biomass conversion technologies

Submitted by:.MANAOIS, Marybhel D.

Submitted to:ENGR. M. CABANGON

PAMANTASAN NG LUNGSOD NG MAYNILAUniversity of the City of Manila

College of Engineering and TechnologyDepartment of Chemical Engineering

Biomass Conversion TechnologiesThere are three types of conversion technologies currently available,

each appropriate for specific biomass types and resulting in specific energy products:

1. Thermochemical conversion is the application of heat and chemical processes in the production of energy products from biomass. A key thermochemical conversion process is gasification.

2. Biochemical conversion involves use of enzymes, bacteria or other microorganisms to break down biomass into liquid fuels, and includes anaerobic digestion, and fermentation.

3. Chemical conversion involves use of chemical agents to convert biomass into liquid fuels.

Technology for the Use of Biomass

Table 1 shows a list of technologies for biomass utilization.

The process of biomass gasification involves generating a high-temperature zone (800–1,200°C) by burning part of the raw material and using oxygen and steam as gasifying agents.

Introduction to Biomass and Thermochemical Conversion



The heat produced converts biomass into syngas, which is primarily comprised of H 2 and CO. The syngas is then used to synthesize liquid fuel and other chemicals.

The advantages of our technology include the possible use of both woody and herbaceous raw materials such as forest residue, inedible crop parts, and wood waste. A large-scale plant can be established in a small space due to the high yield of heat energy and an increased reaction rate.

Thermochemical conversion

Thermochemical technologies are used for converting biomass into fuel gases and chemicals. The thermochemical process involves multiple stages. The first stage involves converting solid biomass into gases. In the second stage the gases are condensed into oils. In the third and final stage the oils are conditioned and synthesized to produce syngas. Syngas contains carbon and hydrogen and can be used to produce ammonia, lubricants, and through the Fischer-Tropsch process can be used to produce biodiesel.




Gasification is the use of high temperatures and a controlled environment that leads to nearly all of the biomass being converted into gas. This takes place in two stages: partial combustion to form producer gas and charcoal, followed by chemical reduction. These stages are spatially separated in the gasifier, with gasifier design very much dependant on the feedstock characteristics. Gasification requires temperatures of about 800°C. Gasification technology has existed since the turn of the century when coal was extensively gasified in the UK and elsewhere for use in power generation and in houses for cooking and lighting. A major future role is envisaged for electricity production from biomass plantations and agricultural residues using large scale gasifiers with direct coupling to gas turbines.

The advantage of gasification is that using the syngas is potentially more efficient than direct combustion of the original fuel because it can be combusted at higher temperatures or even in fuel cells, so that the thermodynamic upper limit to the efficiency defined by Carnot's rule is higher or not applicable. Syngas may be burned directly in gas engines, used to produce methanol and hydrogen, or converted via the Fischer–Tropsch process into synthetic fuel. Gasification can also begin with material which would otherwise have been disposed of such as biodegradable waste. In addition, the high-temperature process refines out corrosive ash elements such as chloride and potassium, allowing clean gas production from otherwise problematic fuels. Gasification of fossil fuels is currently widely used on industrial scales to generate electricity.

History

The process of producing energy using the gasification method has been in use for more than 180 years. During that time coal and peat were used to power these plants. Initially developed to produce town gas for lighting & cooking in 1800s, this was replaced by electricity and natural gas, it was also used in blast furnaces but the bigger role was played in the production of synthetic chemicals where it has been in use since the 1920s.




During both world wars especially the Second World War the need of gasification produced fuel reemerged due to the shortage of petroleum. Wood gas generators, called Gasogene or Gazogène, were used to power motor vehicles in Europe. By 1945 there were trucks, buses and agricultural machines that were powered by gasification. It is estimated that there were close to 9,000,000 vehicles running on producer gas all over the world.

Chemical reactions

The chemical reactions in gasification process take place in the presence of steam in an oxygen-lean,reducing atmosphere. The ratio of oxygen molecules to carbon molecules is far less than one in the gasification reactor.

A portion of the fuel undergoes partial oxidation by precisely controlling the amount of oxygen fed to the gasifier. The heat released in the first reaction provides the necessary energy for the other gasification reaction to proceed very rapidly. In the Turn W2E™ system, gasification temperatures and pressures within the refractory-lined reactor typically range from 800 Deg C to 1200 Deg C and near atmospheric pressure to few inches of water respectively. At higher temperatures the endothermic reactions of carbon with steam are favored. A wide variety of carbonaceous feed stocks can be used in the gasification process. Low-BTU wastes may be blended with high - BTU supplementary fuels such as coal or petroleum coke to maintain the desired gasification temperatures in the reactor.

The reducing atmosphere within the gasification reactor prevents the formation of oxidized species such as SO2 and NOx which are replaced by




H2S (with lesser amounts of COS), ammonia, and nitrogen (N2). These species are much easier to scrub from the syngas than their oxidized counterparts before the syngas is utilized for power.

Gasification process

Gasification is a flexible, reliable, and clean energy technology that can turn a variety of low-value feedstocks into high-value products, help reduce our dependence on foreign oil and natural gas, and can provide a clean alternative source of baseload electricity, fertilizers, fuels, and chemicals.

It is a manufacturing process that converts any material containing carbon—such as coal, petroleum coke (petcoke), or biomass—into synthesis gas (syngas). The syngas can be burned to produce electricity or further processed to manufacture chemicals, fertilizers, liquid fuels, substitute natural gas (SNG), or hydrogen.

Gasification has been reliably used on a commercial scale worldwide for more than 50 years in the refining, fertilizer, and chemical industries, and for more than 35 years in the electric power industry.

There are more than 140 gasification plants operating worldwide. Nineteen of those plants are located in the United States. Worldwide gasification capacity is projected to grow 70 percent by 2015, with 80 percent of the growth occurring in Asia.

Gasification can compete effectively in high-price energy environments to provide power and products.

Because of the limitations of state-of-the-art biomass technology, a quest to improve the efficiency and range of applications has been underway for several decades.

The point of departure was the recognition that the combustion process actually comprises several separate thermal processes which, if conducted in a controlled manner, may considerably improve the result. These processes are:




Drying, where free moisture and cell-bound water are removed from the biomass by evaporation. These processes should ideally take place at a temperature of up to about 160ºC using waste heat from the conversion process.

Pyrolysis, where volatile gases are released from the dry biomass at temperatures ranging up to about 700ºC. These gases are non-condensable vapours (e.g. methane, carbon-monoxide) and condensable vapours (various tar compounds) and the residuum from this process will be mainly activated carbon.

Reduction, where the activated carbon reacts with water vapour and carbon dioxide to form combustible gases such as hydrogen and carbon oxide. The reduction (or gasification) process is carried out in the temperature ranging up to about 1100ºC.

Oxidation, where part of the carbon is burned to provide heat for the previously described processes.

The updraft gasification

In the updraft gasifier, moist biomass fuel is fed at the top and descends though gases rising through the reactor. In the upper zone a drying process occurs, below which pyrolysis is taking place. Following this, the material passes through a reduction zone (gasification) and in the zone above the grate an oxidation process is carried out (combustion).

To supply air for the combustion process and steam for the gasification process, moist hot air is supplied at the bottom of the reactor.

Combustible gas at a low temperature (because of the evaporation of moisture in the drying zone) is discharged at the top of the reactor, and inert ash from the heat-generating combustion process is extracted from the reactor bottom through a water lock.

Properties of Producer gas




The producer gas is affected by various processes as outlined above hence one can expect variations in the gas produced from various biomass sources. Table lists the composition of gas produced from various sources. The gas composition is also a function of gasifier design and thus, the same fuel may give different calorific value as when used in two different gasifiers. Table therefore shows approximate values of gas from different fuels.

The maximum dilution of gas takes place because of presence of nitrogen. Almost 50-60% of gas is composed of noncombustible nitrogen. Thus it may be beneficial to use oxygen 7 instead of air for gasification. However the cost and availability of oxygen may be a limiting factor in this regard. Nevertheless where the end product is methanol – a high energy quality item, then the cost and use of oxygen can be justified 5 .

On an average 1 kg of biomass produces about 2.5 m 3 of producer gas at S.T.P. In this process it consumes about 1.5 m 3 of air for combustion 14 For complete combustion of wood about 4.5 m 3 of air is




required. Thus biomass gasification consumes about 33% of theoretical stoichiometeric ratio for wood burning.

Syngas Cleanup

Syngas Contaminant Removal and Conditioning

Raw synthesis gas (syngas) from the high temperature gas cooling (HTGC) system needs to be cleaned to remove contaminants including fine particulates, sulfur, ammonia, chlorides, mercury, and other trace heavy metals to meet environmental emission regulations, as well as to protect downstream processes. In the case of carbon sequestration, carbon dioxide (CO2) is also removed. Depending on the application, syngas may need to be conditioned to adjust the hydrogen-to-carbon monoxide (H2-to-CO) ratio to meet downstream process requirement. In applications where very low sulfur (<10 ppmv) syngas is required, converting carbonyl sulfide (COS) to hydrogen sulfide (H2S) before sulfur removal may also be needed. Typical cleanup and conditioning processes include cyclone and filters for bulk particulates removal; wet scrubbing to remove fine particulates, ammonia and chlorides; solid absorbents for mercury and trace heavy metal removal; water gas shift (WGS) for H2-to-CO ratio adjustment; catalytic hydrolysis for converting COS to H2S; and acid gas removal (AGR) for extracting sulfur-bearing gases and CO2 removal.

High Temperature Syngas Cooling and Heat Recovery

Synthesis gas (syngas) leaving the reactor is at high temperature; typically 2,500°F to 2,800°F for an entrained-flow gasifier. Recovery of heat from the syngas is essential for attaining process efficiency. Heat recovery systems can reclaim a significant portion (5-25%) of the energy in the feed, depending on the technology employed. The actual design of a syngas cooling and heat recovery system has to consider the characteristics of the coal feed, syngas produced, and the overall gasification process application.

The raw syngas leaving the gasifier can be cooled by a radiant and/or convective heat exchanger and/or by a direct quench system, wherein water or cool recycled gas is injected into the hot raw syngas. Then, the syngas typically passes through a series of heat exchangers for heat recovery at a lower temperature. In all cases, steam is produced for in-plant power generation or process heating. The steam and water systems are integrated and optimized within the overall gasification facility.

Radiant Syngas Cooler




A significant quantity of the sensible heat in the raw syngas can be recovered via a radiant syngas cooler (RSC) to improve the overall gasification plant thermal efficiency. An RSC is a large, expensive piece of equipment. It can be prone to fouling and difficult to clean. The slag entrained in the syngas can stick to the RSC and causes deterioration in heat transfer. Despite that, the Tampa Electric plant seems to achieve satisfactory operational reliability with its RSC.

Dry Particulate Removal

Bulk solid particulate removal can be achieved with either filters and/or cyclones, depending on the gasification system and operating conditions. Cyclones are a commercially proven technology and can be refractory-lined for high temperature operations. High temperature candle filters have been developed and can remove particulates from raw syngas at temperatures between 550°F and 900°F (~ 300°C to 500°C). Below 550°F, the filters may be blinded by deposits of ammonium chloride. Above 900°F, alkali compounds may pass through the filters at unacceptable levels, as the vapor pressures of these compounds may still be high. Development of candle filters that can remove particulates at high temperatures is a significant technology development for gasification. Use of candle filters in dry solids removal systems is now considered commercially available technology. In some current gasification designs, candle filters are being used upstream of a wet scrubber for effective overall solids removal.

Effective dry particulate removal is an integral part of the warm gas cleanup (WGCU) technology development effort being undertaken by Research Triangle Institute (RTI) with funding from the Department of Energy (DOE).

Tar from gasification of biomass

One of the major issues in the biomass gasification process is how to deal with the tar formed during the process. Tars can be easily defined as undesirable and problematic organic products of biomass gasification but there are a large number of definitions for the tar in the literature. The diversity in the operational definitions of tars usually comes from the variable product gas compositions required for a particular end-use application and how the tars are collected and analyzed.




Tar removal technologies can be broadly divided into two approaches: treatments inside the gasifier (primary methods) and hot gas cleaning after the gasifier (secondary methods). Although primary methods theoretically eliminate the need for downstream clean-up creating tar-free gas at the exit of the gasifier, they have not yet resulted in

satisfactory low level of tar. It is more likely that a combination of primary and secondary methods has to be used for total tar removal during technology development in the future.

Different catalysts are used as a part of both primary and secondary methods for tar removal.

Catalysts for tar cracking

There are a large number of different catalysts that have been used to eliminate the tars in the product gas from the gasification process. The two most researched groups are Ni-based catalysts and dolomites. When Ni-based catalysts are used, tar concentration in the product gas can be reduced significantly by means of reforming but since this process is endothermic, a part of the chemically bound energy of the gas has to be burned to sustain this process. This effect leads to a decreased efficiency of the gasification process.

In contrast, when so called tar cracking catalysts such as dolomite are used, the only thing that is reformed is the tar itself while low hydrocarbons e.g. methane, ethane and propane are left intact. Simultaneously with this transformation of tar, the gas composition (CO2, CO, H2 etc.) changes as a consequence of reactions that will be described later in the text. Tar cracking can be defined as a process that breaks down the larger, heavier and more complex hydrocarbon molecules of tar into simpler and lighter molecules by the action of heat and aided by the presence of a catalyst but without the addition of hydrogen.

Two well-known tar cracking catalysts are naturally occurring minerals: dolomite and olivine. Another type of material that has been recognized as a tar cracking catalyst is the Fluid Catalytic Cracking (FCC) catalyst.




Dolomite is a calcium magnesium ore with the general chemical formula CaMg(CO3 )2 with some minor impurities. In order for dolomite to become active for tar conversion, it has to be calcined. Calcination involves decomposition of the carbonate mineral, eliminating CO2 to form MgO-CaO, at high temperatures (usually 800-900°C). The effective use of dolomite as a catalyst is restricted by relatively high temperatures 4 and the partial pressure of CO2.

Fine Particulate Removal

Raw syngas leaving the HTGC system in today's commercial gasification plant is normally quenched and scrubbed with water in a trayed column for fine char and ash particulate removal prior to recycle to the slurry-fed gasifiers. For dry feed gasification, cyclones and candle filters are used to recover most of the fine particulate for recycle to the gasifiers before final cleanup with water quenching and scrubbing. In addition, fine particulates, chlorides, ammonia, some H2S, and other trace contaminants are also removed from the syngas during the scrubbing process. The scrubbed gas is then either reheated for COS hydrolysis and/or a sour WGS when required, or cooled in the low temperature gas cooling (LTGC) system by generating low pressure steam, preheating boiler feed water, and heat exchanging it against cooling water before further processing.

Spent water from the scrubber column is directed to the sour water treatment system, where it is depressurized and decanted in a gravity settler to remove fine particulates. Solid-concentrated underflows from the settler bottom are filtered to recover the fine particulate as the filter cake, which is then either discarded or recycled to the gasifier depending on its carbon content. Water from the settler is recycled for gasification uses with the excess being sent to the wastewater treatment system for disposal.

Wet Scrubbing




In most commercial gasification operations, syngas leaving the filter is quenched and scrubbed with water for final particulate removal. Water scrubbing takes place below the dew point temperature of the syngas so that the finest solid particles can act as nuclei for condensation, thus ensuring that all solids can be removed efficiently.Scrubbing also removes chlorides, ammonia, some hydrogen sulfide (H2S) and other trace contaminants from the syngas. Typically, the scrubbed syngas is reheated for carbonyl sulfide (COS) hydrolysis and/or a sour water gas shift (WGS) if required, followed by cooling in a low temperature gas cooling (LTGC) system to generate low pressure steam. After these processes, the syngas is sent downstream for sulfur and mercury removal.

Spent water from the scrubber column is directed to a gray water treatment system where it is depressurized and vacuum flashed. The spent water is then decanted into a gravity settler to remove particulates. Solid-concentrated underflows from the settler bottom are filtered to recover the fine particulate as a filter cake, which is then either discarded or recycled to the gasifier depending on its carbon content. Water from the settler is recycled for gasification reuse, with excess being sent to the wastewater treatment system for disposal.

Mercury and Trace Elements

Current commercial practice is to pass cooled syngas from LTGC through sulfided, activated carbon beds to remove over 90% of the mercury and a significant amount of other heavy metal contaminants. Due to sulfur in the activated carbon, these beds are normally placed ahead of the AGR system to minimize the possibility of sulfur slipping back into and contaminating the cleaned syngas.




Water Gas Shift

In applications where scrubbed syngas H2/CO ratio must be increased/adjusted to meet downstream process requirements, the syngas is passed through a multi-stage, fixed-bed reactor containing shift catalysts to convert carbon monoxide (CO) and water into additional H2 and CO2 according to the following reaction known as the water-gas shift (WGS) reaction:

The shift reaction will operate with a variety of catalysts between 400°F and 900°F. The reaction does not change molar totals and therefore the effect of pressure on the reaction is minimal. However, the equilibrium for H2 production is favored by high moisture content and low temperature for the exothermic reaction. Normally, excess moisture is present in the scrubber syngas from slurry-fed gasifiers sufficient to drive the shift reaction to achieve the required H2-to-CO ratio. Indeed, for some slurry-fed gasification systems, a portion of the syngas feed may need to be bypassed around the sour shift reactor to avoid exceeding the required product H2-to-CO ratio. On the other hand, additional steam injection before the shift may be needed for syngas output by dry-fed gasifiers.

