases. The mixture from the reactant was cooled down and a bottom fraction was separated by liquid-liquid separation. The bottom fraction exhibited a viscosity of greater than about 10,000 cP, measured via timing and flow on an inclined plane while reheating to about 110 degrees C. 
     The bottom fraction was analyzed by gas chromatography (“DB5-ox method”) via dissolving the sample in excess acetone solvent using a 60-m×0.32 mm ID DB-5 column of 1 μm thickness, with 50:1 split ratio, 2 ml/min helium flow, and column oven at 40° C. for 8 minutes, followed by ramp to 285° C. at 10° C./min, and a hold time of 53.5 minutes. The injector temperature was set at 250° C., and the detector temperature was set at 300° C. Analysis revealed the presence of components with a boiling point greater than that of n-butanol, and the bottom fraction included methoxypropyl phenol and tetrahydrofurfural alcohol. The total weight percent of species detected in the bottom fraction was less than 100%, indicating the presence of higher molecular weight oligomers which could not elute from the heated GC injector. 
     Example 1 shows hydrocatalytic reaction of a biomass feedstock using hydrogen that can be supplied by gasification of a biomass material according to embodiments of the invention. 
     Example 2 
     Example 1 was repeated with 60.06 grams of 25% ethanol in water as solvent, and 0.749 grams of sulfided cobalt molybdate catalyst. The reactor was pressurized to 52 bar with hydrogen, and heated to 190° C. for 1 hour, then to 250° C. for 3 hours, and subsequently to 270° C. for 2 hours. After 8 cycles of adding 6 grams of wood for each cycle as described above in Example 1, formation of a viscous phase on reactor internals was observed. The viscous phase exhibited a viscosity greater than 1000 cP at room temperature. This phase was separated using liquid-liquid separation to generate a bottom fraction. Analysis of this heavy bottoms fraction again revealed the presence of compounds with a boiling point that is higher than that of n-butanol, including tetrahydrofurfural alcohol and methoxypropyl phenol and propyl phenol. The total weight percent of species detected in the bottom fraction was less than 100%, indicating the presence of higher molecular weight oligomers which could not elute from the heated GC injector. Example 2 also shows hydrocatalytic reaction of a biomass feedstock using hydrogen that can be supplied by gasification of a biomass material according to embodiments of the invention. 
     Example 3 
     Example 1 was repeated with 50% ethanol in water as solvent. A heavy viscous phase coating internals and the bottom of the reactor was observed after 10 cycles of adding wood chips as described above in Example 1, with viscosity greater than 10,000 cP. Wood additions comprised 6.05, 6.06, 6.06, 6.06, 6.01, 6.00, 6.01, 6.02, 6.06, and 6.06 for completion of ten cycles. After the 10 cycles, the reactor was subjected to 5 hours of treatment under 52 bar of H 2  at 290° C., upon which the viscosity of the lower layer was reduced to less than about 500 cP. The high temperature hydrogen treatment led to increased formation of methoxy and alkyl phenols, such that the observed weight percent of compounds in the GC was more than 3-fold higher than for the similar phase formed in Example 2. The treated phase can be distilled to remove the components of lower volatility that can elute from a GC injector. Example 3 also shows hydrocatalytic reaction of a biomass feedstock using hydrogen that can be supplied by gasification of a biomass material according to embodiments of the invention. 
     Example 4 
     A 100-ml Parr reactor was charged with a solvent mixture comprising 29.3 grams of 1,2-propylene glycol, 3.3 grams of ethylene glycol, and 32.5 grams of deionized water. 0.75 grams of nickel-oxide promoted cobalt molybdate catalyst were added (DC-2534, containing 1-10% cobalt oxide and molybdenum trioxide (up to 30 wt %) on alumina, and less than 2% nickel), obtained from Criterion Catalyst &amp; Technologies L.P., and sulfided by the method described in US2010/0236988 Example 5. 
     The reactor was charged with 6.1 grams of southern pine mini-chips (39% moisture), of nominal size 3×5×5 mm in dimension, before pressuring with 53 bar of hydrogen. The stirred reactor was heated to 190° C. for 1 hour, and subsequently heated to 250° C. for 5 hours to complete a cycle as described above in Example 1. 
     At the end of each cycle, 5.4 grams of product were withdrawn via a pipette. 6.0 grams of wood were charged to initiate a second reaction cycle using the protocol described in Example 1, along with 0.05 to 0.15 grams of buffer as needed to maintain pH between 5 and 6. Reactor product after each cycle was analyzed by gas chromatography using a 60-m×0.32 mm ID DB-5 column of 1 μm thickness, with 50:1 split ratio, 2 ml/min helium flow, and column oven at 40° C. for 8 minutes, followed by ramp to 285° C. at 10° C./min, and a hold time of 53.5 minutes. The injector temperature was set at 250° C., and the detector temperature was set at 300° C. The reaction sequence was continued through 45 cycles. At the end of cycle 45, 19.1262 grams of aqueous phase were decanted from the viscous heavy components phase. 
     A distillation of the aqueous layer was conducted at ambient pressure under N2 blanket, using a 50-ml micro flask with short-path distillation head. The distillation was continued until 58% of the initial still contents were collected as overhead distillate. A first distillation cut was taken as bottoms temperature increased from 120 to 168 degrees C. A second distillation cut was taken at bottoms temperatures between 169 and 186 degrees C. The atmospheric distillation was terminated at 196.9 degrees C. bottoms temperature, and gave a fraction comprising diols and acids. 
     The distillation of this fraction was resumed under vacuum at a nominal pressure of 10 Torr. A maximum temperature of 279 degrees C. was obtained, and 32% of the heavy ends from vacuum distillation were recovered as overhead distillate. The resulting bottom fraction from vacuum distillation was dissolved in dichloromethane and analyzed by GC MS. Many components were too heavy to analyze. Overall structures resembled asphaltenes, with some phenolic groups present. 
     The distillation bottoms flask was unwrapped and tipped sideways to demonstrate flow of heavy residue at a bottoms temperature of about 268 degrees C., at an estimated viscosity in excess of 1000 cP. About 82% of the final residue could be poured out of the hot flask. Upon cooling, the residue would not flow and required removal by spatula for sampling. 
     This example shows thermal distillation of intermediate production from digestion-reaction of wood biomass using a catalyst capable of activating molecular hydrogen, under a hydrogen atmosphere. Mono- and di-oxygenates which can be coupled via condensation-oligomeration reactions could be separated by distillation at atmospheric pressure and under vacuum, leaving a heavy tar-like residue. The heavy residue could be kept molten to flow out of distillation kettle when heated above 250 degrees C. Example 4 shows hydrocatalytic reaction of a biomass feedstock using hydrogen that can be supplied by gasification of a biomass material according to embodiments of the invention. 
     Example 5 
     Example 4 was repeated using 4-methyl-2-pentanol (methyl isobutyl carbinol or “MIBC”) as the digestion medium, and with use of larger scale batches were run conducted in a 450 mL Parr reactor. The reactor was initially charged with 220.06 g of MIBC, 25.08 g deionized water, 0.855 g of potassium carbonate buffer, and 8.1065 g of sulfided cobalt-molybdate catalyst as described in Example 1. For each reaction cycle, 27 g of softwood pine mini-chips were added, and an equivalent amount of liquid sample was removed at the end of each cycle. For liquid sample removal after each cycle, a portion of the lower aqueous layer was removed from as liquid above the settled catalyst layer, if present, followed by removal of a sufficient amount of the upper layer if required to maintain the liquid inventory in the reactor at a 60% level. After 17 cycles, a sample of the upper layer was distilled at atmospheric pressure under nitrogen, followed by vacuum distillation at 10 Torr. Distillate cut number 2 was collected under nitrogen at atmospheric pressure with a kettle bottoms temperature of about 110 to 140 degrees C. and an overheads temperature of about 90 degrees C. Cut number 2 contains a mixture of oxygenated and alkane intermediates. With a kettle temperature of about 258 to 302 degrees C., a vacuum distillation cut containing an estimated 30% of the reactor product was obtained as distillate cut number 6. In addition to alcohols (including glycols and other diols), significant quantities of phenolic compounds were obtained in cut number 6. For example, methoxy propyl phenol was found to be present in quantities greater than 4%. Tetrahydrofurfural alcohol was also found as a significant reaction product. No observable viscous layer or tar was formed under the experimental conditions of Example 5. A final vacuum distillation cut representing the end point of distillation (final 1% of feed) is produced and reported in Table 1 below. 
     
