Co-treatment of biomass during fluidized coking and gasification

Abstract

Systems and methods are provided for integrated coking and gasification of biomass feeds in a three vessel fluidized coking system under co-processing conditions such that biomass is co-fed with conventional and / or mineral coker feeds, such as feeds containing resid or heavy crude oil. It has been found that co-processing of a biomass feed can unexpectedly increase the coking reaction rate of the conventional / mineral coker feed. This unexpected increase in reaction rate may allow for an improvement in the manner of operation of the three-vessel fluidized coking reaction system. The resulting improvements in operating conditions may allow for the production of improved and / or improved product compositions from a fluidized coker. The improvements in the product composition may include an increase in total liquid product and a reduction in micro-carbon residues and / or n-heptane insolubles in the total liquid product.

Description

Technical Field

[0001] Systems and methods are provided for coprocessing biomass in a reaction system for fluid coking and gasification, wherein the reaction system includes at least one intermediate reactor vessel for heat transfer between a fluid coker and a gasifier. Background Art

[0002] One area of ​​interest for reducing net greenhouse gas emissions from energy generation, or more generally for the generation of carbon-based products, is the use of biomass and / or fractions derived from biomass as a source of at least a portion of the carbon in fuel or other carbon-based products. Because biomass removes CO2 from the environment as it grows, the net CO2 produced by the combustion of fuels derived from biomass is offset by the CO2 consumed during the growth of the biomass.

[0003] Due to the difficulty in processing solid biomass in many types of refinery equipment, a common technique for processing biomass is to use an initial pyrolysis stage to convert the biomass. Rather than creating a dedicated pyrolysis reactor to process biomass, it is desirable to use existing refinery facilities to process biomass. A fluid coker is an example of an existing refinery process that can potentially co-process biomass.

[0004] Some types of fluidized coker reaction systems correspond to systems using three reaction vessels. The three reaction vessels correspond to the coker reactor, the interheater, and the gasifier. In this type of three reaction vessel configuration, instead of forming CO2 during the gasification process, the overhead gas can alternatively correspond to a gas stream including a synthesis gas component. It is desirable to develop an improved method for co-processing biomass in such a three-vessel fluidized reactor system.

[0005] U.S. Patent Application Publication 2018 / 0118644 describes performing both partial oxidation and pyrolysis of biomass within the same reactor environment such that heat for the pyrolysis reaction can be generated in situ by partial oxidation.

[0006] US Patent Application Publication 2005 / 0095183 describes a multi-stage gasification system for converting biomass or municipal solid waste into a synthesis gas product while reducing the amount of carbon char and / or tar in the product.

[0007] U.S. Patent Application Publication 2019 / 0144756 describes a method for fluid coking with increased liquid production. Summary of the invention

[0008] In one aspect, a method for co-processing biomass in a fluidized coking system is provided. The method comprises: exposing a feed containing 1.0 wt% to 60 wt% of biomass and 40 wt% to 99 wt% of a mineral fraction having a T10 distillation point of 500°C or higher to a fluidized bed of particles under fluidized coking conditions in a reactor vessel to form: i) a coker effluent having a liquid portion, ii) char, coke, or a combination thereof, at least a portion of which is deposited on the particles to form particles containing the deposited char, coke, or a combination thereof, and iii) additional hydrocarbons, which are associated with the particles containing the deposited char, coke, or a combination thereof. The method further comprises passing at least a portion of the particles containing the deposited char, coke, or a combination thereof from the reactor vessel into a heater vessel. At least a portion of the particles containing the deposited char, coke, or a combination thereof may contain 0.08 wt% or less of associated additional hydrocarbons relative to the weight of the feed. The method further includes mixing at least a portion of the particles containing the deposited char, coke, or a combination thereof with a portion of the partially gasified particles in the heater container to form a heated particle mixture. The method further includes passing a first portion of the heated particle mixture into the reactor container. The method further includes passing a second portion of the heated particle mixture into a gasification container. The method further includes introducing an oxygen-containing stream and steam into the gasification container. The method further includes exposing the second portion of the heated particle mixture to oxidizing conditions in the gasification container to form gas phase products and partially gasified particles. Additionally, the method includes passing at least a portion of the partially gasified particles from the gasification container to the heater container. In some aspects, the liquid portion of the coker effluent may have a micro-carbon residue content of 0.5 wt % or less, an n-heptane insoluble content of 0.5 wt % or less, or a combination thereof.

[0009] On the other hand, a liquid product is provided. The liquid product can be, for example, the liquid portion of a coker effluent. The liquid product includes 30 wt% to 50 wt% of a naphtha boiling range component, 30 wt% to 50 wt% of a heavy distillate boiling range component, 10 wt% to 25 wt% of a light distillate boiling range component, and 5.0 wt% or less of a vacuum residue boiling range component. Additionally, the liquid product can contain 0.9 wt% to 3.0 wt% of oxygen. Additionally, the liquid product can contain a) a micro carbon residue content of 0.05 wt% to 0.5 wt%, b) 0.05 wt% to 0.5 wt% of n-heptane insolubles, or c) a) and b) combinations. BRIEF DESCRIPTION OF THE DRAWINGS

[0010] Figure 1 An example of a fluidized bed coking system including a coker, a heater, and a gasifier is shown.

[0011] Figure 2 Pyrolysis results for various feeds are shown.

[0012] Figure 3 Results from co-pyrolysis of cellulose with mineral residue oil are shown and compared with predictive model results.

[0013] Figure 4 Shown are the results of co-pyrolysis of pine wood chips with mineral residue oil at 530°C.

[0014] Figure 5 Shown are the results of co-pyrolysis of pine wood chips with mineral residue oil at 360°C.

[0015] Figure 6 The effect of increased reaction rate on hydrocarbon latent load in a three-vessel fluid coking configuration is shown.

[0016] Figure 7 Model product yield results generated from a fluid coking process model at different temperatures are shown.

[0017] Figure 8 Modeling results for fluid coking of resid alone versus co-processing of resid and biomass are shown.

[0018] Fig. 9 Distillation curves for total liquid products from fluid coking of various feeds are shown.

[0019] Fig.10 Additional analysis results of the total liquid products from fluid coking of various feeds are shown.

[0020] Fig.11 Shown is a Fourier transform ion cyclotron resonance (FTICR-MS) analysis of the classes of compounds present in the total liquid product from fluid coking of various feeds. DETAILED DESCRIPTION

[0021] All numerical values ​​in the detailed description and claims herein are modified by the indicated value of "about" or "approximately", and take into account experimental error and variations that would be expected by a person of ordinary skill in the art.

[0022] Overview

[0023] In various aspects, a system and method for integrating coking and gasifying biomass feed in a three-container fluidized coking system under co-processing conditions is provided, so that biomass is co-fed with conventional and / or mineral coker feeds, such as feeds containing residual oil or heavy crude oil. It has been found that the co-processing of biomass feed can unexpectedly increase the coking reaction rate of the conventional / mineral coker feed. This unexpected increase in reaction rate can allow the operation mode of the three-container fluidized coking reaction system to be improved. The resulting improvement in operating conditions can allow the fluidized coker to produce improved and / or improved product compositions. The improvement in the product composition can include an increase in total liquid products and a reduction in micro-carbon residues and / or n-heptane insolubles in the total liquid products. Additionally, the co-processing of biomass with conventional / mineral coker feeds can cause the total liquid product to have an unexpected composition in terms of the component types present in the total liquid product.

[0024] It should be noted that the term "gasification" is used broadly herein to encompass the conversion of biomass to CO and / or H2 at varying ratios of CO to H2, including partial combustion conditions that result in reduced CO production or minimize the amount of H2 production (e.g., substantially no H2 production).

[0025] During operation of the three-vessel fluidized coking system, the central vessel corresponds to a "heater" vessel that serves several functions. First, the heater vessel facilitates heat transfer between the gasifier vessel and the reactor vessel. In the heater, hot coke from the gasifier is mixed with cold coke from the reactor. This produces moderately heated particles that can then be partially returned to the reactor to provide heat for the endothermic coking reaction. Additionally, the gas phase products produced in the gasifier are at least partially returned to the heater as part of the fluidizing gas to transfer the hot coke back to the heater. These gases then leave the three-vessel fluidized coking system from a heater outlet (such as a heater tower top outlet).

[0026] However, the heater container also has some restrictions on the operating conditions of the three-container fluidized coking system. For example, one of the restrictions on operation is that the coke formed in the reactor container needs to be completely solidified before the coke particles are transferred to the heater container. The main reaction in the coking reactor container is a pyrolysis reaction, which can occur relatively quickly under various conditions. However, the combination of a) reaction temperature and b) residence time of the coke particles in the reactor container is usually more stringent than the combination of reaction temperature and residence time required for the coking reaction alone. On the contrary, the residence time and temperature in the coking container are selected to a more stringent level to allow additional reactions to "hydrocarbon carry under" (HCCU). HCCU corresponds to hydrocarbons (coke precursors) entrained by coke particles when the coke particles leave the reactor. Such entrainment can include entrainment in the pores in the coke particles, or entrainment in the flow of coke particles. If these additional hydrocarbons are still at least partially in the fluid phase when entering the heater, the elevated temperature in the heater can volatilize these hydrocarbons. The volatilized hydrocarbons may then deposit at the overhead outlet of the heater, causing fouling and thereby reducing operating life between cleaning cycles.

[0027] In order to maintain a longer operating life between maintenance events, the coking reactor is operated at a combination of fluidized bed temperature and coke particle residence time that is more severe than the combination of fluidized bed temperature and coke particle residence time required for simple pyrolysis. This allows additional reactions to be performed on the HCCU hydrocarbons. The additional reactions allow additional pyrolysis of the HCCU hydrocarbons, so that the amount of potentially volatile hydrocarbons leaving the reactor is reduced or minimized. However, this also means that substantially all of the feed in the coking reactor undergoes additional pyrolysis.

[0028] In various aspects, by co-processing a sufficient amount of biomass and conventional residual oil feed, the severity of the reaction in the reactor can be reduced. It should be noted that the impact of biomass is catalytic in nature, so that even when the amount of biomass in the feed is relatively low, at least a portion of the benefits can be achieved. This allows to improve the resulting product composition from fluid coking. First, the net amount of liquid products can be increased while reducing the generation of light fractions and coke. Secondly, even if the liquid product includes an increased amount of heavier liquid (such as heavy coker gas oil), the amount of micro-carbon residues and / or n-heptane insolubles in the liquid product can be reduced or minimized. When co-processing biomass, the reduction of micro-carbon residues and / or n-heptane insolubles is accompanied by a more general change in liquid product composition. It should be noted that when carrying out the co-processing of biomass and a mineral feed containing a sufficient amount of micro-carbon residues and / or n-heptane insolubles, the benefits of micro-carbon residues and / or n-heptane insolubles reduction are achieved. Therefore, this benefit is typically achieved when co-processing biomass with a mineral feed that includes a substantial portion of components boiling at 500°C or higher.

[0029] In some aspects, for mineral feedstocks containing sufficient amounts of micro carbon residues (MCR) and / or n-heptane insolubles, additional benefits of co-processing biomass and mineral feedstocks can be achieved. In such aspects, the mineral portion of the feedstock for co-processing with biomass (such as the vacuum residue feedstock for co-processing) can have 5.0wt% or more, or 15wt% or more, or 20wt% or more, or 30wt% or more, such as up to 50wt% or possibly higher micro carbon residues. Additionally or alternatively, the mineral portion of the feedstock for co-processing with biomass can have 5.0wt% or more, or 10wt% or more, or 15wt% or more, or 20wt% or more, or 30wt% or more, such as up to 50wt% or possibly higher n-heptane insolubles content. After such feedstock is co-processed with biomass, the resulting total liquid product can have a micro-carbon residue content of 0.5 wt% or less, or 0.2 wt% or less, or 0.1 wt% or less, such as as low as substantially no micro-carbon residue content (0.05 wt% or less). Additionally or alternatively, after such feedstock is co-processed with biomass, the resulting total liquid product can have an n-heptane insoluble content of 0.5 wt% or less, or 0.4 wt% or less, or 0.2 wt% or less, or 0.1 wt% or less, such as as low as substantially no n-heptane insoluble content (0.05 wt% or less). In contrast, a typical coker liquid product (produced in the absence of a biomass co-feed) can contain 0.6 wt% or more, or 1.0 wt% or more, such as up to 5 wt% or more n-heptane insolubles or MCR.

[0030] In various aspects, the total liquid product can also have unexpected oxygen and / or oxidized component content. In some aspects, the oxygen content of the total liquid product through co-treatment can be between 0.9wt% to 3.0wt% or 0.9wt% to 2.5wt%. This is in contrast to the conventional total liquid product from mineral feed processing, which is expected to have an oxygen content of less than 0.5wt%. This is also different from pyrolysis oil, which is expected to have an oxygen content far exceeding 10wt%. Additionally, it has been found that the oxygen content of the total liquid product through co-treatment is unexpectedly lower than the oxygen content expected by the weighted average of the feed used for co-treatment. The unexpected oxygen content can also be characterized based on the number of components / compounds including at least one oxygen atom in the total liquid product. For the total liquid product from conventional mineral feed, the content of oxygen-containing components is expected to be less than 5.0wt%. For pyrolysis oil, it is expected that compounds greater than 50wt% in the total liquid product correspond to oxygen-containing components. In contrast, the co-treated total liquid product may contain between 10 wt% and 40 wt%, or 10 wt% and 25 wt%, or 20 wt% and 40 wt% oxygenated components.

[0031] It should be noted that the above benefits can be achieved when a total liquid product is produced from the co-processing of biomass and mineral residue feedstocks, wherein the total liquid product includes 30 wt% to 50 wt% naphtha boiling range components, 30 wt% to 50 wt% heavy distillates boiling range components, 10 wt% to 25 wt% light distillates boiling range components, and 5.0 wt% or less of vacuum residue boiling range components (e.g., as low as essentially no vacuum residue boiling range components).

[0032] In addition to the benefits associated with the unexpected improvement in reaction rates within the coker reactor described above, a variety of additional features and / or benefits can be achieved by using integrated pyrolysis and gasification to co-process biomass and conventional feeds for fluid coking. An example of a benefit is a reduction in net greenhouse gas emissions. By integrating pyrolysis and gasification, the heat of pyrolysis can be provided by the heat generated during gasification. Because CO2 is consumed by the biomass during its growth, any CO2 produced by the gasification of the biomass does not represent a net increase of CO2 to the environment. In terms of co-processing, the reduction in net CO2 production can be proportional to the amount of biomass char that is gasified relative to the amount of conventional feed that is gasified.

[0033] Another benefit or feature can be related to the synergy between the gasification conditions and the pyrolysis processing conditions. In various aspects, the gasification conditions can be selected so that partial oxidation of the char is carried out in the gasifier. Any char produced by co-processing of conventional feeds in the reactor can also be exposed to partial oxidation conditions. Operating the gasifier under partial oxidation conditions can allow recovery of a synthesis gas product from the gas phase products of the gasifier. The synthesis gas product can be used as a fuel, or the synthesis gas product can be used as an input stream for producing additional liquid products.

[0034] In aspects where the gasifier is operated under partial oxidation conditions, so that the amount of CO produced is increased, the amount of heat generated per carbon atom introduced into the gasifier will be less than the amount of heat generated by conducting a complete oxidation and converting substantially all of the carbon into CO2. Due to this reduction in the heat generated by the gasifier, maximizing the production of liquids in the pyrolysis reactor may increase the likelihood of producing insufficient amounts of coke and / or char to maintain thermal balance in the integrated system. For conventional pyrolysis processes, the goal is to select process conditions that maximize liquid yield. In contrast, in some aspects, rather than maximizing the ratio of liquid products to char produced during pyrolysis, the relative amount of char production can be increased so that additional char is provided to the gasification process. In such aspects, increased char production can allow sufficient char to be delivered to the gasifier to maintain thermal balance and / or can reduce or minimize the amount of additional biomass (or other fuel) added to the gasifier as supplemental fuel.

[0035] In some aspects where integrated pyrolysis and gasification are performed, the biomass may correspond to less than 50 wt % of the feed. In such aspects, the heat generated by partial oxidation in the gasifier is sufficient to maintain thermal balance while still operating at the maximum liquid yield of the pyrolysis reaction. In other aspects, such as some aspects where the biomass corresponds to 50 wt % to 60 wt % of the feed, pyrolysis conditions may be selected to provide increased char production. Additionally or alternatively, in some aspects where insufficient char and / or coke is produced during pyrolysis, additional biomass may be added to the gasifier to maintain thermal balance.

[0036] In some aspects, additional particles may also be present in the reaction environment and / or may be added to the reaction environment. In conventional fluidized coking processes, coke particles are produced in a fluidized coking environment. Coke particles are partially gasified to provide heat, but the remaining coke mass (in the form of particles) after partial gasification may be sufficient to transport heat from the gasifier to other reaction vessels in the reaction system. However, in the presence of a sufficient amount of biomass in the feedstock, the mass of the char and / or coke entering the gasifier may be relatively close to the amount of char and / or coke required for maintaining thermal balance in the system. In such aspects, additional particles may be added to the system to act as heat transfer particles, and maintain the fluidized bed properties of the reaction environment in the reactor. In some aspects, relatively inert particles, such as sand, may be used. In other aspects, at least a portion of the particles may correspond to a catalyst for catalytic pyrolysis reaction.

[0037] definition

[0038] In this discussion, some feeds, fractions, or products may be described based on fractions with boiling points below or above a specified distillation point. For example, a 343°C-product corresponds to a product that substantially contains components with a boiling point (at standard temperature and pressure) of 343°C or less. Similarly, a 343°C+product corresponds to a product that substantially contains components with a boiling point of 343°C or more. Substantially containing components within a boiling range is defined herein as a product that contains 90 vol% or more of the boiling range, optionally 95 vol% or more of the components, such as all components within a specified boiling range.

[0039] In this discussion, a liquid product is defined as a product that is substantially in the liquid phase at 20°C and about 100 kPa-a. Similarly, a gaseous product is defined as a product that is substantially in the gaseous phase at 20°C and about 100 kPa-a.

[0040] In this discussion, reference may be made to the conversion of feedstock relative to the conversion temperature. Conversion relative to temperature may be defined based on the portion of feedstock that boils above the conversion temperature. The amount of conversion during a process (or optionally across multiple processes) may correspond to the weight percentage of the raw material that is converted from boiling above the conversion temperature to boiling below the conversion temperature. As an illustrative hypothetical example, consider a feedstock comprising 40wt% of a component that boils at 650℉ (about 343℃) or higher. By definition, the remaining 60wt% of the feedstock boils at a temperature below 650℉ (about 343℃). For such feedstocks, the amount of conversion relative to a conversion temperature of about 343℃ will only be based on the 40wt% that initially boiled at about 343℃ or higher. If such feedstocks can be exposed to a process with a 30% conversion relative to a conversion temperature of about 343℃, the resulting product will include 72wt% of about 343℃-components and 28wt% of about 343℃+components.

[0041] As defined herein, the term "hydrocarbon-containing" includes compositions or fractions containing hydrocarbons and hydrocarbon-like compounds, which may contain heteroatoms commonly found in petroleum or renewable oil fractions and / or heteroatoms that may be introduced during conventional processing of petroleum fractions. Heteroatoms commonly found in petroleum or renewable oil fractions include, but are not limited to, sulfur, nitrogen, phosphorus, and oxygen. Other types of atoms other than carbon and hydrogen that may be present in the hydrocarbon-containing fraction or composition may include alkali metals and trace amounts of transition metals (such as Ni, V, or Fe).

[0042] In this discussion, the distillation point and / or distillation range may be determined according to ASTM D2887. If a portion of the sample is not suitable for characterization using ASTM D2887, then ASTM D7169 may be used for characterization.

[0043] In this discussion, the vacuum residue boiling range is defined as 538°C and above. It should be noted that it is difficult to characterize the final boiling point of some vacuum residue fractions, but the easily distilled vacuum residue portion can have an endpoint of up to about 750°C. It should be further noted that fractions consisting primarily of vacuum residue generally contain a large amount of lower boiling components. In this discussion, the vacuum residue boiling range fraction is a fraction having a T10 distillation point of 480°C or higher (e.g., up to 600°C).

[0044] In this discussion, the naphtha boiling range is defined as 29°C to 221°C. The light distillates boiling range is defined as 221°C to 343°C. It should be noted that the light distillates boiling range may also be referred to as the diesel boiling range. The heavy distillates boiling range is defined as 343°C to 538°C. It should be noted that the heavy distillates boiling range may also be referred to as the vacuum gas oil boiling range.

[0045] The trace carbon residue can be determined according to ASTM D4530. The content of n-heptane insoluble matter in the sample can be determined according to ASTM D3279.

[0046] raw material

[0047] In various fields, biomass can be co-processed in fluidized bed coking environment.Biomass can be co-processed with the raw material (such as mineral raw material) not derived from biomass, and / or the raw material corresponding to the conventional boiling range of boiling range and fluidized coking feed.In some aspects, biomass can be corresponding to 1.0wt% to 60wt% of the charging for co-processing, or 1.0wt% to 50wt%, or 1.0wt% to 35wt%, or 10wt% to 60wt%, or 10wt% to 50wt%, or 10wt% to 35wt%, or 20wt% to 60wt%, or 20wt% to 50wt%, or 30wt% to 60wt%, or 30wt% to 50wt%, or 50wt% to 60wt%.

[0048] The biomass used for the feed can be any convenient type of inedible lignocellulosic biomass; i.e., biomass consisting primarily of cellulose, hemicellulose, lignin, or a combination thereof. Some forms of biomass can include direct forms of biomass, such as algae biomass and plant biomass. Examples of suitable biomass sources can include woody biomass and switchgrass.

[0049] In biomass at least partly as solid form is introduced into the aspect of fluidized coking reactor, having small particle size can promote solid transport in reactor.Less particle size also may contribute to realize desired biomass conversion level.Therefore, can use one or more optional physical treatment steps to prepare the biomass of solid form for conversion.In order to prepare the solid for gasification, solid can be crushed, shredded, ground or otherwise physically treated, so that average particle size is reduced to 3.0cm or less, or 2.5cm or less, or 2.0cm or less, or 1.0cm or less, as reduced to 0.001cm or may be less.In order to determine average particle size, particle size is defined as the diameter of the minimum boundary sphere containing particle.

[0050] Without being bound by any particular theory, it is believed that when co-processing mineral feedstock, the oxidation part of cellulose, lignin and hemicellulose in biomass helps to increase the reaction rate. In various aspects, the biomass for co-processing can have a cellulose content of 10wt% or more (relative to the weight of the biomass), or 20wt% or more, or 30wt% or more, such as until using a biomass consisting essentially of cellulose (e.g., cotton balls or other biomass containing up to 100wt% cellulose). In such aspects, the lignin content of the biomass can be optionally less than 35wt%, or 30wt% or less, such as as low as substantially no lignin content (1.0wt% or less).

[0051] Based on the boiling range of the feed, biomass can be co-processed with one or more additional raw materials (such as mineral raw materials). The amount of one or more additional raw materials can correspond to 40wt% to 99wt% of the feed for co-processing, or 50wt% to 99wt%, or 65wt% to 99wt%, or 40wt% to 90wt%, or 50wt% to 90wt%, or 65wt% to 90wt%, or 40wt% to 80wt%, or 50wt% to 80wt%, or 40wt% to 70wt%. Conventionally, heavy oil feeds are commonly used as feedstocks for fluidized coking processes. Therefore, heavy oil feeds will typically be heavy (high boiling) vacuum petroleum crude oils; petroleum atmospheric distillation bottoms; petroleum vacuum distillation bottoms or residues; asphalt; earth asphalt; asphalt; other heavy hydrocarbon residues; tar sands oil; shale oil; or even coal slurry or coal liquefaction products, such as coal liquefaction bottoms. Such feeds typically have at least 5 wt.%, typically 5 to 50 wt.% Conradson Carbon Residue (ASTM D189-165). Preferably, the feed is a petroleum vacuum residue. In some aspects, one or more additional feedstocks may have a T10 distillation point (as determined according to ASTM D2887) of 343°C or more, or 400°C or more, or 450°C or more, or 500°C or more, such as up to 600°C or possibly more.

[0052] Typical petroleum (mineral) feeds suitable for processing in a fluidized bed coker may have compositions and properties within the ranges shown below.

[0053] Table 1: Examples of Coker Feedstocks

[0054]

[0055]

[0056] It should be noted that other components may also be included in the feed for co-processing in the fluid coker. In some aspects, 20 wt% or less of the feed for co-processing may correspond to a) non-biomass and / or biomass-derived components, and b) components having a boiling point below 340° C., such as being as low as substantially free of such components.

[0057] Hydrocarbon Undercurrent Control (HCCU)

[0058] In various aspects, the increase in reaction rate provided by co-processing lignocellulosic biomass under fluidized coking conditions can allow for a change in the target operating conditions of the feed, thereby allowing for the production of a modified and / or improved product profile. This change is achieved in part by reducing the residence time required for complete solidification of coke precursor entrained in the coke exiting the coker reactor vessel and passing into the heater vessel.

[0059] Hydrocarbon carryover (HCCU) corresponds to coke precursors that are not completely converted to solid form before leaving the coker reactor and entering the heater. Due to the high temperature in the heater, these coke precursors volatilize and are then deposited on cooler surfaces (such as the overhead outlet of the heater). This results in the formation of coke in the overhead outlet, ultimately resulting in a contraction of the outlet flow, and a shutdown is required to restore the flow path in the overhead outlet to its original size. In order to avoid shortening the reaction cycle, HCCU is maintained at a relatively low level by selecting sufficiently harsh reaction conditions. Specifically, a higher temperature is selected to maintain HCCU at a sufficiently low level relative to the average residence time of the coke particles in the coker reactor vessel.

[0060] It has been found that co-processing lignocellulosic biomass (containing cellulose) in a fluidized coker can increase the reaction rate in the coker reactor. The increase in this reaction rate also increases the reaction rate of the coke precursor solidification process. Without being bound by any particular theory, it is believed that the increase in reaction rate / increase in solidification rate is due to the generation of oxygen-containing free radicals in the fluidized coking environment. It is believed that these oxygen free radicals promote the cracking of the mineral part of the feed in the fluidized coking environment. Additionally, it is believed that the oxygen free radicals can also help some coke precursor compounds to be converted into compounds that form liquid products. Finally, it is believed that these oxygen free radicals help the solidification process of the remaining coke precursor, so that the HCCU is significantly reduced or minimized. As a result, the temperature in the fluidized bed of the coker reactor can be reduced while still maintaining the target level of HCCU. By reducing the temperature and / or based on the unexpected catalytic benefits of co-processing with biomass, improved and / or improved product formation can be achieved.

[0061] During operation of a three-vessel fluid coking system, the amount of HCCU is typically maintained at a low level. In various aspects, by co-processing a mineral feedstock with biomass, the temperature and / or coke particle residence time in the coker reactor vessel can be reduced while still maintaining a low level of HCCU. In various aspects, during operation of the coker reactor vessel, the amount of HCCU can correspond to 0.08 wt% or less of the input feed, or 0.06 wt% or less, such as as low as essentially no HCCU (0.005 wt% or less). The amount of HCCU can be characterized, for example, by sampling cold coke from the coke transfer line between the reactor and heater sections of a commercial flexible coker during steady-state operation, and thermally treating the sampled material in an oxygen-free environment at a temperature matching the heater section of the commercial unit. The mass loss wt% of the volatilized material removed from the solid sample under these conditions corresponds to the HCCU.

[0062] Fluid coking system operating conditions

[0063] The feed for co-processing can be introduced into the fluidized coking reactor by any convenient method. One option is to form a slurry and / or solution of biomass in conventional feed. As another option, biomass can be introduced separately from the co-feed as a raw material mainly consisting of solids. In this type of aspect, a feeding mechanism (such as a screw feeder) for delivering solids can be used. The feed can be preheated before entering the reactor. For example, in the aspect of using conventional co-feed to form slurry, preheating can increase the temperature of the feed so that the feed is flowable and pumpable. Then, the slurry can be passed into the reactor towards the top of the reactor vessel by one or more slurry injection nozzles.

[0064] In various aspects, the temperature in the fluid coking zone of the reactor may be in the range of 400° C. to 550° C. or 400° C. to 500° C. The pressure may be in the range of 120 kPag to 400 kPag (17 psig to 58 psig), and preferably 200 kPag to 350 kPag (29 psig to 51 psig).

[0065] The conditions in the fluidized coking zone can be selected so that the desired amount of feedstock conversion occurs in the fluidized bed reactor. The amount of coking reaction and conversion can be selected to be similar to the values ​​used in conventional fluidized coking reactions. For example, conditions can be selected to achieve a conversion of at least 10 wt% relative to 343°C (or 371°C), or a conversion of at least 20 wt% relative to 343°C (or 371°C), or a conversion of at least 40 wt% relative to 343°C (or 371°C), such as a conversion of up to 80 wt% or possibly higher. In some aspects, the light hydrocarbon products of the coking (thermal cracking) reaction evaporate, mix with the fluidizing steam, and pass upward through the dense phase of the fluidized bed into the dilute phase region above the dense fluidized bed of coke particles. It should be noted that in some aspects, other purge gases (such as CH4, H2 or other light gases) can be used to replace at least a portion of the steam (such as replacing substantially all of the steam at most) to help control the severity of the conversion. In some configurations, this mixture of vaporized hydrocarbon products formed in the coking reaction flows upward through a dilute phase with steam at a superficial velocity of about 1 to 2 m / s (about 3 to 6 ft / s), entraining some fine solid particles of coke, which are separated from the cracked vapors in the reactor cyclone separator as described above. The cracked hydrocarbon vapors are passed out of the cyclone separator, enter the scrubbing section of the reactor, and then undergo product fractionation and recovery. The cracked hydrocarbon vapors may include one or more liquid products having a boiling range of 343°C or less. Examples of 343°C-liquid products include naphtha boiling range products and distillate boiling range products.

[0066] In some aspects, as the cracking process proceeds in the reactor, coke, char and / or other particles (such as optional sand particles) pass downward through the pyrolysis zone, through the stripping zone, where obstructed hydrocarbons are stripped by an ascending stream of fluidizing gas (steam), and then exit the coking reactor and pass into a heating vessel.

[0067] The heating vessel receives particles from both the coker reactor vessel and from the gasification vessel. The particles arriving from the coker reactor correspond to "cold" particles, while the particles arriving from the gasification vessel correspond to "heated" particles. In the heater vessel, the particles are mixed resulting in heat transfer from the heated particles to the cold particles. A portion of the particles are then sent to the coker reactor, while another portion of the particles are sent to the gasification reactor for further heating. The remaining portion of the particles can be extracted from the heater vessel. Removing particles from the heater vessel provides a mechanism for avoiding metal buildup within the fluid coking system.

[0068] Combustion / oxidation products produced in the gasifier (such as synthesis gas components formed during partial oxidation) can serve as the fluidizing gas in the heater to mix the particles.

[0069] The particles can leave the heating vessel by passing into a coker reactor vessel or by passing into a gasification reactor. A gasification reactor (gasifier) ​​contains a fluidized bed of solid particles and is operated at a temperature above the temperature of the reactor coking zone. In the gasifier, the coke particles are converted into a fuel gas comprising primarily carbon monoxide and hydrogen by reaction with steam and an oxygen-containing gas at high temperature.

[0070] The gasification zone is typically maintained at an elevated temperature in the range of 650°C to 1000°C, such as 850°C to 1000°C (1560°F to 1830°F), to maximize H2 / CO; or in the range of 650°C to 850°C, to maximize CO; or in the range of 650°C to 760°C. The gasification zone may be maintained at a pressure in the range of 0 kPag to 1000 kPag (0 psig to 150 psig), preferably 200 kPag to 400 kPag (30 psig to 60 psig). Steam and an oxygen-containing gas are introduced into the gasifier to react with solid particles containing coke deposited thereon in the coking zone. Preferably, the oxygen-containing gas may have an oxygen content greater than that of air. Air may be used, but this increases the volume of nitrogen, which will then be separated from the gasifier product to recover the synthesis gas. Alternatively, if the gasifier product is used as the fuel gas, the additional nitrogen from the air reduces the concentration of the fuel in the fuel gas. In some aspects, the gasification zone can be contained in a gasifier associated with the reactor, such as a gasifier from a fluid coking system. In some aspects using a system similar to a fluid catalytic cracking system, the gasification zone can be contained in a "gasifier" corresponding to a regenerator associated with a riser reactor.

[0071] In some aspects, the oxygen-containing gas can have a low nitrogen content, such as oxygen from an air separation unit or another oxygen stream comprising 95vol% or more oxygen or 98vol% or more, such as substantially only containing oxygen at most. In other aspects, the oxygen-containing gas can be generally enriched relative to air, such as having an oxygen content of 21vol% or more, or 30vol% or more, or 40vol% or more, or 50vol% or more, such as substantially only containing oxygen at most. In some aspects, the oxygen content can be 21vol% to 50vol%, or 21vol% to 40vol%, or 21vol% to 30vol%. Additionally or alternatively, the N2 content of the oxygen-containing gas can be 70vol% or less, or 50vol% or less, or 35vol% or less, or 20vol% or less, or 10vol% or less, such as being as low as substantially without N2 content. In the aspect that the oxygen-containing gas is enriched relative to air, it may also be desirable to introduce a diluent stream to facilitate the transport of additional heat out of the gasifier. An example of a separate diluent stream can be recycled CO2 and / or H2S delivered from the overhead gas produced by the gasifier. The amount of diluent can be selected by any convenient method. For example, the amount of diluent can be selected so that if air is used as an oxygen-containing stream, the amount of diluent replaces the weight of N2 that will be present in the oxygen-containing stream. As another example, the amount of diluent can be selected to allow substitution of the same BTU value for heat removal, if N2 is present based on the use of air as an oxygen-containing stream, the heat removal will be available. Relative to conventional operation, these types of strategy examples can allow maintaining substantially the same or similar temperature profile in the gasifier. It should be noted that if CO2 is used as a diluent, this can increase the CO2 concentration (and reduce the N2 concentration) of the resulting flue or exhaust gas from the gasifier. This can promote carbon capture of the resulting flue or exhaust gas, or alternatively can promote carbon capture of another stream derived from the flue or exhaust gas.

[0072] In the gasification zone, the reaction between coke and / or char and steam and oxygen-containing gas produces a fuel gas containing carbon monoxide and a partially gasified residual coke product. In some aspects, the fuel gas may further contain H2, while in other aspects, the fuel gas may include a content that reduces or minimizes H2, such as being as low as substantially free of H2. The conditions in the gasifier are selected accordingly to produce these products. The rate of steam, oxygen and CO2 (or other diluent gases) will depend on the rate at which cold coke and / or char enter from the reactor. The amount of steam and oxygen may be selected so that the conditions in the gasifier correspond to partial oxidation conditions, so as to increase the production of CO at the expense of CO2. Typically, the conditions of partial oxidation may correspond to conditions in which the amount of oxygen in the environment is significantly lower than the stoichiometric amount required for complete combustion of coke and / or char particles. The amount of steam may also be optionally significantly increased. By providing a substoichiometric amount of oxygen, insufficient oxidant may be used to burn available fuel. In some aspects, the flow rate of O2 introduced into the gasifier may correspond to 45% to 75% of the O2 required for complete combustion of all coke and char. The introduction of additional steam can promote the water-gas shift reaction so that a portion of the CO produced by combustion is converted to H 2. This can help produce a target ratio of H 2 to CO in the resulting synthesis gas in the gasifier output stream.

[0073] The overhead gas product from the gasifier may contain entrained coke and / or char solids, and these entrained coke and / or char solids are removed in the gasifier section of the unit by cyclones or other separation techniques; the cyclones may be internal cyclones in the main gasifier vessel itself, or external cyclones in a separate smaller vessel as described below. The overhead gas product is removed from the gasifier cyclones as overheads. The resulting partially vaporized solids are removed from the gasifier and introduced directly into the coking zone of the coking reactor at a level in the dilute phase above the lower dense phase.

[0074] In some aspects, the partially gasified solid coke and / or char particles exiting the gasifier may be insufficient to deliver the necessary amount of heat to the pyrolysis reaction. Additionally or alternatively, the total content of coke and / or char particles in the integrated reaction system may be insufficient to maintain the desired fluidized bed conditions in the pyrolysis reaction while the particles are also present in the gasifier. In such aspects, additional particles may be added to the reaction system. Sand or other inert particles are one type of option.

[0075] In aspects where gasification of char and / or char does not provide sufficient heat for pyrolysis, additional fuel can be added to the gasifier. In some aspects, fuels such as methane or mineral feedstock can be used. Preferably, the additional fuel can correspond to the biomass or atomic biomass fuel so that any CO2 produced in the gasifier corresponds to CO2 produced by the fuel derived from the biological source.

[0076] An example of a fluid coking system with an integrated gasifier is the Flexicoking TM system. In some aspects, the integrated process can allow for the reduction or minimization of the production of inorganic nitrogen compounds by using oxygen from an air separation unit as the oxygen source for gasification. Although the amount of nitrogen introduced into the gasification as a diluent will be reduced, minimized, or eliminated, the integrated process can also allow for the gasification of coke while reducing, minimizing, or eliminating the production of slag or other glassy materials in the gasifier. This can be achieved, for example, by recycling a portion of the CO2 produced during gasification back to the gasifier. Additionally or alternatively, other diluent compounds such as steam, CO, and / or inorganic compounds (such as inorganic compounds that are non-reactive in the gasifier environment) can also be used.

[0077] One of the difficulties of using petroleum coke, coal and / or heavy oil as gasification feed is that such feed may potentially contain relatively high percentages of transition metals such as iron, nickel and vanadium. During normal operation of the gasifier, these transition metals are converted into "slag", which tends to corrode the internal structure of the gasifier. Therefore, gasifiers typically have relatively short operating lengths between shutdown events, such as operating lengths of about 3 to 18 months. Biomass can include lesser amounts of such metals, but the metals can still be present. Additionally, in some aspects, biomass can be co-processed with conventional fluid coking feeds.

[0078] For independently operated gasifiers, frequent shutdown events are acceptable. However, for gasifiers that are integrated to provide heat balance for another process (such as a fluidized bed coker), short cycle lengths for the gasifier may also necessitate short cycle lengths for the coker. To overcome this problem, a gasifier that is thermally integrated with a fluidized bed coking process and / or a pyrolysis process may be operated under conditions that reduce, minimize, or eliminate the formation of slag.

[0079] One option for avoiding slag formation is to use air as at least a major portion of the oxygen source for the gasifier integrated with the fluidized bed coking process. Additional nitrogen in the air can provide a diluent for the gasifier environment that can reduce or minimize slag formation. The metal in the coke can be retained in the form of coke and purged from the integrated system, rather than forming slag or other glassy products containing metals. This can allow the removal / disposal of metals in a secondary device or location. By avoiding the formation of corrosive slag, the cycle length of the integrated coker and gasifier can be significantly improved. However, the additional nitrogen produced using air as an oxygen-containing stream can dilute the overhead gas product from the gasifier, making it difficult to use the overhead gas as a fuel in a conventional burner. Alternatively, additional nitrogen may increase the cost associated with recovering synthesis gas from the gasifier overhead product.

[0080] Instead of using air as an oxygen source, an oxygen-containing stream with increased oxygen content, such as an oxygen-containing stream produced by an air separation unit, can be used. Although reducing the nitrogen content of the fuel gas may be beneficial, the nitrogen introduced into the gasifier also provides benefits in the form of reducing or minimizing the formation of slag or other glassy compounds in the gasifier. In order to maintain a reduced or minimized slag formation level (such as no slag formation), an alternative diluent can be introduced into the gasifier. In various aspects, the alternative diluent can correspond to CO2, H2S, steam, other inorganic compounds or a combination thereof. Optionally, at least a portion of the alternative diluent can correspond to a recycle stream. The addition of steam and H2S also helps to reduce metal carburization and metal corrosion caused by the high carbon activity of the gasification product gas. This helps to allow the use of lower cost metallurgy. Although gasification is usually carried out under the condition that a limited amount of oxygen is present in the reaction environment, at least some CO2 is usually formed by the gasification reaction. Additionally, the water-gas shift equilibrium of the syngas may potentially favor the additional formation of CO2, depending on the temperature and the relative concentrations of H2, H2O, CO, and CO2. As a result, the overhead product formed in the gasifier may include a large portion of CO2. The CO2 formed in the gasifier environment may be separated by any convenient method, such as by using a monoethanolamine wash or another type of amine wash. Conveniently, the amine wash may also be suitable for removing any H2S formed during gasification (such as by reaction of H2 with sulfur present in the coke). In some aspects, multiple amine regeneration steps may be used to desorb CO2- and H2S-rich streams separately, thereby allowing control of the amount of recycled CO2 while also allowing separate treatment of H2S. In some aspects, a selective amine wash (such as Flexsorb 2000) may first be used before using a more general amine wash for CO2 separation. TMprocess) to remove H2S. The pressure at which amine absorption of CO2 occurs can range from about 20 Psia to 1500 Psia (about 140 kPa-a to 10.5 MPa-a), and is optimized based on the overall configuration of the plant, including factors such as the use of a low-pressure or high-pressure CO shift reaction section and compression costs. At higher pressures, the range of choices for amines or solvents for absorbing CO2 is expanded, which can minimize the cost and energy requirements of CO2 absorption and desorption. At lower pressures, amines such as methylethylamine (MEA) may be preferred. At medium pressures, amines such as methyldiethylamine (MDEA) may be preferred. At high pressures, chemical solvents such as methanol may be preferred.

[0081] After separation of CO2 and / or H2S from the fuel gas, a portion of the CO2 can be recycled back to the gasifier as a diluent to reduce or minimize the formation of slag. In some aspects, the net concentration of O2 in the oxygen stream introduced into the gasifier, after addition of any diluents and / or steam, can be 22 vol% to 60 vol% relative to the weight of the combined oxygen stream plus diluents and / or steam. In terms of recycling CO2, at least a portion of the H2S present in the CO2 stream can be removed before the CO2 stream is recycled to the gasifier. This can help maintain conditions in the gasifier, allowing the metal and / or ash content of the coke to be removed from the gasifier as part of the coke purge, rather than forming a corrosive slag. Alternatively, a portion of the fuel gas after or before H2S adsorption (such as a Flexsorb unit) can be compressed and recycled back as a diluent stream.

[0082] By reducing or minimizing the amount of N2 in the fuel gas, while also reducing or minimizing slag formation, the fuel gas produced by the integrated coker / gasifier can have a significantly increased content of synthesis gas. After removal of sulfur contaminants, water, and / or a large portion of CO2, the resulting overhead gas can correspond to 70 vol% to 99 vol%, or 80 vol% to 95 vol% H2 and CO, which is a component of the synthesis gas used for methanol production. This is of sufficient purity and / or high enough quality to be potentially valuable for use in the synthesis of other compounds.

[0083] In various aspects, it should be noted that the reaction conditions within the coker reactor vessel, the heater vessel, and the gasification vessel may be different from one another. The coker reactor vessel may be operated at a temperature of 550°C or less. The heater vessel may be operated at a temperature between 550°C and 700°C, wherein the temperature in the heater is 50°C or more, or 100°C or more, such as up to 250°C or possibly higher, than the temperature in the coker reactor. In the presence of sufficient O2 for partial oxidation, the gasifier may be operated at a temperature of 650°C or more. The temperature in the gasifier may be 50°C or more, or 100°C or more, such as up to 250°C or possibly higher, than the temperature in the heater.

[0084] Examples of Integrated Reaction Systems

[0085] Figure 1 An example of a system including a gasifier is shown, which is thermally integrated with a fluidized bed coker having three reaction vessels: a reactor, a heater, and a gasifier. The unit includes a reactor section 10 having a pyrolysis zone and its associated stripping and washing section (not shown separately), a heater section 11, and a gasifier section 12. The relationship between the pyrolysis zone, the washing zone, and the stripping zone in the reactor section is shown, for example, in U.S. Pat. No. 5,472,596, which describes these relationships in terms of the pyrolysis zone corresponding to the coking zone of conventional feedstock. U.S. Pat. No. 5,472,594 is incorporated herein by reference for the limited purpose of further describing the relationship between the pyrolysis zone, the washing zone, and the stripping zone. The heavy oil feed is introduced into the device via line 13, and the pyrolysis and / or cracking hydrocarbon products are extracted via line 14. Fluidizing and stripping steam is provided by line 15. Cold char, coke and / or other particles (such as sand) used to form the fluidized bed are withdrawn from the stripping section at the base of the reactor 10 through line 16 and passed to the heater 11. Of course, the term "cold" applied to the temperature of the withdrawn char / coke / particles is absolutely relative, since it is much higher than the ambient temperature at the operating temperature of the stripping section. The hot char / coke / particles are circulated from the heater 11 to the reactor 10 through line 17. The char / coke / particles from the heater 11 are transferred to the gasifier 12 through line 21, and the hot, partially gasified char / coke / sand particles are circulated back to the heater from the gasifier through line 22. A portion of the excess char / coke / particles can be withdrawn from the heater 11 through line 23. This is beneficial, for example, for reducing or minimizing the accumulation of metals in the gasifier.

[0086] The gasifier 12 can be supplied with steam and an oxygen-containing gas via line 24. The heated gasification products (including synthesis gas) can be transported from the gasifier to the heater via line 25. In some aspects, the oxygen-containing gas can correspond to air. In other aspects, an oxygen stream with a purity of 55 vol% or more, such as an oxygen stream from an air separation unit, can be provided instead of supplying air to the gasifier 12 via line 24. In such aspects, in addition to supplying the oxygen stream, an additional dilution gas stream can be supplied via line 31. The additional dilution gas can correspond to CO2 separated from the fuel gas produced during gasification, for example. The gasification products including synthesis gas can be removed from the unit via line 26 on the heater. Particle fines (such as char fines or coke fines) can be removed from the gasification products in a heater cyclone system 27, which includes a primary and secondary cyclone separator in series with a dip tube that returns the separated fines to the fluidized bed in the heater. The gasification product from line 26 may then undergo further processing, such as separation of desired synthesis gas components from the remainder of the gasification product.

[0087] It should be noted that in some optional aspects, the heater cyclone system 27 can be located in a separate container (not shown) rather than in the heater 11. In such aspects, the pipeline 26 can extract the gasification products from the separate container, and the pipeline 23 for purging excess coke can correspond to the pipeline for conveying coke fines from the separate container. Relative to the raw material, these coke fines and / or other partially gasified coke particles discharged from the heater (or gasifier) ​​can have an increased metal content. For example, the weight percentage of metal in the coke particles discharged from the system (relative to the weight of the discharged particles) can be greater than the weight percentage of metal in the raw material (relative to the weight of the raw material). In other words, the metal from the raw material is concentrated in the discharged coke particles. Since the gasifier conditions do not produce slag, the discharged coke particles correspond to the mechanism of removing metals from the coker / gasifier environment. In some aspects, the metal can correspond to a combination of nickel, vanadium and / or iron. Additionally or alternatively, the gasifier conditions may result in substantially no metal oxide deposition on the interior walls of the gasifier, such as less than 0.1 wt%, or less than 0.01 wt% deposition of metals present in the feedstock introduced into the coker / gasifier system.

[0088] In such Figure 1 In the configuration shown, the features of the system elements shown in the figure are based on the fluid communication between the elements. For example, the reactor section 10 is in direct fluid communication with the heater 11. The reactor section 10 is also in indirect fluid communication with the gasifier 12 through the heater 11.

[0089] Example 1 - Coke Generation, Partial Gasification and Heat Balance

[0090] Coking is a type of pyrolysis. The conditions for fast pyrolysis can be similar to those for fluid coking. This can facilitate co-processing of biomass with conventional fluid coking feedstocks in a fluid coking reaction system.

[0091] Table 1 shows a comparison of the typical compositions of coke produced during fluid coking of a heavy oil mineral feed and char produced during fast pyrolysis of biomass.

[0092] Table 1 - Comparison of charcoal and coke

[0093]

[0094] As shown in Table 1, char from biomass is primarily composed of carbon, hydrogen and oxygen. This contrasts with the composition of coke from heavy oil mineral feeds, which is primarily composed of carbon, hydrogen and sulfur. The compositions are otherwise similar, but the higher heating value of the coke is approximately 10% higher than the higher heating value of the char. This means that under full or partial oxidation conditions, an additional weight of char is required during gasification to obtain the same amount of heat compared to the coke.

[0095] Table 2 shows the comparison of the operating conditions and products of the fluid coking reaction system for operating the fluid coking of conventional heavy oil feedstock or the fast pyrolysis of biomass. The reaction system configuration of the values ​​in Table 2 is similar to Figure 1 Configuration shown. Fluid coking values ​​represent experimental data, while pyrolysis values ​​are predictions of biomass pyrolysis yields based on public sources.

[0096] Table 2 - Comparison of Fluidized Coking Operation and Biomass Pyrolysis in Fluidized Coking Reactors

[0097] Fluid coking (mineral feed) Pyrolysis (100% biomass - calculated) T(dilute phase) 530C 530C P(dilute phase) 35psia 35psia Feed rate 46kbd 5000T / day C5+ Product Rate (klb / hr) 360 330 Gas phase products (klb / h) 95 50 Coke / Char Production (klbs / hr) 165 60

[0098] In Table 2, the pyrolysis conditions are selected to be similar to the fluidized coking conditions. The feed rate is selected so that the heat of biomass pyrolysis is equivalent to the heat of pyrolysis (coking) required for the fluidized coking example. As shown in Table 2, the product yield of biomass pyrolysis is generally lower, partly because biomass pyrolysis also generally produces water, accounting for about 10wt% of the total product. For the biomass pyrolysis example, the weight ratio of char relative to the weight of the gas phase product is also reduced.

[0099] It should be noted that under partial gasification conditions, the weight of char produced by pyrolysis in Table 2 is insufficient to provide the heat required to sustain the pyrolysis reaction. One option for generating additional heat in the gasifier is to add biomass directly to the gasifier. This can increase the output of heat and the output of synthesis gas produced in the gasifier. Additionally, by using biomass as a supplemental fuel in the gasifier, any CO2 produced by gasification of the biomass will correspond to atomic biogenic source CO2, thereby reducing or minimizing net greenhouse gas emissions associated with the process.

[0100] Adding biomass to the gasifier does not result in a significant change in the composition of the overhead gas from the gasifier. To illustrate this, simulation calculations were performed for the gasification of char from biomass in the gasifier. A second set of calculations was also performed in which 20 wt% of the feed entering the gasifier corresponded to biomass instead of char. In the calculations, air was used as the source of oxygen-containing gas. Table 3 shows the overhead gas composition from the calculations.

[0101] Table 3 - Gasifier overhead product gas composition

[0102]

[0103]

[0104] Incorporating 20 wt% biomass into the input stream to the gasification reaction had only a modest effect on the overall product distribution as shown in Table 3. The biomass appears to result in additional water being present in the gasifier environment with a slight reduction in the overall content of carbon oxides.

[0105] Example 2 - Increased reaction rate of mineral coking feedstock during biomass co-processing

[0106] In some aspects, solid biomass can be co-processed with mineral residue feed part under fluidized coking conditions, wherein solid biomass corresponds to 1.0wt% or more (or 10wt% or more, or 20wt% or more) of the combined feed, and mineral residue feed corresponds to 40wt% or more (or 50wt% or more) of the combined feed. In such aspects, it has been found that the presence of biomass in the fluidized coking environment can increase the pyrolysis reaction rate of the mineral residue part of the combined feed. This can potentially allow multiple processing advantages, including, but not limited to, increasing product yield and reducing the reaction temperature during fluidized coking.

[0107] The pyrolysis (such as coking) reaction rate of the mineral residue feed part unexpectedly improves when co-processing with solid biomass by a series of pyrolysis reactions carried out to various combinations of biomass and mineral residue feed. For the pyrolysis reactions involving mineral residue feed, the residue feed corresponds to a vacuum residue fraction with an MCR of 9.46wt%, an estimated n-heptane insoluble content of 1.1wt%, and a T10 of 553°C. For biomass, cellulose is used as solid biomass in some operations, while pine chips are used in other operations. Biomass has an average particle size of about 0.5mm. More generally, biomass can have an average particle size of about 0.25mm to 2500mm or 0.5mm to 2.0mm.

[0108] In the first set of runs, cellulose, mineral residue oil and a mixture of 30wt% cellulose and 70wt% residue oil were pyrolyzed. The runs were performed in a thermogravimetric analysis (TGA) unit to allow detailed measurements of a) temperature and b) weight loss of feed during the pyrolysis reaction. In a TGA experiment, solid and / or liquid samples are loaded into a small (about 50 mg), open pan, and this pan is fixed in a temperature-controlled cell. All oxygen in the cell is purged with flowing nitrogen, and the temperature of the cell is quickly raised to a target value. When nitrogen flows through the cell, the temperature of the cell is maintained at this target value. During this process, the contents in the TGA pan are pyrolyzed, so that some or all of the samples in the sample are cracked into low molecular weight species, volatilized or both. The volatilized contents of the TGA pan are eluted from the cell in a nitrogen carrier gas, and the mass loss from the TGA pan is recorded by a weight balance. This process is recorded in the form of residual mass (normalized relative to 100%) relative to time and cell temperature. The weight loss represents the feed amount of fluid converted from the solid to the gas phase under pyrolysis conditions.

[0109] In the first set of runs, the target pyrolysis temperature was set to 400° C. However, since it takes some time to heat the vessel to the target temperature, the pyrolysis reaction (at least for cellulose) will begin before the target temperature of 400° C. is reached. To this end, time is rescaled proportionally with temperature using a metric called equivalent residence time (ERT; Equation 1):

[0110] (1)

[0111] In Equation 1, t is time, T is the absolute temperature of the TGA cell, Tref is the reference temperature (e.g., 400°C), R is the gas constant, and E app is the apparent activation energy selected by the user (210 kJ / mol is a typical value for residue pyrolysis). Therefore, ERT at temperature allows the TGA curve to be analyzed as if the process occurred at a constant temperature (similar to continuous pyrolysis processes such as flexicoking). In this discussion, the ERT temperature will be specified for displaying the data over time.

[0112] Figure 2 The pyrolysis results of cellulose 310 alone and resid feed 220 alone are shown. Figure 2 It is based on ERT at 400°C. Figure 2As shown, pyrolysis of cellulose occurs rapidly at 400° C., with substantially all of the clumps in the cellulose that are readily converted to fluid being completed in about 2 minutes or less. In contrast, pyrolysis of the residual oil feed at 400° C. requires significantly longer time, with some pyrolysis still occurring after about 55 minutes in the reactor. It should be noted that both the cellulose pyrolysis residual mass curve 210 and the mineral residue pyrolysis residual mass curve 220 can be easily fitted to a first order reaction data model, as expected for pyrolysis reactions.

[0113] A combined feed including 30 wt% cellulose and 70 wt% mineral residue oil was then pyrolyzed using a TGA reactor. Figure 3 Results from the combined feed pyrolysis (based on the ERT display at 400°C) are shown (curve 330), along with a model prediction of an expected residual mass curve 340. The model prediction of the expected residual mass curve 340 is determined based on the assumption of no interaction between the biomass and mineral residue in the pyrolysis environment. This model prediction is formed using constants determined from model fits of separate cellulose and mineral residue pyrolysis runs. Figure 3 As shown, the measured pyrolysis residual mass curve 330 shows a significantly faster reaction than the reaction predicted by the (no interaction) model residual mass curve 340. The clear difference between these curves demonstrates the synergistic reaction between the solid biomass (cellulose in this run) and the mineral residue feed. The difference in reaction rate between the (no interaction) model residual mass curve 340 and the measured residual mass curve 330 indicates that the reaction rate has increased by about 2 times.

[0114] A second set of runs was performed using a similar procedure, but using pine chips (a complete form of biomass) instead of cellulose. First, the pine chips alone were pyrolyzed in a TGA reactor to allow determination of the constants used to make the model predictions. Figure 4 ) and 360℃( Figure 5 ) was carried out on a mixture of 50 wt% pine wood chips and 50 wt% mineral residue oil.

[0115] like Figure 4 As shown, pyrolysis of a mixed feed of pine wood chips and mineral residue at 530°C results in a significant increase in the reaction rate of the residue, as evidenced by the difference in the measured residual mass curve 430 relative to the (no interaction) model residual mass curve 440. Similar differences in the measured residual mass curve 530 and the (no interaction) model residual mass curve 540 are shown in FIG. Figure 5As shown. Based on the difference between the measured curve and the model curve, the co-processing of solid biomass and mineral residue under pyrolysis conditions increases the reaction rate by about 2 times relative to the expected value in the absence of interaction between the reaction mechanisms for co-feed pyrolysis. This is based on the unexpected synergy of the co-processing of biomass and mineral feed under fluid coking conditions.

[0116] Depend on Figure 3 , Figure 4 and Figure 5 The reaction rate benefits illustrated by the various residual mass curves in can be used in a variety of ways to improve the operation of a fluid coking reaction system. For example, the increased reaction rate can allow the temperature in the fluid coking reactor to be reduced while still maintaining a target conversion rate for the input feed. Reduced temperatures during fluid coking (or other pyrolysis) generally result in increased liquid product yields.

[0117] Example 3 - Improved and / or Modified Fluid Coking Based on Increased Reaction Rate

[0118] As demonstrated in Example 2, co-processing of biomass with a mineral feedstock results in an increased reaction rate of the mineral feedstock portion of the feed under fluid coking conditions. The increased reaction rate can have a variety of effects on the operation of the fluid coking system and / or the resulting product composition.

[0119] One improvement that can be achieved by increasing the reaction rate is to reduce the process severity within the coker reactor vessel while still achieving a target amount of HCCU during operation. Figure 6 The effect of increased reaction rate on HCCU is shown. Figure 6 The model is based on empirical data and can provide predictions of the yields of various products from fluid coking based on changes in the modeled process variables. Figure 6 In FIG. 1 , the vertical axis shows the amount of HCCU that exits the reactor and will therefore be passed to the heater of the three-vessel reaction system. The horizontal axis shows how increasing the reaction rate within the model (relative to the expected baseline value) improves the HCCU.

[0120] like Figure 6 As shown, increasing the reaction rate of the reactions within the fluid coking environment results in a reduction in HCCU. Based on the measurements in Example 2, it is calculated that co-processing of biomass can increase the reaction rate of the mineral portion of the feed by a factor of two. Figure 6 As shown, increasing the reaction rate by a factor of 2 will reduce the HCCU from an initial amount of 0.06 wt% (the expected reaction rate under the conditions described) to essentially no HCCU when the reaction rate is doubled.

[0121] based on Figure 6Co-processing of biomass can allow for a significant reduction in the amount of HCCU produced during fluid coking relative to the HCCU produced during processing of a separate mineral feed. Since fluid coking is typically limited by the need to maintain a target level of HCCU, co-processing of biomass can allow for a reduction in the severity of conditions in the fluid coking environment. For example, with a roughly constant residence time of the coke particles within the reactor vessel, a lower temperature can be used within the reactor while still achieving a target HCCU amount.

[0122] Figure 7 An example of the benefit of reducing the temperature in the coking reactor is shown. Figure 7 Model product yield results generated by a fluid coking process model are shown. Figure 7 , modeled product yield results for a resid feed are shown when the temperature in the fluid coking reactor is changed from 920°F (493°C) to 990°F (532°C). Based on the model, the difference in temperature between 493°C and 532°C roughly corresponds to the difference in operating temperatures that can be achieved in a fluid coking unit if the reaction rate for resid conversion is increased by a factor of two. In other words, the amount of HCCU produced at 532°C to process the feed used in the model at the expected reaction rate is similar to the amount of HCCU produced at 493°C when the reaction rate is doubled. Figure 7 As shown in the modeling results, reducing the temperature can reduce the yields of coke (751), light gas (753), and coker naphtha (755), while increasing the yields of light coker gas oil (757) and heavy coker gas oil (759). Therefore, the reduction in temperature achieved by the increase in reaction rate can provide a substantial shift in the properties of the product composition.

[0123] Figure 8 Modeling results are shown that demonstrate how changes in product composition will occur when comparing processing a residue feed alone to co-processing a residue feed with solid biomass under fluid coking conditions. Figure 8 In FIG. 1 , the estimated / modeled product yields for fluid coking of two types of feeds are shown. The first feed corresponds to a model mineral residue oil. The second feed corresponds to a blend of 75 wt % of the model mineral residue oil and 25 wt % of model biomass particles.

[0124] To simulate the results, use the Figure 7 The product yields for the residue portion of each feed were modeled in the same manner as the model yields shown in . For the biomass portion of the second feed, product yields were modeled based on typical published reported values ​​for fast pyrolysis of woody biomass at approximately 500°C.

[0125] exist Figure 8In the figure, the products produced by the model fluid coking process are classified as coke, light gas, coker naphtha (KN), light coker gas oil (LKGO) and heavy coker gas oil (HKGO). The products shown represent the products of processing 622 thousand pounds per hour of feed. The left-hand solid bar of each product corresponds to the model yield prediction of 100wt% residual oil feed exposed to fluid coking conditions at about 532°C. The right-hand solid bar of each product corresponds to the model prediction of fluid coking of the 75wt% residual oil portion of the second feed at a temperature of 493°C. For each product, the box formed by the dashed line above the right-hand solid bar represents the additional estimated product yield contribution from the fast pyrolysis of 25wt% biomass.

[0126] like Figure 8 As shown by the estimated yields in , by reducing the temperature and then adding back the estimated yields from the biomass portion of the feed, co-processing of 25 wt% biomass with a residual feed can produce a product profile with a reduced net yield of coke and light gases while providing a net increase in coker naphtha and coker heavy gas oil yields. It should be noted that Figure 8 The total liquid products shown correspond to approximately 40 wt% naphtha boiling range components, approximately 40 wt% heavy distillates boiling range components, and approximately 20 wt% light distillates boiling range components.

[0127] Example 4 - Additional Product Characterization

[0128] To further characterize the benefits of co-processing of biomass and mineral feeds, additional characterization was performed on liquid products produced by co-processing of mineral residue with 10 wt% biomass. For comparison, liquid products from fluid coking of mineral residue alone were also characterized. For the liquid products characterized in this example, fluid coking was performed at a reactor temperature of 400°C.

[0129] Several types of characterizations were performed on the total liquid products produced from the mineral feed and the combined feed containing portions of both biomass and the mineral feed. Fig. 9 The SIMDIS (ASTM D2887) boiling point curve of the resulting total liquid product is shown. Fig.10 Analysis of sulfur, MCR and n-heptane insolubles in the resulting total liquid product is shown. Fig.11 Fourier transform ion cyclotron resonance (FTICR-MS) analysis of each class of compounds present in the total liquid product is shown. Figure 12 shows two-dimensional gas chromatography (2D-GC) of the amounts of saturates, aromatics, and polar compounds present in the total liquid product.

[0130] Fig. 9The distillation curves of the resulting total liquid product are shown. Line 901 corresponds to the distillation curve of the co-processed product, while line 902 corresponds to the distillation curve of the processed mineral residue alone. Fig. 9 As shown, the total liquid product from co-processing 901 generally has a higher temperature distillation curve. It is believed that the higher temperature distillation curve reflects the unexpected chemical reactions that occur in the fluidized bed coking reactor when lignocellulosic biomass is co-processed. It should be noted that due to the difference in mineral feed type, Fig. 9 The distillation curve in is usually different from Figure 8 It should be further noted that the co-processing of biomass changes the ratio of naphtha boiling range components to light distillate boiling range components produced by the process. Fig. 9 The coker effluent from the coker treating a mineral residue feed has a weight ratio of naphtha boiling range compounds to light distillate boiling range compounds greater than 0.65 or greater than 0.70. In contrast, co-processing a cellulose-containing biomass with a mineral residue feed allows for the production of an effluent having a weight ratio of naphtha boiling range compounds to light distillate boiling range compounds of 0.65 or less, or 0.62 or less, or 0.60 or less, such as as low as 0.50 or possibly less.

[0131] Fig.10 The product analysis of the total liquid product is shown, which is related to the sulfur content, micro carbon residue (MCR) content and n-heptane insoluble content (in Fig.10 In the abbreviation C7 insoluble matter). Fig.10 As shown, there is a modest reduction in sulfur content between the co-processed product and the product of processing only the mineral feed. It should be noted that biomass has little or no sulfur content, so Fig.10 The lower sulfur content of the co-processed product may simply reflect the lower sulfur content of the combined biomass / residue feed prior to processing. However, there are additional synergistic effects for MCR and n-heptane insolubles. For the total liquid product of the co-process, simply blending with biomass to dilute the initial concentrations of MCR and n-heptane insolubles will result in a maximum reduction in MCR to slightly above 0.5 wt%, and a reduction in n-heptane insolubles to about 0.8 wt%. In contrast, Fig.10 As shown, the MCR content and n-heptane insoluble content of the co-processed liquid product have been reduced to about 0.2 wt % or less or 0.1 wt % or less. This is an unexpected improvement in product quality. It is believed that the catalytic interaction caused by the oxygen free radicals formed by the biomass reduces or minimizes the presence of coke precursors and / or other insolubles in the resulting total liquid product.

[0132] Fig.11Results of FTICR-MS analysis of three products are shown. One product corresponds to the total liquid products from fluid coking of a mineral feed alone. The second product corresponds to the products from co-processing a mineral feed with biomass. The third product corresponds to the FTICR-MS analysis of a representative pyrolysis oil formed by rapid pyrolysis of a biomass feed.

[0133] Due to the high resolution of the mass fragments in FTICR-MS, the number and type of atoms other than carbon and hydrogen present in the compounds within the sample can be specified in detail. Fig.11 As shown, the total liquid product from conventional residual oil is mainly composed of hydrocarbons (greater than 40wt%); compounds containing carbon, hydrogen and 1 sulfur atom (approximately 25-30wt%); and compounds containing carbon, hydrogen and 1 nitrogen atom (approximately 10-15wt%). Pyrolysis oil provides a significantly different curve, where the sample contains 5.0wt% or less hydrocarbons. In contrast, most of the compounds in the pyrolysis oil contain 4 oxygen atoms or more, with the weight of the single most common type of compound corresponding to the weight of compounds containing carbon, hydrogen and 12 oxygens. This indicates that typical pyrolysis oils correspond to large hydrocarbon-containing compounds with multiple oxygen-containing functional groups. Typically, more than 50wt% of the components in conventional pyrolysis oils include at least one oxygen atom.

[0134] Unexpectedly, the FTICR-MS analysis of the product from co-processing biomass and mineral residue feedstock is not similar to a certain blend of the product from processing a separate biomass or a separate mineral residue. The total co-processed liquid product does contain a large amount of hydrocarbons (15-20wt%) and compounds containing carbon, hydrogen and 1 sulfur (15-20wt%). However, compounds with a large amount of oxygen atoms do not exist or exist in the co-processed liquid product in a minimal amount. On the contrary, the co-processed liquid product contains a large amount of compounds consisting of carbon, hydrogen and 1 oxygen atom (about 10wt%). The content of compounds including carbon, hydrogen and 1 oxygen atom is about twice the content found in the mineral residue liquid product. It should be noted that pyrolysis oil is substantially free of compounds containing carbon, hydrogen and only 1 oxygen atom. Additionally, the co-processed liquid product contains about 5.0wt% of compounds consisting of carbon, hydrogen and 3 oxygen atoms. This is higher than the content of such compounds in the mineral residue liquid product or pyrolysis oil.

[0135] Based on the chromatographic characterization of the liquid products, it should be noted that the coking of the mineral feed results in a total liquid product containing approximately 0.25 wt% oxygen in total. In contrast, the pyrolysis oil contains approximately 45 wt% or oxygen because the pyrolysis oil contains relatively few components that do not contain at least one oxygen. However, the co-processing of the biomass with the mineral feed results in a total liquid product containing approximately 1.2 wt% oxygen. The total oxygen content of the total liquid product is increased relative to the pure mineral feed, but the oxygen content is unexpectedly reduced by a large amount relative to the expected oxygen content (4.7 wt%) based on a linear combination of mineral-based and biomass-based products produced independently under similar conditions.

[0136] The nature of the FTICR-MS results indicates that the total liquid product from the co-processing of biomass and mineral residue is not just an average of the products produced individually. On the contrary, the FTICR-MS results show that interactions occur during the reaction of biomass and mineral residue, resulting in the formation of components in the total liquid product of the co-processing that would not be formed by processing either type of feedstock individually.

[0137] Other embodiments

[0138] Embodiment 1. A method for co-processing biomass in a fluidized coking system, the method comprising: exposing a feed comprising 1.0 wt% to 60 wt% of biomass and 40 wt% to 99 wt% of a mineral fraction having a T10 distillation point of 500°C or higher to a fluidized bed of particles in a reactor vessel under fluidized coking conditions to form: i) a coker effluent, the coker effluent comprising a liquid portion, ii) char, coke, or a combination thereof, at least a portion of which is deposited on the particles to form particles comprising the deposited char, coke, or a combination thereof, and iii) additional hydrocarbons, the additional hydrocarbons being associated with the particles comprising the deposited char, coke, or a combination thereof; passing at least a portion of the particles comprising the deposited char, coke, or a combination thereof from the reactor vessel to a heater vessel, the at least a portion of which comprises a relative amount of hydrocarbons to the particles; 0.08 wt% or less of associated additional hydrocarbons based on the weight of the feed; mixing at least a portion of the particles containing deposited char, coke or a combination thereof with a portion of the partially gasified particles in the heater vessel to form a heated particle mixture; passing a first portion of the heated particle mixture into the reactor vessel; passing a second portion of the heated particle mixture into a gasification vessel; introducing an oxygen-containing stream and steam into the gasification vessel; exposing the second portion of the heated particle mixture to oxidizing conditions in the gasification vessel to form a gas phase product and partially gasified particles; and passing at least a portion of the partially gasified particles from the gasification vessel to the heater vessel, wherein the liquid portion of the coker effluent contains a micro-carbon residue content of 0.5 wt% or less, an n-heptane insoluble content of 0.5 wt% or less, or a combination thereof.

[0139] Embodiment 2. The method according to embodiment 1, wherein the liquid portion of the coker effluent comprises a micro carbon residue content of 0.4 wt% or less, an n-heptane insoluble content of 0.4 wt% or less, or a combination thereof.

[0140] Embodiment 3. A method according to any one of the above embodiments, wherein the oxidation conditions comprise partial oxidation conditions to form a gas-phase product comprising CO and CO2.

[0141] Embodiment 4. A method according to any one of the above embodiments, wherein the gas phase product further comprises H2.

[0142] Embodiment 5. The method according to any one of the above embodiments, further comprising passing the gas-phase product from the gasification vessel into the heater vessel, and discharging at least a portion of the gas-phase product from the heater vessel.

[0143] Embodiment 6. The method of any of the above embodiments, wherein the biomass comprises 20 wt% or more cellulose, or wherein the biomass comprises 30 wt% or less lignin, or a combination thereof.

[0144] Embodiment 7. The method according to any one of the above embodiments, wherein the feed comprises 10 wt% to 60 wt% biomass.

[0145] Embodiment 8. The method according to any one of the above embodiments, wherein the feed comprises 50 wt% to 60 wt% biomass, or wherein the feed comprises 20 wt% or less of components having a boiling point of 350°C or less, or a combination thereof.

[0146] Embodiment 9. The method of any of the above embodiments, wherein the oxidizing conditions comprise exposing the second portion of the particles to an oxygen-containing stream comprising 45% to 75% of a stoichiometric amount of oxygen to combust the char, coke, or a combination thereof.

[0147] Embodiment 10. The method according to any of the above embodiments, wherein the liquid portion of the coker effluent contains 0.9 wt% to 3.0 wt% oxygen.

[0148] Example 11. A liquid portion of a coker effluent formed according to the method described in any one of Examples 1 to 10, the liquid portion of the coker effluent comprising: 30 wt% to 50 wt% of naphtha boiling range components; 30 wt% to 50 wt% of heavy distillate boiling range components; 10 wt% to 25 wt% of light distillate boiling range components; and 5.0 wt% or less of vacuum residue boiling range components, the liquid portion comprising 0.9 wt% to 3.0 wt% of oxygen, the liquid portion further comprising a) 0.05 wt% to 0.5 wt% of micro-carbon residue content, b) 0.05 wt% to 0.5 wt% of n-heptane insolubles, or c) a combination of a) and b).

[0149] Embodiment 12. The liquid portion of the coker effluent according to embodiment 11, wherein the liquid portion comprises a micro-carbon residue content of 0.05 wt% to 0.4 wt%, or wherein the liquid portion comprises 0.05 wt% to 0.4 wt% n-heptane insolubles or a combination thereof.

[0150] Embodiment 13. The liquid portion of the coker effluent according to embodiment 11, wherein the liquid portion comprises a micro-carbon residue content of 0.05 wt% to 0.2 wt%, or wherein the liquid portion comprises 0.05 wt% to 0.2 wt% n-heptane insolubles or a combination thereof.

[0151] Embodiment 14. The liquid portion of the coker effluent according to any one of embodiments 11 to 13, wherein the liquid portion comprises 10 wt% to 40 wt% of an oxidized component, or wherein the liquid portion comprises 0.9 wt% to 2.5 wt% of oxygen, or a combination thereof.

[0152] Embodiment 15. The liquid portion of the coker effluent according to any one of embodiments 11 to 14, wherein the liquid portion comprises 1.0 wt% or less of vacuum residue boiling range components.

[0153] In another embodiment A, according to the method of any one of embodiments 1 to 10, the liquid portion of the coker effluent contains a weight ratio of naphtha boiling range components to light distillate boiling range components of 0.65 or less; or wherein the liquid portion of the coker effluent contains 30 wt% to 50 wt% naphtha boiling range components, 30 wt% to 50 wt% heavy distillate boiling range components, 10 wt% to 25 wt% light distillate boiling range components; and 5.0 wt% or less vacuum residue boiling range components.

[0154] When numerical lower limits and numerical upper limits are listed herein, the range from any lower limit to any upper limit is considered. Although the illustrative embodiments of the present invention have been specifically described, it should be understood that various other modifications will be apparent to those skilled in the art and can be easily made without departing from the spirit and scope of the present invention. Therefore, the scope of the appended claims is not intended to be limited to the examples and descriptions set forth herein, but the claims are interpreted as covering all features of patentable novelties present in the present invention, including all features that would be considered equivalents by a technician in the field to which the present invention belongs.

[0155] The present invention has been described above with reference to many embodiments and specific examples. Those skilled in the art will associate many variations based on the above detailed description. All such obvious variations are within the full contemplation of the appended claims.

Claims

1. A method for co-processing biomass in a fluidized coking system, the method comprising: exposing a feed comprising 1.0 wt% to 60 wt% of biomass and 40 wt% to 99 wt% of a mineral fraction having a T10 distillation point of 500°C or higher to a fluidized bed of particles in a reactor vessel under fluidized coking conditions to form: i) a coker effluent, the coker effluent comprising a liquid portion, ii) char, coke, or a combination thereof, at least a portion of which is deposited on the particles to form particles comprising the deposited char, coke, or a combination thereof, and iii) additional hydrocarbons, the additional hydrocarbons being in contact with the particles; associating the particles comprising deposited char, coke or a combination thereof; passing at least a portion of the particles comprising deposited char, coke or a combination thereof from the reactor vessel into a heater vessel, the at least a portion of the particles comprising deposited char, coke or a combination thereof comprising 0.08 wt % or less of associated additional hydrocarbons relative to the weight of the feed; mixing the at least a portion of the particles comprising deposited char, coke or a combination thereof with a portion of the partially gasified particles in the heater vessel to form a heated particle mixture; passing a first portion of the heated particle mixture into the reactor vessel; passing a second portion of the heated particle mixture into a gasification vessel; introducing an oxygen-containing stream and steam into the gasification vessel; exposing the second portion of the heated particle mixture to oxidizing conditions in the gasification vessel to form a gas phase product and partially gasified particles; and passing at least a portion of the partially gasified particles from the gasification vessel to the heater vessel, wherein the liquid portion of the coker effluent comprises a micro-carbon residue content of 0.5 wt% or less, an n-heptane insoluble content of 0.5 wt% or less, or a combination thereof.

2. The process of claim 1, wherein the liquid portion of the coker effluent comprises a micro carbon residue content of 0.4 wt% or less, an n-heptane insoluble content of 0.4 wt% or less, or a combination thereof.

3. The method of claim 1, wherein the oxidation conditions comprise partial oxidation conditions to form a gas-phase product comprising CO and CO2.

4. The method of claim 1, wherein the gas phase product further comprises H2.

5. The method of claim 1, further comprising passing the gaseous product from the gasification vessel into the heater vessel, and discharging at least a portion of the gaseous product from the heater vessel.

6. The method of claim 1, wherein the biomass comprises 20 wt% or more cellulose, or wherein the biomass comprises 30 wt% or less lignin, or a combination thereof.

7. The method of claim 1, wherein the feed comprises 10 wt% to 60 wt% biomass.

8. The method according to claim 1, wherein the feed comprises 20 wt% or less of a component having a boiling point of 350°C or less.

9. The method of claim 1, wherein the oxidizing conditions comprise exposing the second portion of particles to an oxygen-containing stream comprising 45% to 75% stoichiometric amount of oxygen to combust the char, coke, or a combination thereof.

10. The process of claim 1, wherein the liquid portion of the coker effluent comprises a weight ratio of naphtha boiling range components to light distillate boiling range components of 0.65 or less; or wherein the liquid portion of the coker effluent comprises 30 wt % to 50 wt % of naphtha boiling range components, 30 wt % to 50 wt % of heavy distillate boiling range components, 10 wt % to 25 wt % of light distillate boiling range components; and 5.0 wt % or less of vacuum residue boiling range components.

11. The process of claim 1 wherein the liquid portion of the coker effluent comprises 0.9 wt% to 3.0 wt% oxygen.

12. A liquid product comprising: 30 wt% to 50 wt% of naphtha boiling range components; 30 wt% to 50 wt% of heavy distillate boiling range components; 10 wt% to 25 wt% of light distillate boiling range components; and 5.0 wt% or less of vacuum residue boiling range components, the liquid product comprising 0.9 wt% to 3.0 wt% of oxygen, the liquid product further comprising a) a micro carbon residue content of 0.05 wt% to 0.5 wt%, b) 0.05 wt% to 0.5 wt% of n-heptane insolubles, or c) a combination of a) and b).

13. The liquid product according to claim 12, wherein the liquid product comprises a micro-carbon residue content of 0.05 wt% to 0.4 wt%.

14. The liquid product according to claim 12, wherein the liquid product comprises 0.05 wt% to 0.4 wt% of n-heptane insolubles.

15. The liquid product according to claim 12, wherein the liquid product comprises a micro-carbon residue content of 0.05 wt% to 0.2 wt%.

16. The liquid product according to claim 12, wherein the liquid product comprises 0.05 wt% to 0.2 wt% of n-heptane insolubles.

17. The liquid product of claim 12, wherein the liquid product comprises 10 wt% to 40 wt% of the oxygenated component.

18. The liquid product of claim 12, wherein the liquid product comprises 15 wt% to 30 wt% of the oxygenated component.

19. The liquid product according to claim 12, wherein the liquid product comprises 1.0 wt% or less of a vacuum residue boiling range component.

20. The liquid product of claim 12, wherein the liquid product comprises 0.9 wt% to 2.5 wt% oxygen.

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