Gasification and synthetic liquid fuel production
an overview
R. Luque1; J.G. Speight2 1 University of Córdoba, Córdoba, Spain
2 CD&W Inc., Laramie, WY, USA
Abstract
This chapter discusses general considerations on gasification processes and synthetic liquid fuel production. It provides an overview of state-of-the-art gasification technologies, feedstocks and applications in power generation, and synthetic fuels production, together with some recent future trends in the field.
1.1 Introduction
Gasification is a process that converts organic (carbonaceous) feedstocks into carbon monoxide, carbon dioxide, and hydrogen by reacting the feedstock at high temperatures (> 700 °C, 1290 °F), without combustion, with a controlled amount of oxygen and/or steam (Lee, Speight, & Loyalka, 2007; Speight, 2008, 2013). The resulting gas mixture (synthesis gas, or syngas) is itself a fuel. The power derived from carbonaceous feedstocks and gasification, followed by the combustion of the product gas(es), is considered to be a source of renewable energy if derived gaseous products are generated from a source (e.g., biomass) other than a fossil fuel (Speight, 2008).
The advantage of gasification is that the use of synthesis gas (syngas) is potentially more efficient as compared to direct combustion of the original fuel because it can be (1) combusted at higher temperatures, (2) used in fuel cells, (3) used to produce methanol and hydrogen, and (4) converted via the Fischer–Tropsch (FT) process into a range of synthesis liquid fuels suitable for use in gasoline engines or diesel engines. The gasification process can also utilize carbonaceous feedstocks that would otherwise have been discarded (e.g., biodegradable waste).
In addition, the high-temperature process causes corrosive ash elements, including metal chlorides and potassium salts, that allow clean gas production from otherwise problematic fuels.
Coal has been the primary feedstock for gasification units for many decades. However, due to the concern of environmental pollutants and the potential shortage of coal in some areas (except the United States), there is a movement to use materials other than coal feedstocks for gasification processes. Nevertheless, coal still prevails and will continue to prevail for at least several decades into the future, if not well into the next century (Speight, 2013).
Coal gasification plants are cleaner with respect to standard pulverized coal combustion facilities, producing fewer sulfur and nitrogen by-products, which contribute to smog and acid rain. For this reason, gasification is an appealing way to utilize relatively inexpensive and expansive coal reserves, while reducing the environmental impact. Indeed, the increasing mounting interest in coal gasification technology reflects a convergence of two changes in the electricity-generation marketplace: (1) the maturity of gasification technology and (2) the extremely low emissions from integrated gasification combined cycle (IGCC) plants, especially air emissions, and the potential for lower cost control of greenhouse gases than other coal-based systems. Fluctuations in the costs associated with natural gas-based power, which is viewed as a major competitor to coal-based power, can also play a role.
Furthermore, gasification permits the utilization of various feedstocks (coal, biomass, petroleum residues, and other carbonaceous wastes) to their fullest potential. Thus, power developers would be well advised to consider gasification as a means of converting coal to gas.
Liquid fuels, including gasoline, diesel, naphtha, and jet fuel, are usually processed via the refining of crude oil (Speight, 2014). Due to the direct distillation, crude oil is the best-suited raw material for liquid fuel production. However, with fluctuating and rising prices of petroleum, coal-to-liquids and biomass-to-liquids processes are starting to be considered as alternative routes for liquid fuels production. Both feedstocks are converted to syngas (a mixture of carbon monoxide and hydrogen), which is subsequently converted into a mixture of liquid products by FT processes. The liquid fuel obtained after FT synthesis is eventually upgraded using known petroleum refinery technologies to produce gasoline, naphtha, diesel fuel, and jet fuel (Chadeesingh, 2011; Dry, 1976; Speight, 2014).
1.2 Gasification processes
Gasification processes are segregated according to bed types, which differ in their ability to accept (and use) caking coals. They are generally divided into four categories based on reactor (bed) configuration: (1) fixed bed, (2) fluidized bed, (3) entrained bed, and (4) molten salt.
In a fixed-bed process, the coal is supported by a grate. Combustion gases (steam, air, oxygen, etc.) pass through the supported coal where the produced hot gases then exit from the top of the reactor. Heat is supplied internally or from an outside source, but caking coals cannot be used in an unmodified fixed-bed reactor.
The fluidized-bed system uses finely sized coal particles and the bed exhibits liquid-like characteristics when a gas flows upward through the bed. Gas flowing through the coal produces turbulent lifting and separation of particles, which results in an expanded bed having a greater coal surface area to promote the chemical reaction. However, such systems have a limited ability to handle caking coals.
An entrained-bed system uses finely sized coal particles blown into the gas steam prior to entry into the reactor, and combustion occurs with the coal particles suspended in the gas phase. The entrained system is suitable for both caking and noncaking coals.
The fourth and final category of the gasification process is the molten salt system. It employs a bath of molten salt to convert coal (Cover, Schreiner, & Skaperdas, 1973; Howard-Smith & Werner, 1976; Speight, 2013, and references cited therein).
The aim of underground (or in situ) gasification of coal is the conversion into combustible gases by combustion of a coal seam in the presence of air and oxygen, or oxygen and steam. Thus, seams that were once considered to be inaccessible, unworkable, or uneconomical to mine could be put to use. In addition, strip mining and the accompanying environmental impacts – the problems of spoil banks, acid mine drainage, and the problems associated with use of high-ash coal – are minimized or even eliminated.
The principles of underground gasification are very similar to those involved in the above-ground gasification of coal. The concept involves the drilling and subsequent linking of two boreholes so that gas will pass between the two (King & Magee, 1979). Combustion is then initiated at the bottom of one borehole (injection well) and is maintained by the continuous injection of air. In the initial reaction zone (combustion zone), carbon dioxide is generated by the reaction of oxygen (air) with the coal:
The carbon dioxide reacts with coal (partially devolatilized) further along the seam (reduction zone) to produce carbon monoxide:
In addition, at the high temperatures that can frequently occur, moisture injected with oxygen or even moisture inherent in the seam may also react with the coal to produce carbon monoxide and hydrogen:
The gas product varies in character and composition but usually falls into the low-heat (low Btu) category ranging from 125 to 175 Btu/ft3 (King & Magee, 1979).
1.3 Gasification feedstocks
Gasification processes can accept a variety of feedstocks but the reactor must be selected on the basis of feedstock properties and behavior in the process.
1.3.1 Coal
Coal is a fossil fuel formed in swamp ecosystems where plant remains were saved from oxidization and biodegradation by water and mud. Coal is a combustible organic sedimentary rock (composed primarily of carbon, hydrogen, and oxygen, as well as other minor elements including sulfur) formed from ancient vegetation and consolidated between other rock strata to form coal seams. The harder forms can be regarded as organic metamorphic rocks (e.g., anthracite coal) because of a higher degree of maturation.
Coal is the largest single source of fuel for generating electricity worldwide, as well as the largest source of carbon dioxide emissions, which have been implicated as the primary cause of global warming. Coal is found as successive layers, or seams, sandwiched between strata of sandstone and shale and extracted from the ground by coal mining – either underground coal seams (underground mining) or by open-pit mining (surface mining).
There is an adequate supply of coal; at current rates of recovery and consumption, the world global coal reserves have been variously estimated to have a reserves/production ratio of at least 155 years. However, as with all estimates of resource longevity, coal longevity is subject to the assumed rate of consumption remaining at the current rate of consumption and, moreover, to technological developments that dictate the rate at which the coal can be mined. But most importantly, coal is a fossil fuel and an unclean energy source that will only add to global warming. In fact, the next time electricity is advertised as a clean energy source, consider the means by which the majority of electricity is produced – almost 50% of the electricity generated in the United States derives from coal (EIA, 2007; Speight, 2013).
There are different forms or types of coal (Speight, 2013). Variations in the nature of the source material, as well as local or regional variations in the coalification processes cause the vegetal matter to evolve differently. Various classification systems thus exist to define the different types of coal. The coal precursors are transformed over time (as geological processes increase their effect over time) into:
1. Lignite – Also referred to as brown coal, this is the lowest rank of coal and used almost exclusively as fuel for steam-electric power generation. Jet is a compact form of lignite that is sometimes polished and has been used as an ornamental stone since the Iron Age.
2. Sub-bituminous coal – The properties of this type of coal range from those of lignite to those of bituminous coal and is used primarily as fuel for steam-electric power generation.
3. Bituminous coal – This dense coal, usually black but sometimes dark brown, often with well-defined bands of brittle and dull material, is used primarily as fuel in steam-electric power generation, with substantial quantities also used for heat and power applications in manufacturing and to make coke.
4. Anthracite – This harder, glossy, black coal is used primarily for residential and commercial space heating; it is the highest-ranking coal.
Chemically, coal is a hydrogen-deficient hydrocarbon with an atomic hydrogen-to-carbon ratio near 0.8, as compared to petroleum hydrocarbons, which have an atomic hydrogen-to-carbon ratio approximately equal to two, and methane (CH4) that has an atomic carbon-to-hydrogen ratio equal to four. For this reason, any process used to convert coal to alternative fuels must add hydrogen or redistribute the hydrogen in the original coal to generate hydrogen-rich products and coke (Speight, 2013).
The chemical composition of the coal is defined in terms of its proximate and ultimate (elemental) analyses (Speight, 2013). The parameters of proximate analysis are moisture, volatile matter, ash, and fixed carbon. Elemental or ultimate analysis encompasses the quantitative determination of carbon, hydrogen, nitrogen, sulfur, and oxygen within the coal. Additionally, specific physical and mechanical properties of coal and particular carbonization properties are also determined.
Carbon monoxide and hydrogen are produced by the gasification of coal in which a mixture of gases is produced. In addition to carbon monoxide and hydrogen, methane and other hydrocarbons are also produced depending on conditions. Gasification may be accomplished either in situ or in processing plants. In situ gasification is accomplished by controlled, incomplete burning of a coal bed underground while adding air and steam. The gases are withdrawn and may be burned to produce heat and generate electricity, or are utilized as syngas in indirect liquefaction as well as for the production of chemicals.
Producing diesel and other fuels from coal can be performed through the conversion of coal to syngas, a combination of carbon monoxide, hydrogen, carbon dioxide, and methane. Syngas is subsequently reacted through FT synthesis processes to produce hydrocarbons that can be refined into liquid fuels. By increasing the quantity of high-quality fuels from coal (while reducing costs), research into this process could help mitigate the dependence on ever-increasingly expensive and depleting stocks of petroleum.
Although coal is an abundant natural resource, its combustion or gasification produces both toxic pollutants and greenhouse gases. By developing adsorbents to capture the pollutants (mercury, sulfur, arsenic, and other harmful gases), scientists are striving not only to reduce the quantity of emitted gases but also to maximize the thermal efficiency of the clean-up.
Gasification thus offers one of the most clean and versatile ways to convert the energy contained in coal into electricity, hydrogen, and other sources of power. Turning coal into syngas isn’t a new concept; in fact, the basic technology dates back to World War II.
1.3.2 Biomass
Biomass can be considered as any renewable feedstock that, in principle, is carbon neutral. (While the plant is growing, it uses the sun’s energy to absorb the same amount of carbon from the atmosphere as it releases into the atmosphere.)
Raw materials that can be used to produce biomass-derived fuels are widely available; they come from a large number of different sources and in numerous forms (Rajvanshi, 1986). The basic sources of biomass include (1) wood, including bark, logs, sawdust, wood chips, wood pellets, and briquettes; (2) high-yield energy crops, such as wheat, grown specifically for energy applications; (3) agricultural crops and residues (e.g., straw); and (4) industrial waste, such as wood pulp or paper pulp. For processing, a simple form of biomass, such as untreated and unfinished wood, may be converted into a number of physical forms, including pellets and wood chips, for use in biomass boilers and stoves.
Biomass includes a wide range of materials that produce a variety of products that are dependent on the feedstock (Balat, 2011; Demirbaş, 2011; Ramroop Singh, 2011; Speight, 2011a). In addition, the heat content of the different types of biomass widely varies and has to be taken into consideration when designing any conversion process (Jenkins & Ebeling, 1985).
Thermal conversion processes use heat as the dominant mechanism to convert biomass into another chemical form. The basic alternatives of combustion – torrefaction, pyrolysis, and gasification – are separated principally by the extent to which the chemical reactions involved are allowed to proceed (mainly controlled by the availability of oxygen and conversion temperature) (Speight, 2011a).
Energy created by burning biomass (fuelwood), also known as dendrothermal energy, is particularly suited for countries where fuelwood grows more rapidly (e.g., tropical countries). A number of other less common, more experimental or proprietary thermal processes may offer benefits, including hydrothermal upgrading and hydroprocessing. Some have been developed to be compatible with high-moisture content biomass (e.g., aqueous slurries) and allow them to be converted into more convenient forms.
Some of the applications of thermal conversion are combined heat and power and cofiring. In a typical dedicated biomass power plant, efficiencies range from 7% to 27%. In contrast, biomass cofiring with coal typically occurs at efficiencies close to those of coal combustors (30–40%) (Baxter, 2005; Liu, Larson, Williams, Kreutz, & Guo, 2011).
Many forms of biomass contain a high percentage of moisture (along with carbohydrates and sugars) and mineral constituents, both of which can influence the economics and viability of a gasification process. The presence of high levels of moisture in biomass reduces the temperature inside the gasifier, which then reduces the efficiency of the gasifier. Many biomass gasification technologies therefore require dried biomass to reduce the moisture content prior to feeding into the gasifier. In addition, biomass can come in a range of sizes. In many biomass gasification systems, biomass must be processed to a uniform size or shape to be fed into the gasifier at a consistent rate as well as to maximize gasification efficiency.
Biomass such as wood pellets, yard and crop waste, and “energy crops,” including switchgrass and waste from pulp and paper mills, can also be employed to produce bioethanol and synthetic diesel. Biomass is first gasified to produce syngas and then subsequently converted via catalytic processes to the aforementioned downstream products. Biomass can also be used to produce electricity – either blended with traditional feedstocks, such as coal, or by itself.
Most biomass gasification systems use air instead of oxygen for gasification reactions (which is typically used in large-scale industrial and power gasification plants). Gasifiers that use oxygen require an air separation unit (ASU) to provide the gaseous/liquid oxygen; this is usually not cost-effective at the smaller scales used in biomass gasification plants. Air-blown gasifiers utilize oxygen from air for gasification processes.
In general, biomass gasification plants are comparatively smaller than those of typical coal or petroleum coke plants used in the power, chemical, fertilizer, and refining industries. As such, they are less expensive to build and have a smaller environmental footprint. Whereas a large industrial gasification plant may take up 150 acres of land and process 2500–15,000 tons per day of feedstock (e.g., coal or petroleum coke), smaller biomass plants typically process 25–200 tons of feedstock per day and take up less than 10 acres.
Finally, although biomass may seem to some observers to be the answer to the global climate change issue, advantages and disadvantages of biomass as feedstock must be considered carefully:
Advantages: (1) theoretically inexhaustible fuel source; (2) minimal environmental impact when direct combustion of plant mass is not used to generate energy (i.e., fermentation, pyrolysis, etc., are used instead); (3) alcohols and other fuels produced by biomass are efficient, viable, and relatively clean-burning; and (4) available on a worldwide basis.
Disadvantages: (1) could contribute a great deal to global climate change and particulate pollution if combusted directly; (2) remains an expensive source of energy, both in terms of producing biomass and the technological conversion to alcohols or other fuels; and (3) life cycle assessments should be taken into account to address energy inputs and outputs but there is most likely a net loss of energy when operated on a small scale (as energy must be put in to grow the plant mass).
Also, while taking the issues of global climate change into account, it must be remembered that the Earth is in an interglacial period when warming will take place. The extent of this warming is not known – no one was around to measure the temperature change in the last interglacial period – and by the same token the contribution of anthropological sources to global climate change cannot be measure accurately.
1.3.3 Petroleum residues
Gasification is the only technology that makes possible a zero residue target for refineries. All other conversion technologies (including thermal cracking, catalytic cracking, cooking, deasphalting, hydroprocessing, etc.) can only reduce the bottom volume, with the complication that the residue qualities generally get worse with the degree of conversion (Speight, 2014).
The flexibility of gasification allows the handling of any type of refinery residue, including petroleum coke, tank bottoms, and refinery sludge. Gasification makes available a range of value-added products, including electricity, steam, hydrogen, and various chemicals based on syngas chemistry: methanol, ammonia, MTBE, TAME, acetic acid, and formaldehyde (Speight, 2008; Chapter 7). The environmental performance of gasification is unmatched. No other technology processing low-value refinery residues can come close to the emission levels achievable with gasification (Speight, 2014).
Gasification is also a method for converting petroleum coke and other refinery nonvolatile waste streams (often referred to as refinery residuals and include but are not limited to atmospheric residuum, vacuum residuum, visbreaker tar, and deasphalter pitch) into power, steam, and hydrogen for use in the production of cleaner transportation fuels. The main requirement for a gasification feedstock (including coal and biomass) is that it contains both hydrogen and carbon (Table 1.1).
Table 1.1
Types of refinery feedstocks available for gasification on-site
| Ultimate analysis | Units | Vacuum Residue | Visbreaker tar | Asphalt | Petcoke |
| C | w/w | 84.9% | 86.1% | 85.1% | 88.6% |
| H | w/w | 10.4% | 10.4% | 9.1% | 2.8% |
| Na | w/w | 0.5% | 0.6% | 0.7% | 1.1% |
| Sa | w/w | 4.2% | 2.4% | 5.1% | 7.3% |
| O | w/w | 0.5% | 0.0% | ||
| Ash | w/w | 0.0% | 0.1% | 0.2% | |
| Total | w/w | 100.0% | 100.0% | 100.0% | 100.0% |
| H2/C ratio | mol/mol | 0.727 | 0.720 | 0.640 | 0.188 |
| Density | |||||
| specific | 60°/60° | 1.028 | 1.008 | 1.070 | 0.863 |
| API gravity | °API | 6.2 | 8.88 | 0.8 | – |
| Heating values | |||||
| HHV (dry) | M Btu/lb | 17.72 | 18.6 | 17.28 | 14.85 |
| LHV (dry) | M Btu/lb | 16.77 | 17.6 | 16.45 | 14.48 |
Source: National Energy Technology Laboratory, United States Department of Energy, Washington, DC.
a Nitrogen and sulfur contents vary widely.
The typical gasification system incorporated into a refinery consists of several process units, including feed preparation, the gasifier itself, an ASU, syngas clean-up, sulfur recovery unit (SRU), and downstream process options depending on target products. Figure 1.1 shows a typical arrangement of these process units in addition to the optional downstream processes for producing power through cogeneration, hydrogen, FT, or methanol synthesis.
The benefits of the addition of a gasification system in a refinery to process petroleum coke or other residuals include (1) production of power, steam, oxygen, and nitrogen for refinery use or sale; (2) the source of syngas for hydrogen to be used in refinery operations as well as for the production of light refinery products through FT synthesis; (3) increased efficiency of power generation, improved air emissions, and reduced waste stream versus combustion of petroleum coke or residues or incineration; (4) no off-site transportation or storage for petroleum coke or residuals; and (5) the potential to dispose of waste streams including hazardous materials.
Gasification can provide high-purity hydrogen for a variety of uses within the refinery (Speight, 2014). Hydrogen is used in refineries to remove sulfur, nitrogen, and other impurities from intermediate to finished product streams and in hydrocracking operations for the conversion of heavy distillates and oils into light products, naphtha, kerosene, and diesel fuel. Hydrocracking and severe hydrotreating require hydrogen that is at least 99% (v/v), whereas less severe hydrotreating can work with gas streams containing 90% (v/v) pure hydrogen.
Electric power and high-pressure steam can be generated via gasification of petroleum coke and residuals to drive mostly small and intermittent loads such as compressors, blowers, and pumps. Steam can also be used for process heating, steam tracing, partial pressure reduction in fractionation systems, and stripping low-boiling components to stabilize process streams.
Carbon soot is produced during gasification, which ends up in the quench water. The soot is transferred to the feedstock by contacting, in sequence, the quench water blowdown with naphtha, and then the naphtha-soot slurry with a fraction of the feed. The soot mixed with the feed is finally recycled into the gasifier, thus achieving 100% conversion of carbon to gas.
1.3.4 Black liquor
Black liquor is the spent liquor from the Kraft process in which pulpwood is converted into paper pulp by removing lignin and hemicellulose constituents as well as other extractable materials from wood to free the cellulose fibers. The equivalent spent cooking liquor in the sulfite process is usually called brown liquor, but the terms red liquor, thick liquor, and sulfite liquor are also used. Approximately seven units of black liquor are produced in the manufacture of one unit of pulp (Biermann, 1993).
Black liquor is comprised of an aqueous solution of lignin residues, hemicellulose, the inorganic chemical used in the process, and 15% (w/w) solids of which 10% (w/w) are inorganic and 5% (w/w) are organic. Typically, the organic constituents in black liquor are 40–45% (w/w) soaps, 35–45% (w/w) lignin, and 10–15% (w/w) other (miscellaneous) organic materials.
The organic constituents in the black liquor are made up of water/alkali soluble degradation components from the wood. Lignin is partially degraded to shorter fragments with sulfur contents of about 1–2% (w/w) and sodium content at approximately 6% (w/w) of the dry solids. Cellulose (and hemicellulose) is degraded to aliphatic carboxylic acid soaps and hemicellulose fragments. The extractable constituents yield tall oil soap and crude turpentine. The tall oil soap may contain up to 20% (w/w) sodium. Residual lignin components currently serve hydrolytic or pyrolytic conversion or combustion. Alternatively, hemicellulose constituents may also be used in fermentation processes.
Gasification of black liquor has the potential to achieve higher overall energy efficiency, as compared to those of conventional recovery boilers, while generating an energy-rich syngas. The syngas can then be burned in a gas turbine combined cycle system (BLGCC – black liquor gasification combined cycle – similar to IGCC) to produce electricity, or the syngas can be converted through catalytic processes into chemicals or fuels, such as methanol, dimethyl ether, FT hydrocarbons, and diesel fuel.
1.4 Gasification for power generation
1.4.1 General aspects
The gasification of coal, biomass, petroleum, or any carbonaceous residues is generally aimed at feedstock conversion to gaseous products. In fact, gasification offers one of the most versatile methods (with a reduced environmental impact with respect to combustion) to convert carbonaceous feedstocks into electricity, hydrogen, and other valuable energy products.
Depending on the previously described type of gasifier (e.g., air-blown, enriched oxygen-blown) and the operating conditions, gasification can be used to produce a fuel gas that is suitable for several applications.
Gasification for generating electric power enables the use of a common technology in modern gas-fired power plants (combined cycle) to recover more of the energy released by burning the fuel. The use of these two types of turbines in the combined cycle system involves (1) a combustion turbine and (2) a steam turbine. The increased efficiency of the combined cycle for electrical power generation results in a 50% (v/v) decrease in carbon dioxide emissions compared to conventional coal plants. Gasification units could be modified to further reduce their climate-change impact, because a large part of the carbon dioxide generated can be separated from the other product gas before combustion. For example, carbon dioxide can be separated or sequestered from gaseous by-products by using absorbents (e.g., MOFs) to prevent its release to the atmosphere.
Gasification has also been considered for many years as an alternative to combustion of solid or liquid fuels. Compared to solid or high-viscosity liquid fuels, gaseous mixtures are simpler to clean. Cleaned gases can be used in internal combustion-based power plants that would suffer from severe fouling or corrosion if solid or low-quality liquid fuels were burned inside them.
In fact, the hot syngas produced by gasification of carbonaceous feedstocks can then be processed to remove sulfur compounds, mercury, and particulate matter, prior to its use as fuel in a combustion turbine generator to produce electricity. The heat in the exhaust gases from the combustion turbine is recovered to generate additional steam. This steam, along with the steam produced by the gasification process, drives a steam turbine generator to produce additional electricity. In the past decade, the primary application of gasification to power production has become more common due to the demand for high efficiency and low environmental impact.
As anticipated, the quality of the gas generated in a system is influenced by feedstock characteristics and gasifier configuration, as well as the amount of air, oxygen, or steam introduced into the system. The output and quality of the gas produced is determined by the equilibrium established when the heat of oxidation (combustion) balances the heat of vaporization and volatilization plus the sensible heat (temperature rise) of the exhaust gases. The quality of the outlet gas (Btu/ft3) is determined by the amount of volatile gases, such as hydrogen, carbon monoxide, water, carbon dioxide, and methane, in the gas stream. With some feedstocks, the higher the amounts of volatile produced in the early stages of the process, the higher the heat content of the product gas. In some cases, the highest gas quality may be produced at lower temperatures. However, char oxidation reaction is suppressed when the temperature is too low, and the overall heat content of the product gas is diminished.
Gasification agents are normally air, oxygen-enriched air, or oxygen. Steam is sometimes added to control for temperature, to enhance heating value, or to allow the use of external heat (allothermal gasification). The major chemical reactions break and oxidize hydrocarbons to produce a product gas containing carbon monoxide, carbon dioxide, hydrogen, and water. Other important components include hydrogen sulfide, various compounds of sulfur and carbon, ammonia, light hydrocarbons, and heavy hydrocarbons (tars).
Depending on the employed gasifier technology and operating conditions, significant quantities of water, carbon dioxide, and methane can be present in the product gas, as well as a number of minor and trace components. Under reducing conditions in the gasifier, most of the feedstock sulfur converts to hydrogen sulfide (H2S), but 3–10% converts to carbonyl sulfide. Organically bound nitrogen in the coal feedstock is generally converted to gaseous nitrogen (N2), but some ammonia (NH3) and a small amount of hydrogen cyanide (HCN) are also formed. Any chlorine in the coal is converted to hydrogen chloride (HCl), with some chlorine present in the particulate matter (fly ash). Trace elements, such as mercury and arsenic, are released during gasification and partition among the different phases (e.g., fly ash, bottom ash, slag, and product gas).
1.4.2 Cogasification of coal with biomass and waste
Pyrolysis and gasification of fossil fuels, biomass materials, and waste have been used for many years to convert organic solids and liquids into useful gaseous, liquid, and cleaner solid fuels (Brar, Singh, Wang, & Kumar, 2012; Speight, 2011a).
1.4.2.1 Biomass
Coal gasification is an established technology (Hotchkiss, 2003; Ishi, 1982; Speight, 2013). Comparatively, biomass gasification has been the focus of research in recent years for the purpose of estimating efficiency and performance of the gasification process using various types of biomass such as sugarcane residue (Gabra, Pettersson, Backman, & Kjellström, 2001), rice hulls (Boateng, Walawender, Fan, & Chee, 1992), pine sawdust (Lv et al., 2004), almond shells (Rapagnà, Kiennemann, & Foscolo, 2000; Rapagnà & Latif, 1997), wheat straw (Ergudenler & Ghaly, 1993), food waste (Ko, Lee, Kim, Lee, & Chun, 2001), and wood biomass (Bhattacharya, Siddique, & Pham, 1999; Chen, Sjöström, & Bjornbom, 1992; Hanaoka, Inoue, Uno, Ogi, & Minowa, 2005; Pakdel & Roy, 1991). Recently, cogasification of various biomass and coal mixtures has attracted a great deal of interest from the scientific community. Feedstock combinations, including Japanese cedar wood and coal (Kumabe, Hanaoka, Fujimoto, Minowa, & Sakanishi, 2007), coal and saw dust (Vélez, Chejne, Valdés, Emery, & Londoño, 2009), coal and pine chips (Pan, Velo, Roca, Manyà, & Puigjaner, 2000), coal and silver birch wood (Collot, Zhuo, Dugwell, & Kandiyoti, 1999), and coal and birch wood (Brage, Yu, Chen, & Sjöström, 2000) have been reported in gasification practices. Cogasification of coal and biomass has some synergy – the process not only produces a low carbon footprint on the environment, but it also improves the H2/CO ratio in the produced gas, which is required for liquid fuel synthesis (Kumabe et al., 2007; Sjöström, Chen, Yu, Brage, & Rosén, 1999). In addition, the inorganic matter present in biomass catalyzes the gasification of coal. However, cogasification processes require custom fittings and optimized processes for the coal and region-specific wood residues.
Although cogasification of coal and biomass is advantageous from a chemical viewpoint, some practical problems are present on upstream, gasification, and downstream processes. On the upstream side, the particle size of the coal and biomass is required to be uniform for optimum gasification. In addition, moisture content and pretreatment (torrefaction) are very important during upstream processing.
Upstream processing is influential from a material handling point of view, but the choice of gasifier operation parameters (temperature, gasifying agent, and catalysts) dictate the product gas composition and quality. Biomass decomposition occurs at a lower temperature than coal, and therefore different reactors compatible to the feedstock mixture are required (Brar et al., 2012). Furthermore, feedstock and gasifier type, along with operating parameters, not only decide product gas composition but also dictate the amount of impurities to be handled downstream.
Downstream processes need to be modified if coal is cogasified with biomass. Heavy metal and impurities, such as sulfur and mercury, present in coal can make syngas difficult to use and unhealthy for the environment. Alkali present in biomass can also cause corrosion problems and high temperatures in downstream pipes. An alternative option to downstream gas cleaning would be to process coal to remove mercury and sulfur prior to its feeding into the gasifier.
However, first and foremost, coal and biomass require drying and size reduction before they can be fed into a gasifier. Size reduction is needed to obtain appropriate particle sizes; however, drying is required to achieve moisture content suitable for gasification operations. In addition, biomass densification may be conducted to prepare pellets and improve density and material flow in the feeder areas.
It is recommended that biomass moisture content should be less than 15% (w/w) prior to gasification. High-moisture content reduces the temperature achieved in the gasification zone, thus resulting in incomplete gasification. Forest residues or wood has a fiber saturation point at 30–31% moisture content (dry basis) (Brar et al., 2012). Compressive and shear strength of the wood increases with decreased moisture content below the fiber saturation point. In such a situation, water is removed from the cell wall leading to its shrinkage. The long-chain molecule constituents of the cell wall move closer to each other and bind more tightly. A high level of moisture, usually injected in the form of steam in the gasification zone, favors formation of a water-gas shift reaction that increases hydrogen concentration in the resulting gas.
The torrefaction process is a thermal treatment of biomass in the absence of oxygen, usually at 250–300 °C to drive off moisture, decompose hemicellulose completely, and partially decompose cellulose (Speight, 2011a). Torrefied biomass has reactive and unstable cellulose molecules with broken hydrogen bonds. Not only does it retain 79–95% of feedstock energy, but it also produces a more reactive feedstock with lower atomic hydrogen–carbon and oxygen–carbon ratios compared to the original biomass. Torrefaction results in higher yields of hydrogen and carbon monoxide in the gasification process.
Finally, the presence of mineral matter in the coal-biomass feedstock is not appropriate for fluidized-bed gasification. The low melting point of ash present in woody biomass leads to agglomeration that causes defluidization of the ash, sintering, and deposition, as well as corrosion of the gasifier construction metal bed (Vélez et al., 2009). Biomass containing alkali oxides and salts are likely to produce clinkering/slagging problems from ash formation (McKendry, 2002). Thus, it is imperative to be aware of the melting of biomass ash, its chemistry within the gasification bed (no bed, silica/sand, or calcium bed), and the fate of alkali metals when using fluidized-bed gasifiers.
Most small to medium-sized biomass/waste gasifiers are air blown, operate at atmospheric pressure, and range in temperatures from 800 to 100 °C (1470–2190 °F). They face very different challenges from large gasification plants – such as the use of small-scale air separation plant should oxygen gasification be preferred or application of pressurized operation, which eases gas cleaning, may not be practical.
Biomass fuel producers, coal producers, and, to a lesser extent, waste companies are enthusiastic about supplying cogasification power plants and realize the benefits of cogasification with alternate fuels (Lee & Shah, 2013; Speight, 2008, 2011a, 2013). The benefits of a cogasification technology involving coal and biomass include the use of a reliable coal supply with gate-fee waste and biomass, which allows the economies of scale from a larger plant to be supplied just with waste and biomass. In addition, the technology offers a future option of hydrogen production and fuel development in refineries. In fact, oil refineries and petrochemical plants are opportunities for gasifiers when the hydrogen is particularly valuable (Speight, 2011b, 2014).
1.4.2.2 Waste
Waste may be municipal solid waste which had minimal presorting, or refuse-derived fuel with significant pretreatment, usually mechanical screening and shredding. Other more specific waste sources (excluding hazardous waste) and possibly including petroleum coke, may provide niche opportunities for coutilization.
The traditional waste-to-energy plant, based on mass-burn combustion on an inclined grate, has a low public acceptability despite the very low emissions achieved over the last decade with modern flue gas clean-up equipment. This has led to difficulty in obtaining planning permissions to construct much-needed new waste-to-energy plants. After a great deal of debate, various governments have allowed options for advanced waste conversion technologies (gasification, pyrolysis, and anaerobic digestion), but will give credit only to the proportion of electricity generated from nonfossil waste.
Coutilization of waste and biomass with coal may provide economies of scale that help achieve the identified policy objectives at an affordable cost. In some countries, governments propose cogasification processes as being well suited for community-sized developments, suggesting that waste should be dealt with in smaller plants serving towns and cities, rather than moved to large, central plants, thus satisfying the so-called proximity principal.
In fact, neither biomass nor wastes are currently produced or naturally gathered at sites in sufficient quantities to fuel a modern large and efficient power plant. Disruption, transport issues, fuel use, and public opinion all act against gathering hundreds of megawatts (MWe) at a single location. Biomass or waste-fired power plants are therefore inherently limited in size and hence in efficiency (labor costs per unit electricity produced) and in other economies of scale. The production rates of municipal refuse follow reasonably predictable patterns over time periods of a few years. Recent experience with the very limited current biomass-for-energy harvesting has shown unpredictable variations in harvesting capability with long periods of zero production over large areas during wet weather.
The situation is very different for coal. Coal is generally mined or imported, and thus large quantities are available from a single source or a number of closely located sources, and supply has been reliable and predictable. However, the economics of new coal-fired power plants of any technology or size have not encouraged any new coal-fired power plant in the gas-generation market.
The potential unreliability of biomass, longer-term changes in refuse, and the size limitation of a power plant using only waste and/or biomass can be overcome by combining biomass, refuse, and coal. Users would benefit from a premium electricity price for electricity from biomass and the gate fee associated with waste. If the power plant is gasification-based, rather than direct-combustion-based, further benefits may be available. These include a premium price for the electricity from waste, a range of technologies available for the gas-to-electricity part of the process, gas cleaning prior to the main combustion stage instead of after combustion, and an improved public image, which is currently generally better for gasification as compared to combustion. These considerations lead to current studies of cogasification of wastes/biomass with coal (Speight, 2008).
For large-scale power generation (> 50 MWe), the gasification field is dominated by plants based on the pressurized, oxygen-blown, entrained flow or fixed-bed gasification of fossil fuels. Entrained gasifier operational experience to date has largely been with well-controlled fuel feedstocks with short-term trial work at low cogasification ratios and with easily handled fuels.
Use of waste materials as cogasification feedstocks may attract significant disposal credits. Cleaner biomass materials are renewable fuels and may attract premium prices for the electricity generated. Availability of sufficient fuel locally for an economic plant size is often a major issue, as is the reliability of the fuel supply. Use of more predictably available coal alongside these fuels overcomes some of these difficulties and risks. Coal could be regarded as the “flywheel” that keeps the plant running when the fuels producing the better revenue streams are not available in sufficient quantities.
Coal characteristics are very different in younger hydrocarbon fuels such as biomass and waste. Hydrogen-to-carbon ratios are higher for younger fuels, as is the oxygen content. This means that reactivity is also quite different under gasification conditions. Gas-cleaning issues can also be dissimilar, given that sulfur is a major concern for coal gasification and chlorine compounds and tars are more important for waste and biomass gasification. There are no current proposals for adjacent gasifiers and gas-cleaning systems, one handling biomass or waste and one handling coal, alongside each other and feeding the same power production equipment. However, there are some advantages to such a design, as compared with mixing fuels in the same gasifier and gas-cleaning systems.
Electricity production or combined electricity and heat production remain the most likely area for the application of gasification or cogasification. The lowest investment cost per unit of electricity generated is the use of the gas in an existing large power station. This has been done in several large utility boilers, often with the gas fired alongside the main fuel. This option allows a comparatively small thermal output of gas to be used with the same efficiency as the main fuel in the boiler as a large, efficient steam turbine can be used. It is anticipated that addition of gas from a biomass or wood gasifier into the natural gas feed to a gas turbine could be technically possible, but there will be concerns as to the balance of commercial risks to a large power plant and the benefits of using the gas from the gasifier. The use of fuel cells with gasifiers is frequently discussed but the current cost of fuel cells is such that their use for mainstream electricity generation is uneconomic.
Furthermore, the disposal of municipal and industrial waste has become an important problem because the traditional means of disposal – landfill – are much less environmentally acceptable than previously. Much stricter regulation of these disposal methods will make the economics of waste processing for resource recovery much more favorable.
One method of processing waste streams is to convert the energy value of the combustible waste into a fuel. One type of fuel attainable from waste is a low-heating value gas, usually 100–150 Btus per standard cubic foot (scf), which can be used to generate process steam or to generate electricity (Gay, Barclay, Grantham, & Yosim, 1980). Coprocessing such waste with coal is also an option (Speight, 2008).
In summary, coal may be cogasified with waste or biomass for environmental, technical, or commercial reasons. It allows larger, more efficient plants than those sized for grown biomass or arising waste within a reasonable transport distance; specific operating costs are likely to be lower and fuel supply security is assured.
Cogasification technology varies, usually being site specific and dependent on high feedstock. At the largest scale, the plant may include the well-proven fixed-bed and entrained flow gasification processes. At smaller scales, emphasis is placed on technologies that appear closest to commercial operation. Pyrolysis and other advanced thermal conversion processes are included where power generation is practical using the on-site feedstock produced. However, the needs to be addressed are (1) core fuel handling and gasification/pyrolysis technologies, (2) fuel gas clean-up, and (3) conversion of fuel gas to electric power (Ricketts, Hotchkiss, Livingston, & Hall, 2002).
1.5 Gasification for synthetic fuel production
The gasification of coal or a derivative (i.e., char produced from coal) is the conversion of coal (by any one of a variety of processes) to produce gaseous products that are combustible as well as a wide range of chemical products (Figure 1.2). With the rapid increase in the use of coal from the fifteenth century onward (Nef, 1957; Taylor & Singer, 1957), it is not surprising that the concept of using coal to produce a flammable gas, especially the use of the water and hot coal (Van Heek & Muhlen, 1991), became commonplace (Elton, 1958).
In fact, the production of gas from coal has been a vastly expanding area of coal technology, leading to numerous research and development programs. As a result, the characteristics of rank, mineral matter, particle size, and reaction conditions are all recognized as having a bearing on the outcome of the process – not only in terms of gas yields but also gas properties (Massey, 1974; Van Heek & Muhlen, 1991). The products from the gasification of coal may be of low-, medium-, or high-heat content (high Btu) as dictated by the process as well as by the ultimate use for the gas (Figure 1.2) (Anderson & Tillman, 1979; Argonne National Laboratory, 1990; Baker & Rodriguez, 1990; Bodle & Huebler, 1981; Cavagnaro, 1980; Fryer & Speight, 1976; Lahaye & Ehrburger, 1991; Mahajan & Walker, 1978; Matsukata, Kikuchi, & Morita, 1992; Probstein & Hicks, 1990; Speight, 2013, and references cited therein).
1.5.1 Gaseous products
The products of gasification are different insofar as the gas composition varies with the system employed (Speight, 2013). It is emphasized that the gas product must first be freed from any pollutants such as particulate matter and sulfur compounds before further use, particularly when the intended use is a water–gas shift or methanation (Cusumano, Dalla Betta, & Levy, 1978; Probstein & Hicks, 1990).
1.5.1.1 Synthesis gas
Synthesis gas (syngas) is a mixture mainly of hydrogen and carbon monoxide that is comparable in its combustion efficiency to natural gas (Speight, 2008; Chapter 7). This reduces the emissions of sulfur, nitrogen oxides, and mercury, resulting in a much cleaner fuel (Lee et al., 2007; Nordstrand, Duong, & Miller, 2008; Sondreal, Benson, & Pavlish, 2006; Sondreal, Benson, Pavlish, & Ralston, 2004; Wang et al., 2008; Yang, Xua, Fan, Bland, & Judkins, 2007). The resulting hydrogen gas can be used for electricity generation or as a transport fuel. The gasification process also facilitates capture of carbon dioxide emissions from the combustion effluent. (A discussion about carbon capture and storage will be presented later.)
Although syngas can be used as a stand-alone fuel, its energy density is approximately half that of natural gas and is therefore mostly suited for the production of transportation fuels and other chemical products. Syngas is mainly used as an intermediary building block for the final production (synthesis) of various fuels such as synthetic natural gas, methanol, and synthetic petroleum fuel (dimethyl ether – synthesized gasoline and diesel fuel) (Chadeesingh, 2011; Speight, 2013).
The use of syngas offers the opportunity to furnish a broad range of environmentally clean fuels and chemicals, and there has been steady growth in the traditional uses of this fuel. Almost all hydrogen gas is manufactured from synthesis gas; not surprisingly, there has been an increase in the demand for this basic chemical. In fact, the major use of syngas is in the manufacture of hydrogen for a growing number of purposes, especially in petroleum refineries (Speight, 2014). Methanol not only remains the second largest consumer of synthesis gas, but has shown remarkable growth as part of the methyl ethers used as octane enhancers in automotive fuels.
The FT synthesis remains the third largest consumer of syngas, mostly for transportation fuels but also as a growing feedstock source for the manufacture of chemicals, including polymers. The hydroformylation of olefins (the Oxo reaction), a completely chemical use of syngas, is the fourth largest use of carbon monoxide and hydrogen mixtures. A direct application of syngas as fuel (and eventually also for chemicals) that promises to increase is its use for IGCC units for the generation of electricity (and also chemicals) from coal, petroleum coke, or heavy residuals. Finally, synthesis gas is the principal source of carbon monoxide, which is used in an expanding list of carbonylation reactions, which are of major industrial interest.
1.5.1.2 Low-heat content (low-Btu) gas
During the production of coal gas by oxidation with air, the oxygen is not separated from the air and, as a result, the gas product invariably has a low-heat content (150–300 Btu/ft3). Low-heat content gas is also the usual product of in situ gasification of coal (Speight, 2013), which is essentially used as a method for obtaining energy from coal without the necessity of mining the coal, especially if the coal cannot be mined or if mining is uneconomical.
Several important chemical reactions and a host of side reactions are involved in the manufacture of low-heat content gas under the high temperature conditions employed (Balat, 2011; Speight, 2013). Low-heat content gas contains several components, four of which are always major components present at levels of at least several percent; a fifth component, methane, is marginally a major component.
The nitrogen content of low-heat content gas ranges from somewhat less than 33% (v/v) to slightly more than 50% (v/v) and cannot be removed by any reasonable means; the presence of nitrogen at these levels makes the product gas low-heat content by definition. The nitrogen also strongly limits the applicability of the gas to chemical synthesis. Two other noncombustible components – water (H2O) and carbon dioxide (CO) – further lower the heating value of the gas; water can be removed by condensation and carbon dioxide by relatively straightforward chemical means.
The two major combustible components are hydrogen and carbon monoxide; the H2/CO ratio varies from approximately 2:3 to about 3:2. Methane may also make an appreciable contribution to the heat content of the gas. Of the minor components, hydrogen sulfide is the most significant; in fact, the amount produced is proportional to the sulfur content of the feed coal. Any hydrogen sulfide present must be removed by one or more of several procedures (Mokhatab, Poe, & Speight, 2006; Speight, 2007).
Low-heat content gas is of interest to industry as a fuel gas or occasionally as a raw material from which ammonia, methanol, and other compounds may be synthesized.
1.5.1.3 Medium-heat content (medium-Btu) gas
Medium-heat content gas has a heating value in the range 300–550 Btu/ft3 and the composition is much like that of low-heat content gas, except that there is virtually no nitrogen. The primary combustible gases in medium-heat content gas are hydrogen and carbon monoxide (Kasem, 1979). Medium-heat content gas is considerably more versatile than low-heat content gas; like low-heat content gas, medium-heat content gas may be used directly as a fuel to raise steam, or used through a combined power cycle to drive a gas turbine, with the hot exhaust gases employed to raise steam. But medium-heat content gas is especially amenable to synthesize methane (by methanation), higher hydrocarbons (by FT synthesis), methanol, and a variety of synthetic chemicals.
The reactions used to produce medium-heat content gas are the same as those employed for low-heat content gas synthesis. The major difference is the application of a nitrogen barrier (such as the use of pure oxygen) to keep diluent nitrogen out of the system.
In medium-heat content gas, the H2/CO ratio varies from 2:3 C to 3:1 and the increased heating value correlates with higher methane and hydrogen contents as well as with lower carbon dioxide contents. Furthermore, the very nature of the gasification process used to produce the medium-heat content gas has a marked effect on the ease of subsequent processing. For example, the CO2-acceptor product is quite amenable to use for methane production because it has (1) the desired H2/CO ratio just exceeding 3:1, (2) an initially high methane content, and (3) relatively low water and carbon dioxide contents. Other gases may require appreciable shift reaction and removal of large quantities of water and carbon dioxide prior to methanation.