       
         
           
               
             
               
                 TABLE 1 
               
             
            
               
                   
               
               
                 Final vacuum distillation cut at 348 degrees C. bottom temperature 
               
            
           
           
               
               
               
            
               
                   
                 Name 
                 area % 
               
               
                   
               
               
                   
                 acetone (diluent) 
                 N/A 
               
               
                   
                 1-butanol (internal standard) 
                 N/A 
               
               
                   
                 4-methyl-2-Pentanol 
                 N/A 
               
               
                   
                 tetrahydro Furanmethanol 
                  3.27% 
               
               
                   
                 phenol 
                  6.93% 
               
               
                   
                 methoxy phenol 
                  8.61% 
               
               
                   
                 methyl phenol 
                 12.39% 
               
               
                   
                 unknown 
                  3.89% 
               
               
                   
                 dimethy phenol 
                  7.37% 
               
               
                   
                 methyl methoxy phenol 
                  6.27% 
               
               
                   
                 ethyl phenol 
                  6.15% 
               
               
                   
                 methyl ethyl phenol 
                  5.51% 
               
               
                   
                 unknown 
                  2.58% 
               
               
                   
                 ethyl methoxy phenol 
                  5.24% 
               
               
                   
                 unknown 
                  3.76% 
               
               
                   
                 propyl phenol 
                  6.09% 
               
               
                   
                 unknown 
                  0.91% 
               
               
                   
                 benzene diol 
                  5.24% 
               
               
                   
                 propyl methoxy phenol 
                  6.30% 
               
               
                   
                 unknown 
                  1.15% 
               
               
                   
                 unknown 
                  2.50% 
               
               
                   
                 unknown 
                  5.84% 
               
               
                   
               
            
           
         
       
     
     The distillation flask bottoms after distillation with a final temperature of about 345 degrees C. continued to boil and bubble, but formed a solid char with resemblance to coal, upon cooling to room temperature. This example shows digestion and reaction intermediates. Distillation allows removal of monooxygenates and diols, with some phenols. Some heavy tar components with boiling points in excess of 350 degrees C. remain in the bottoms, and for a char phase upon cooling. Example 5 shows hydrocatalytic reaction of a biomass feedstock using hydrogen that can be supplied by gasification of a biomass material according to embodiments of the invention. 
     Example 6 
     Example 5 was repeated with 34 cycles of wood addition. Distillation was conducted at atmospheric pressure under N 2  to remove 85% of the reactor contents as overhead product, analyzed as a mixture of monooxygenates and some diols. The remaining 15% kettle bottoms formed a non-flowable viscous tar at room temperature, for which dissolution in acetone solvent required reheating. Example shows hydrocatalytic reaction of a biomass feedstock using hydrogen that can be supplied by gasification of a biomass material according to embodiments of the invention. 
     Further modifications and alternative embodiments of various aspects of the invention will be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims.