7.2.2.1 Gasoline production

From synthesis gas, the FT process produces a wide range of hydrocarbon products:

$\left(2\mathit{n}+1\right){\mathrm{H}}_2+\mathit{n}\mathrm{CO}\to {\mathrm{C}}_{\mathit{n}}{\mathrm{H}}_{\left(2\mathit{n}+2\right)}+\mathit{n}{\mathrm{H}}_2\mathrm{O}$

The alkanes, or saturated hydrocarbons (C_nH_(2n + 2)), tend to be normal, or straight-chain isomers. The mean value of n is determined by catalyst, process conditions, and residence time, which are usually selected to maximize formation of alkanes in the range C₅ − C₂₁. −. The lower boiling fraction (C₅ − C₁₂), is separated as naphtha, which may be further refined into gasoline (which typically contains aromatic and branched hydrocarbon fractions).

High-temperature circulating fluidized-bed reactors (Synthol reactors) have been developed for gasoline and light olefin production, and these reactors operate at 350 °C (660 °F) and up to 400 psi. The combined gas feed (fresh and recycled) enters at the bottom of the reactor and entrains catalyst that is flowing down the standpipe and through the slide valve. The high gas velocity carries the entrained catalyst into the reaction zone where heat is removed through heat exchangers. Product gases and catalyst are then transported into a large-diameter catalyst hopper where the catalyst settles out and the product gases exit through a cyclone. These Synthol reactors have been successfully used for many years; however, they do have limitations: They are physically very complex reactors that involve circulation of large amounts of catalyst that leads to considerable erosion in particular regions of the reactor.

The higher boiling fraction (C₈ − C₂₁), being straight-chain hydrocarbons, is suitable for direct blending into the diesel fuel pool. Higher molecular weight alkanes (waxes) may also be formed but are usually undesirable. One inescapable aspect of Fischer-Tropsch chemistry is that more water will be produced than hydrocarbons (by mass). This produced water must be considered an undesirable sink for expensive and valuable hydrogen and also an unwanted waste stream.

The naphtha fraction, which is not generally marketable, must be shipped to a refinery for further processing into gasoline blending stock. It is advisable to have a commercial Fischer-Tropsch plant associated with a refinery complexes. In fact, the composition of the naphtha gasoline fraction [H(CH₂)_nH, where n = approximately 5 to 12] is an issue. The FT synthesis produces primarily straight-chain paraffins, thus any gasoline produced is low in octane rating (< 85).

The naphtha fraction contains components that are equivalent to the petroleum counterparts produced in a typical refinery. Alkylate, produced from reacting C₃, C₄, and C₅ olefins with isobutane, is the highest octane component in the gasoline. Isomerate is produced from isomerizing normal pentane and hexane. It has a moderate octane rating but is relatively volatile. The reformate, on the other hand, has a high octane rating but contains undesirable aromatic components. All of the gasoline-blending components have zero sulfur and olefins, which is of considerable benefit when manufacturing specification-grade and environmentally mandated fuels.

Modern automobile gasoline as sold to the consumer ranges in octane from 87 to 93, which is achieved by blending various petroleum streams distillates, reforming gasoline-range hydrocarbons, and ethanol or other additives increase the octane-number (Gary et al., 2007; Hsu & Robinson, 2006; Speight, 2014; Speight & Ozum, 2002). Branched paraffin series like iso-octane cannot be directly produced in Fischer-Tropsch synthesis. Consequently, when Fisher-Tropsch synthesis has been used to produce gasoline, it has been blended with conventionally refined petroleum to achieve the desired octane number.

On the other hand, the methanol-to-gasoline (MTG) process developed by Mobil Oil Corporation involves the conversion of methanol to hydrocarbons over zeolite catalysts and offers a better-quality naphtha-gasoline (Hindman, 2013).

Methanol synthesis also enjoys a long history, actually preceding the Fischer-Tropsch process. In 1923, BASF first synthesized methanol on an industrial scale, also from coal-produced synthesis gas:

${\mathrm{H}}_2+\mathrm{CO}–{\mathrm{CH}}_3\mathrm{OH}$

The methanol-to-gasoline process occurs in two steps. First, crude methanol (containing 17% v/v water) is super-heated to 300 °C (570 °F) and partially dehydrated over an alumina catalyst at 400 psi to yield an equilibrium mixture of methanol, dimethyl ether, and water (75% of the methanol is converted). Second, this effluent is then mixed with heated recycled synthesis gas and introduced into a reactor containing ZSM-5 zeolite catalyst at 350 to 365 °C (660 to 690 °F) and 280 to 340 psi to produce hydrocarbons (44%) and water (56%) (Spath & Dayton, 2003). The overall process usually contains multiple gasoline conversion reactors in parallel because the zeolites have to be regenerated frequently to burn off the coke formed during the reaction. The reactors are then cycled so that individual reactors can be regenerated without stopping the process (Kam, Schreiner, & Yurchak, 1984). The process reactions may be summarized simply as:

$2{\mathrm{CH}}_3\mathrm{OH}\to {\mathrm{CH}}_3{\mathrm{OCH}}_3+{\mathrm{H}}_2\mathrm{O}$

${\mathrm{CH}}_3{\mathrm{OCH}}_3\to {\mathrm{C}}_2-{\mathrm{C}}_5\mathrm{olefins}$

${\mathrm{C}}_2-{\mathrm{C}}_5\mathrm{olefins}\to \mathrm{paraffins},\mathrm{cycloparaffins},\mathrm{aromatics}$

The selectivity to gasoline range hydrocarbons is greater than 85%, with the remainder of the product being primarily low-boiling hydrocarbons (such as LPG constituents) (Wender, 1996). Approximately 40% of the gasoline produced from the process is aromatic hydrocarbons with the following distribution: 4% v/v benzene, 26% v/v toluene, 2% v/v ethylbenzene, 43% v/v mixed xylenes, 14% v/v trimethyl-substituted benzenes, plus 12% v/v other aromatics (Wender, 1996). The shape selectivity of the zeolite catalyst results in a relatively high durene (1,2,4,5-tetramethylbenzene) concentration, which is 3 to 5% of the gasoline produced (MacDougall, 1991).

7.2.2.2 Diesel production

The Fischer-Tropsch synthesis is well suited to producing middle-distillate range fuels such as diesel fuel and jet fuel. The diesel produced is superior to conventionally refined diesel in terms of higher cetane number and low sulfur content. Thus, the Fischer-Tropsch process is more amenable to the production of diesel fuel [H(CH₂)_nH, where n = approximately 7 to 24] and the various types of jet fuel [H(CH₂)_nH, where n = approximately 5 to 18].

Diesel produced from conventional upgrading of Fischer-Tropsch synthetic fuel consists of hydrotreated straight-run distillate blended with distillate from wax hydrocracking. Like the naphtha/gasoline, FT diesel has rather unique properties relative to petroleum-derived diesels: It it is sulfur free, almost completely paraffinic, and typically has an acceptable-to-high cetane rating.

The standard for diesel fuel rates the ease of which autoignition occurs during compression in the engine cylinder, thus eliminating the need for a spark plug. The number 100 was assigned to cetane (n-hexadecane, C₁₆H₃₄) to represent a straight-chain hydrocarbon in the paraffin series. This is the hydrocarbon type and molecular weight that the Fischer-Tropsch synthesis is best suited to produce. Diesel fuel cetane numbers range from 40 to 45, and as high as 55 in Europe, where high-speed diesel engines are prevalent in light-duty passenger vehicles.

Recent efforts to improve the Fischer-Tropsch process tend to focus on increasing selectivity for the diesel fraction and minimizing the naphtha fraction. With certain modifications and modest post-processing, the Fischer-Tropsch process can currently claim selectivity for the diesel fraction with the distribution of the hydrocarbon fraction as diesel (kerosene) 75% v/v, naphtha (gasoline) 20% v/v, and LPG 5% v/v (Lewis, 2013).

7.4.1.1 Conversion to liquids

After recovery, the bitumen is transported to a limited scope refinery that typically involves application of one of two coking processes that have been applied to the production of liquids from Athabasca bitumen. Delayed coking is practiced at the Suncor (formerly Great Canadian Oil Sands) plant, whereas Syncrude employs a fluid coking process that produces less coke than the delayed coking in exchange for more liquids and gases. In each case, the bitumen is converted to distillate, coke, and low-boiling gases. The coke fraction and product gases can be used for plant fuel. The distillate (raw synthetic crude oil, raw syncrude) is a partially upgraded material and is a suitable feed for hydrodesulfurization to produce a low-sulfur synthetic crude oil as a saleable product.

7.4.1.2 Upgrading tar sand liquids

Sulfur is distributed throughout the boiling range of the delayed coker distillate, as with distillates from direct coking. Nitrogen is more heavily concentrated in the higher boiling fractions but is present in most of the distillate fractions. Raw coker naphtha contains significant quantities of olefins and di-olefins that must be saturated by downstream hydrotreating. The gas oil has a high aromatic content typical of coker gas oils.

Catalytic hydrotreating is used for secondary upgrading to remove impurities and enhance the quality of the final synthetic crude oil product. In a typical catalytic hydrotreating unit, the feedstock is mixed with hydrogen, preheated in a fired heater and then charged under high pressure to a fixed-bed catalytic reactor. Hydrotreating converts sulfur and nitrogen compounds present in the feedstock to hydrogen sulfide and ammonia. Sour gases from the hydrotreater(s) are treated for use as plant fuel. A further option is that hydrocracking may also be employed at this stage to improve product yields and quality.

Thus, the primary liquid product (synthetic crude oil) is, of necessity, hydrotreated (secondary upgrading) to remove sulfur and nitrogen (as hydrogen sulphide and ammonia, respectively) and to hydrogenate the unsaturated sites exposed by the conversion process. It may be necessary to employ separate hydrotreaters for the lower-, medium-, and high-boiling distillates. For example, the higher-boiling distillates fractions require higher hydrogen partial pressures and higher operating temperatures to achieve the desired degree of sulfur and nitrogen removal. Commercial applications have therefore been based on the separate treatment of two or three distillate fractions at the appropriate severity to achieve the required product quality and process efficiency.

The synthetic crude oil is a blend of naphtha, middles distillate, and gas oil range materials, with no residuum (1050 °F +, 565 °C + material). Canadian synthetic crude oil first became available in 1967 when Suncor started to market a blend produced by hydrotreating the naphtha, distillate, and gas oil generated in a delayed coking unit. The light, sweet synthetic crude currently marketed by Suncor is called Suncor oil sands blend A (OSA). Syncrude Canada Ltd. started production in 1978, marketing a fully hydrotreated blend utilizing fluidized-bed coking technology as the primary upgrading step. This product is referred to as Syncrude sweet blend (SSB).

7.4.2.1 Conversion to liquids

The production of liquid fuels from coal is not new. It has received considerable attention because the concept does represent alternate pathways to liquid fuels (Speight, 2008, and references cited therein). In fact, the concept is often cited as a viable option for alleviating projected shortages of liquid fuels as well as offering some measure of energy independence for those countries with vast resources of coal who are also net importers of crude oil.

There are inherent technological advantages with the conversion of coal to liquid products because coal liquefaction can produce clean liquid fuels that can be sold as transportation fuels such as gasoline and diesel. The three principal routes by which liquid fuels can be produced from solid coal are (1) direct conversion to liquids by thermal cracking, (2) hydrocracking the coal, and (3) indirect conversion to liquids using the Fischer-Tropsch technology. The third route involves gasification of coal to mixtures of carbon monoxide and hydrogen (synthesis gas) followed by application of the Fischer-Tropsch process in which the syngas is converted to hydrocarbons under catalytic conditions of temperature and pressure. This section will focus on the conversion of coal to liquids by direct liquefaction technologies.

The direct liquefaction of coal by the Bergius process (liquefaction by hydrogenation) is also available. In the process, coal is finely ground and mixed with heavy oil recycled from the process. Catalyst is typically added to the mixture and the mixture is pumped into a reactor. The reaction occurs at between 400 to 500 °C and 20 to 70 MPa hydrogen pressure. The reaction produces heavy oil, middle oil, gasoline, and gas:

$\mathit{n}{\mathrm{C}}_{\mathrm{coal}}+\left(\mathit{n}+1\right){\mathrm{H}}_2\to \mathrm{C}\mathit{n}{\mathrm{H}}_{2\mathit{n}+2}$

A number of catalysts have been developed over the years, including catalysts containing tungsten, molybdenum, tin, or nickel.

Another process to manufacture liquid hydrocarbons from coal is low-temperature carbonization (LTC) (referred to as the Karrick process). Coal is coked at temperatures between 450 and 700 °C (840 and 1290 °F) compared to 800 to 1000 °C (1830 °F) for metallurgical coke. The lower temperatures optimize the production of coal tar that is richer in lighter hydrocarbons than high-temperature coal tar. The coal tar is then further processed into fuels. Several other direct liquefaction processes have been developed over the last four decades with varying degrees of success (Speight, 2013a).

The thermal decomposition of coal on a commercial scale is often more commonly referred to as carbonization and is more usually achieved by the use of temperatures up to 1500 °C (2730 °F). The degradation of the coal is quite severe at these temperatures and produces (in addition to the desired coke) substantial amounts of gaseous products. However, carbonization is essentially a process for the production of a carbonaceous residue by thermal decomposition (with simultaneous removal of distillate) of organic substances.

${\left[\mathit{C}\right]}_{\mathrm{organic}\mathrm{carbon}}\to {\left[\mathit{C}\right]}_{\mathrm{coke}/\mathrm{char}/\mathrm{carbon}}+\mathrm{liquids}+\mathrm{gases}$

The process is a complex sequence of events that can be described in terms of several important physicochemical changes, such as the tendency of the coal to soften and flow when heated (plastic properties or the relationship to carbon-type in the coal). In fact, some coals become quite fluid at temperatures on the order of 400 to 500 °C (750 to 930 °F), and there is a considerable variation in the degree of the temperature of maximum plasticity, as well as the plasticity temperature range for various types of coal. The yields of tar and low molecular weight liquids are, to some extent, variable but are greatly dependent on the process parameters, especially temperature, as well as the type of coal.

7.4.2.2 Upgrading coal liquids

Liquid products from coal are generally different from those produced by petroleum refining, particularly as they can contain substantial amounts of phenols. In fact and in spite of the interest in coal liquefaction processes that emerged during the 1970s and the 1980s, petroleum prices always remained sufficiently low to ensure that the initiation of a synthetic fuels industry based on non-petroleum sources would not become a commercial reality.

The different fractions are not suitable for immediate use as a fuel but must be sent to a refinery for further processing to yield a synthetic fuel or a fuel blending stock of the desired quality. It has been reported that as much as 97% of the coal carbon can be converted to synthetic fuel, but this greatly depends on the coal type, the reactor configuration, and the process parameters.

Typically, the liquids need to be hydrotreated, and the manner by which hydrogenation can occur varies from process to process and may even occur as part of the process by the use of a hydrogen atmosphere and a solvent capable of donating hydrogen to the system and the type of catalyst employed (Speight, 2013a, 2014). Nevertheless, in the more general sense, at some stage of the operation, the liquid products need to be stabilized (i.e., freed from unsaturated materials as well as nitrogen, oxygen, and sulfur species) by what may be simply referred to as a hydrotreating operation.

For the most part, current concepts for refining the products of coal liquefaction processes rely on the already existing petroleum refineries, although it must be recognized that the acidity (i.e., phenol content) of the coal liquids and the potential incompatibility of the coal liquids with conventional petroleum (or even heavy oil) feedstocks may pose severe problems within the refinery system. Thus, the first essential step in refining coal liquids is severe catalytic hydrogenation to remove most of the nitrogen, sulfur, and oxygen and to convert at least part of the high-boiling material to lower-boiling distillates that might be further refined. This is analogous to the hydrodesulfurization of heavy oils using a preliminary cracking technique so that after product separation (by distillation) the most suitable choice of process conditions can be made (Ancheyta & Speight, 2007; Speight, 2000).

However, a major limiting factor in refining coal liquids is due to the high aromatics content and to the condensed nature of many of the aromatic ring systems (Speight, 2013a). Thus, to produce liquid fuels of the types currently in demand, each condensed aromatic ring would have to be hydrogenated (saturated) and cracked to produce the lower-boiling distillate material. The hydrogen demand for such conversions and the effect of these polynuclear aromatic systems (especially those which contain nitrogen and other heteroatoms) systems on catalysts is a very worthy hurdle to overcome! Nevertheless, it is a hurdle that can be surpassed, and by a variety of process conditions.

7.4.3.1 Conversion to liquids

Retorting at high temperature (approximately 500 °C, 930 °F) is the process of heating oil shale in order to recover the organic material, predominantly as a liquid (shale oil). A retort is simply a vessel (a rock formation for in situ retorting or a manufacture reactor of surface retorting) in which the oil shale is heated so that the product gases and vapors can escape to a collector.

Retorting involves the destructive distillation (pyrolysis) of oil shale in the absence of oxygen. At temperatures above 500 °C, 930 °F, pyrolisis thermally decomposes or breaks down (cracks) the kerogen (the organic constituent of oil shale) to release the hydrocarbons and then cracks the hydrocarbons into lower-weight hydrocarbon molecules.

The active devolatilization of oil shale begins at about 350 to 400 °C, with the peak rate of oil evolution at about 425 °C, and with devolatilization essentially complete in the range of 470 to 500 °C (Speight, 2008). At temperatures of approximately 500 °C (930 °F), mineral matter, consisting mainly of calcium, magnesium and calcium carbonates, begins to decompose, yielding carbon dioxide as the principal product. The properties of crude shale oil are dependent on the retorting temperature, but more importantly on the temperature-time history because of the secondary reactions accompanying the evolution of the liquid and gaseous products. The produced shale oil is dark brown, is odoriferous, and tends toward waxy oil.

Oil derived from shale has been referred to as a synthetic crude oil and thus is closely associated with synthetic fuel production. However, the process of retorting shale oil bears more similarities to conventional refining processes, such as the delayed coking process, than to synthetic fuel processes. For the purpose of this chapter, the term oil-shale distillate is used to refer to middle-distillate range hydrocarbons produced by retorting oil shale. Disposal of spent shale is also a problem that must be solved in economic fashion for the large-scale development of oil shale to proceed. Retorted shale contains carbon as a kind of char, representing more than half of the original carbon values in the shale. The char is potentially pyrophoric and can burn if dumped into the open air while hot. The heating process results in a solid that occupies more volume than the fresh shale because of the problems of packing random particles.

A preferred method for thermally treating oil shale involves using a moving bed reactor followed by a fractionation step to divide the wide boiling-range crude oil produced from the shale oil into two separate fractions. The lighter fraction is hydrotreated for the removal of residual metals, sulfur, and nitrogen, whereas the heavier fraction is cracked in a second fixed bed reactor normally operated under high-severity conditions.

Also, the fluidized-bed hydroretort process eliminates the retorting stage of conventional shale upgrading, by directly subjecting crushed oil shale to a hydroretorting treatment in an upflow fluidized-bed reactor, such as that used for the hydrocracking of heavy petroleum residues. This process is a single-stage retorting and upgrading process. Therefore, the process involves (1) crushing oil shale; (2) mixing the crushed oil shale with a hydrocarbon liquid to provide a pumpable slurry; (3) introducing the slurry along with a hydrogen-containing gas into an upflow, fluidized-bed reactor at a superficial fluid velocity sufficient to move the mixture upwardly through the reactor; (4) hydroretorting the oil shale; (5) removing the reaction mixture from the reactor; and (6) separating the reactor effluent into several components.

7.4.3.2 Upgrading refining shale oil

Shale retorting processes produce oil with almost no heavy residual (high-boiling) fraction. With upgrading, shale oil is a light boiling premium product more valuable than most crude oils. However, the properties of shale oil vary as a function of the production (retorting) process. Fine mineral matter carried over from the retorting process and the high viscosity and instability of shale oil produced by present retorting processes have necessitated upgrading of the shale oil before transport to a refinery.

Shale oil contains a wide variety of hydrocarbon compounds, but it also has high nitrogen content compared to a nitrogen content of 0.2 to 0.3 wt. % for a typical petroleum. In addition, shale oil also has a high olefin and di-olefin content. It is the presence of these olefins and diolefins, in conjunction with high nitrogen content, that gives shale oil the characteristic difficulty in refining and the tendency to form insoluble sediment. Crude shale oil also contains appreciable amounts of arsenic, iron, and nickel that interfere with refining.

To improve the qualities of crude shale oil, upgrading, or partial refining, may be carried out using different options, after removal of the inorganic fines. Hydrotreating is the option of choice to produce a stable product that is comparable to benchmark crude oils. In terms of refining and catalyst activity, the nitrogen content of shale oil is a disadvantage. But, in terms of the use of shale oil residue as a modifier for asphalt, the nitrogen content is beneficial, as nitrogen species can enhance binding with the inorganic aggregate. If not removed, the arsenic and iron in shale oil would poison and foul the supported catalysts used in hydrotreating.

Blending refined shale oil products with corresponding crude oil products, and using shale oil fractions obtained from a very mildly hydrogen treated shale oil, yields kerosene and diesel fuel of satisfactory properties. Hydroprocessing shale oil products, either alone or in a blend with the corresponding crude oil fractions, is therefore necessary. The severity of the hydroprocessing has to be adjusted according to the particular properties of the feed and the required level of the stability of the product.

Gasoline from shale oil usually contains a high percentage of aromatic and naphthenic compounds that are not affected by the various treatment processes. The olefin content, although reduced in most cases by refining processes, will still remain significant. It is assumed that di-olefins and the higher unsaturated constituents will be removed from the gasoline product by appropriate treatment processes. The same should be true, although to a lesser extent, for nitrogen- and sulfur-containing constituents.

The sulfur content of raw shale oil gasoline may be rather high due to the high sulfur content of the shale oil itself and the frequently even distribution of the sulfur compounds in the various shale oil fractions. Not only the concentration but also the type of the sulfur compounds are important when studying the effect on gum formation tendency of the gasoline containing them.

Catalytic hydrodesulfurization processes are not a good solution for the removal of sulfur constituents from gasoline when high proportions of unsaturated constituents are present. A significant amount of the hydrogen would be used for hydrogenation of the unsaturated components. However, when hydrogenation of the unsaturated hydrocarbons is desirable, catalytic hydrogenation processes would be effective.

The naphtha fraction (the gasoline precursor fraction) derived from shale oil contains varying amounts of oxygen compounds. The presence of oxygen in a product, in which free radicals form easily, is a cause for concern. Free hydroxyl radicals are generated and the polymerization chain reaction is quickly brought to its propagation stage. Unless effective means are provided for the termination of the polymerization process, the propagation stage may well lead to an uncontrollable generation of oxygen bearing free radicals leading to gum and other polymeric products.

Diesel fuel derived from oil shale is also subject to the degree of unsaturation, the effect of di-olefins, the effect of aromatics, and the effect of nitrogen and sulfur compounds. In addition, jet fuel produced from shale oil would have to be subjected to suitable refining treatments and special processes. The resulting product must be identical in its properties to corresponding products obtained from conventional crude oil. This can be achieved by subjecting the shale oil product to a severe catalytic hydrogenation process with a subsequent addition of additives to ensure resistance to oxidation.

Thus, like coal liquids, shale oil is different to conventional crude oils, and several refining technologies have been developed to deal with this. The primary problems identified in the past were arsenic, nitrogen, and the waxy nature of the raw synthetic crude oil. Nitrogen and wax problems were solved using hydroprocessing approaches, essentially classical hydrocracking and the production of high-quality lube stocks, which require that waxy materials be removed or isomerized. However, the arsenic problem remains.

In general, oil-shale distillates have a much higher concentration of high boiling-point compounds that would favor production of middle-distillates (such as diesel and jet fuels) rather than naphtha. Oil-shale distillates also have a higher content of olefins, oxygen, and nitrogen than crude oil, as well as higher pour points and viscosities. Above-ground retorting processes tended to yield a lower API gravity oil than the in situ processes (a 25° API gravity was the highest produced). Additional processing equivalent to hydrocracking would be required to convert oil-shale distillates to a lighter range hydrocarbon (gasoline). Removal of sulfur and nitrogen would, however, require hydrotreating.

Arsenic removed from the shale oil by hydrotreating remains on the catalyst, generating a material that is a carcinogen, an acute poison, and a chronic poison. The catalyst must be removed and replaced when its capacity to hold arsenic is reached.

7.4.4.1 Conversion to liquids

Biomass (other than by fermentation to alcohol fuels) is typically converted to liquids by fast pyrolysis – a process in which organic materials are rapidly heated to 450 to 600 °C (840 to 1110 °F) in the absence of air. Under these conditions, organic vapors, pyrolysis gases, and charcoal are produced – the vapors are condensed to bio-oil. Depending on the biomass feedstock, a 50 to 70% w/w yield of liquid can be expected. However, fast pyrolysis is a non-equilibrium process and bio-oil properties are a function of temperature, pressure, residence time, reactor configuration, and quench method.

In fast pyrolysis, biomass decomposes quickly to generate mostly vapors and aerosols and some charcoal and gas. After cooling and condensation, a dark brown homogeneous mobile liquid is formed that has a heating value about half that of conventional fuel oil. In a particular example, biomass particles are fed near the bottom of the fluidized-bed reactor (analogous to a fluid-bed catalytic cracking unit (Speight, 2008, 2011b, 2014) together with an excess flow of hot heat carrier material such as sand. The pyrolysis reactor is integrated in a circulating sand system composed of a riser, a fluidized-bed char combustor, the pyrolysis reactor, and a down-comer. The bio-oil is treated (typically in a cyclone) to remove particulate matter before entering the condenser, in which the volatile products are quenched by recirculated bio-oil. Any char that is produced is burned with air to provide the heat required for the pyrolysis process, and non-condensable pyrolysis gases are combusted to generate additional steam as well as heat for drying the biomass feedstock.

However, due to the presence of oxygenated constituents, bio-oil is polar and does not mix readily with hydrocarbons. The degradation products from the biomass constituents include organic acids – such as formic acid (HCO₂H) and acetic acid (CH₃CO₂H) – that give the oil a low pH and hydrophilic character. Typically, hydrophilic bio-oils have water content on the order of 15 to 35% w/w, and phase separation does occur when the water content is higher than about 30 to 45% w/w.

7.4.4.2 Upgrading bio-oil

The high acidity and chemical instability of bio-oils impose severe limitations on the extent to which they might be processed in a refinery. One way to address this is by treating the bio-oil with a low-cost alcohol (e.g., methanol, ethanol, or butanol) in the presence of an acid catalyst, converting the carboxyl and carbonyl groups to esters and acetals or ketals, respectively. As esterification and acetylation reactions are equilibrium reactions, increasing concentrations of esters, acetals, and water will tend to shift equilibrium back toward the original reactants. A solution to this problem is to remove the reaction products as they are formed by azeotropic water removal or reactive distillation (Moens, Black, Myers, & Czernik, 2009).

Pyrolysis oils from biomass pyrolysis are free-flowing liquids, usually dark brown in color, often with an odor of smoke. Liquid yields and properties depend on biomass type, temperature, hot vapor residence time, char separation, and mineral matter content of the biomass feedstock. The last two factors have a catalytic effect on vapor cracking (Bertero, de la Puente, & Sedran, 2012; Bridgwater, 2012; Lédé et al., 2007; Zheng & Wei, 2011).

However, high oxygen content, storage instability, particulate matter, and corrosiveness contribute to downstream upgrading difficulties for bio-oil. In fact, the most important properties affecting bio-oil fuel quality are incompatibility with conventional fuels from the high oxygen content of the bio-oil, high solids content, high viscosity, and chemical instability. Mitigating these effects involves understanding or achieving (1) reduced oxygen content; (2) effective particulate matter removal; (3) sulfur, nitrogen, and other contaminant species distribution among the gas, liquid, and char; and (4) reduction of corrosion potential. Furthermore, bio-oils can be emulsified with conventional fuel with the aid of surfactants. The main drawback of this approach is the cost of surfactants, the high energy required for emulsion and the significantly higher levels of corrosion/erosion in engine applications (Baglioni et al., 2003).

Hydrotreating removes oxygen as well as nitrogen and sulfur. It can also saturate olefins and aromatics, and will completely deoxygenate phenolic constituents depending on the severity of the operation. In fact, upgrading fast pyrolysis oil to stable hydrocarbon oil occurs in two steps. The first reactor step uses mild hydrotreating conditions to remove some of the oxygen and prevent secondary reactions (such as polymerization) that lead to catalyst deactivation. The second reactor operates at greater severity than the first; it uses higher temperatures and/or lower space velocities to achieve low levels of oxygen (< 1% w/w).

The process is typically high pressure and moderate temperature (up to 400 °C, 750 °F) and produces a naphtha-like product that requires orthodox refining to derive conventional transport fuel. Typical catalysts are sulfided CoMo or NiMo supported on alumina or aluminosilicates. Ketones and aldehydes can be hydrogenated to alcohols under mild conditions over Raney nickel catalyst. In the presence of the reduced Mo-10 Ni/γ-alumina,hydrotreatment as well as the esterification have happened in the bio-oil during the upgrading process. The optimal conditions for hydroprocessing of bio-oil are quite different from those for petroleum-derived products. A two-step hydroprocessing scheme comprising a mild stabilization step and a more intensive upgrading step are necessary.

Catalytic cracking accomplishes deoxygenating through simultaneous dehydration, decarboxylation, and decarbonylation reactions occurring in the presence of zeolite catalysts. Bio-oils are generally best upgraded by HZSM-5 or ZSM-5, as these zeolite catalysts promote high yields of liquid products and propylene (Alonso, Bond, & Dumesic, 2010). There is also an increasing interest in improving the quality of bio-oils by integrated catalytic pyrolysis – pyrolysis of biomass in the presence of ZSM-5 to produce naphtha and kerosene, heating oil, and renewable chemicals, including benzene, toluene, and xylenes, has been claimed (Williams & Nugranad, 2000).