1.5.1.4 High-heat content (high-Btu) gas
High-heat content gas is essentially pure methane and is often referred to as synthetic natural gas or substitute natural gas (SNG) (Kasem, 1979; c.f. Speight, 1990, 2013). However, to qualify as SNG, a product must contain at least 95% methane, giving an energy content (heat content) of synthetic natural gas on the order of 980–1080 Btu/ft3.
The commonly accepted approach to the synthesis of high-heat content gas is the catalytic reaction of hydrogen and carbon monoxide:
To avoid catalyst poisoning, the feed gases for this reaction must be quite pure; therefore, impurities in the product are rare. The large quantities of water produced are removed by condensation and recirculated as very pure water through the gasification system. The hydrogen is usually present in slight excess to ensure that the toxic carbon monoxide is reacted; this small quantity of hydrogen will lower the heat content to a small degree.
The carbon monoxide/hydrogen reaction is somewhat inefficient as a means of producing methane because the reaction liberates large quantities of heat. In addition, the methanation catalyst is troublesome and prone to poisoning by sulfur compounds and the decomposition of metals can destroy the catalyst. Hydrogasification may be thus employed to minimize the need for methanation:
The product of hydrogasification is far from pure methane, and additional methanation is required after hydrogen sulfide and other impurities are removed.
1.5.2 Liquid fuels
The production of liquid fuels from coal via gasification is often referred to as the indirect liquefaction of coal (Speight, 2013). In these processes, coal is not converted directly into liquid products but involves a two-stage conversion operation in which coal is first converted (by reaction with steam and oxygen) to produce a gaseous mixture that is composed primarily of carbon monoxide and hydrogen (synthesis gas). The gas stream is subsequently purified (to remove sulfur, nitrogen, and any particulate matter) after which it is catalytically converted to a mixture of liquid hydrocarbon products.
The synthesis of hydrocarbons from carbon monoxide and hydrogen (the FT synthesis) is a procedure for the indirect liquefaction of coal and other carbonaceous feedstocks (Anderson, 1984; Batchelder, 1962; Dry, 1976; Speight, 2011a,b; Storch, Golumbic, & Anderson, 1951). This process is the only coal liquefaction scheme currently in use on a relatively large commercial scale; South Africa is currently using the FT process on a commercial scale in their Sasol complex.
Thus, coal is converted to gaseous products at temperatures in excess of 800 °C (1470 °F), and at moderate pressures, to produce syngas:
The gasification may be attained by means of any one of several processes or even by gasification of coal in place (underground, or in situ, gasification of coal).
In practice, the FT reaction is carried out at temperatures of 200–350 °C (390–660 °F) and at pressures of 75–4000 psi. The hydrogen/carbon monoxide ratio is typically on the order of 2/2:1 or 2/5:1. As up to three volumes of hydrogen may be required to achieve the next stage of the liquids production, the synthesis gas must then be converted by means of the water–gas shift reaction to the desired level of hydrogen:
After this, the gaseous mix is purified and converted to a wide variety of hydrocarbons:
These reactions result primarily in low- and medium-boiling aliphatic compounds suitable for gasoline and diesel fuel.
1.6 Future trends
The future depends very much on the effect of coal gasification processes on the surrounding environment. It is these environmental effects and issues that will direct the success of gasification.
Clean coal technologies (CCTs) are a new generation of advanced coal utilization processes that are designed to enhance both the efficiency and the environmental acceptability of coal extraction, preparation, and use. These technologies reduce emissions, reduce waste, and increase the amount of energy gained from coal. The goal of the program is to foster development of the most promising CCTs such as improved methods of cleaning coal, fluidized-bed combustion, IGCC, furnace sorbent injection, and advanced flue-gas desulfurization.
In fact, there is a distinct possibility that within the foreseeable future the gasification process will increase in popularity in petroleum refineries – some refineries may even be known as gasification refineries (Speight, 2011b). A gasification refinery, such as the Sasol refinery in South Africa (Couvaras, 1997), would produce synthesis gas (from the carbonaceous feedstock) from which liquid fuels would be manufactured using the FT synthesis technology.
In fact, gasification to produce synthesis gas can proceed from any carbonaceous material, including biomass. Inorganic components of the feedstock, such as metals and minerals, are trapped in an inert and environmentally safe form as char, which may have use as a fertilizer. Biomass gasification is therefore one of the most technically and economically convincing energy possibilities for a potentially carbon neutral economy.
The manufacture of gas mixtures of carbon monoxide and hydrogen has been an important part of chemical technology for about a century. Originally, such mixtures were obtained by the reaction of steam with incandescent coke and were known as water gas. Eventually, steam-reforming processes, in which steam is reacted with natural gas (methane) or petroleum naphtha over a nickel catalyst, found wide application for the production of synthesis gas.
A modified version of steam reforming known as autothermal reforming, which is a combination of partial oxidation near the reactor inlet with conventional steam reforming further along the reactor, improves the overall reactor efficiency and increases the flexibility of the process. Partial oxidation processes using oxygen instead of steam also found wide application for the manufacture of synthesis gas, with the special feature that low-value feedstocks, such as heavy petroleum residues, could be used. In recent years, catalytic partial oxidation employing very short reaction times (milliseconds) at high temperatures (850–1000 °C) is providing still another approach to synthesis gas manufacture (Hickman & Schmidt, 1993).
In a gasifier, the carbonaceous material undergoes several different processes: (1) pyrolysis of carbonaceous fuels, (2) combustion, and (3) gasification of the remaining char. The process is highly dependent on the properties of the carbonaceous material and determines the structure and composition of the char, which will then undergo gasification reactions.
As petroleum supplies decrease, the desirability of producing gas from other carbonaceous feedstocks will increase, especially in those areas where natural gas is in short supply. It is also anticipated that costs of natural gas will increase, allowing coal gasification to compete as an economically viable process. Research in progress on a laboratory and pilot-plant scale should lead to the invention of new process technology by the end of the century, thus accelerating the industrial use of coal gasification.
The conversion of the gaseous products of gasification processes to synthesis gas – a mixture of hydrogen (H2) and carbon monoxide (CO), in a ratio appropriate to the application – needs additional steps after purification. The product gases (carbon monoxide, carbon dioxide, hydrogen, methane, and nitrogen) can be used as fuels or as raw materials for chemical or fertilizer manufacture.