In any case, the scrubber syngas feed is normally reheated to 30 to 50°F above saturation temperature to avoid catalyst damage by condensation of liquid water in the shift reactor. Shifted syngas is cooled in the low temperature gas cooling (LTGC) system by generating low pressure steam, preheating boiler feed water, and heat exchanging against cooling water before going through the acid gas removal system for sulfur removal.

There is some flexibility for locating the WGS reactor: it can be located either before the sulfur removal step (sour shift) or after sulfur removal (sweet shift). Sour shift uses a cobalt-molybdenum catalyst and is normally located after the water scrubber, where syngas is saturated with water at about 450°F to 500°F, depending on the gasification conditions and the amount of high temperature heat recovery. An important benefit of sour shift is its




ability to also convert COS and other organic sulfur compounds into H2S to make downstream sulfur removal easier. Therefore, syngas treated through WGS does not need separate COS hydrolysis conditioning.

A conventional high temperature (HT) sweet shifting operates between 550°F to 900°F and uses chromium or copper promoted iron-based catalysts. Because syngas from the sulfur removal process is saturated with water at either near or below ambient temperature, steam injection or other means to add moisture to the feed is normally needed for HT sweet shifting.

A conventional low temperature (LT) sweet shift, typically used to reduce residual CO content to below 1%, operates between 400°F to 500°F and uses a copper-zinc-aluminum catalyst. LT sweet shifting catalysts are extremely sensitive to sulfur and chloride poisoning and are normally not used in coal gasification plants.

Sweet shift is normally not used for coal gasification applications, given the problems of sulfur and chloride poisoning as mentioned above, in addition to the inefficiency of having to cool the syngas before sulfur removal, which condenses out all of the moisture gained in the water scrubber, and then reheating and re-injecting the steam into the treated gas after H2S removal to provide moisture for shift. Sour shift is normally preferred for coal gasification applications since the moisture gained in the water scrubber is used to drive the shift reaction to meet the required H2/CO ratio.

Selexol Process




Selexol solvent is a mixture of dimethyl ethers of polyethylene glycols, nontoxic, with a high boiling point, and is an excellent solvent for acid gases. The selectivity for H2S is much higher than that for CO2, so it can be used to selectively remove these different acid gases, minimizing CO2 content in the H2S stream sent to the SRU with associated benefits on SRU sizing and economics, and enabling regeneration of solvent for CO2 recovery by economical flashing. These points are reflected in Figure 1, which depicts a dual-stage Selexol process. The first column (sulfur absorber) removes most of the H2S (and a limited amount of CO2) from the feed syngas, which then flows to the second column (CO2 absorber) which removes most of the CO2. The rich solvent leaving the CO2 absorption column is flashed in drums, from which relatively pure CO2 is recovered. The solvent in the sulfur absorber column must be stripped in a column with reboiler to remove the high H2S content gases.

CO2 capture/separation technologies

Solvent absorption involves a cyclical process in which carbon dioxide is absorbed from a gas stream directed into a liquid, typically an amine. The gas stream, with most of the carbon dioxide removed, is then emitted to the atmosphere. The liquid is processed to remove the carbon dioxide, which is then compressed for storage. The resulting carbon-dioxide-free liquid is used again for absorption and the process continues. This technique is fairly widely used in a range of applications, but it needs a large amount of power to regenerate the solvent.

The absorption process is most commonly applied to post-combustion capture and in the main, the absorbents are liquid solvents.

In post-combustion systems, the flue gas needs to be cooled and impurities removed so that the solvent can efficiently absorb the CO2. The flue gases containing CO2 and N2 are then fed into a tower called the absorber tower. The flue gas comes into the bottom of the tower while the solvent is fed into the top of the tower. There is packing material in the tower, and the flue gas flows up through the packing, making contact with the solvent as it falls down. The CO2 is absorbed by the solvent as the flue gas rises so that the gas that comes out of the top of the tower contains very little CO2. Modifying the packing material to improve the absorption of CO2 is another area of research.

The solvent, with dissolved CO2, is then removed from the chamber. The N2 is released as it is not absorbed in the solvent. The recovery of CO2 from the solvent is called desorption. The usual process for recovery of CO2 from the




solvent is temperature change. Other methods include pressure changes and the use of membranes with solvents.

Fischer-Tropsch diesel

The Fischer-Tropsch process is one of the advanced biofuel conversion technologies that comprise gasification of biomass feedstocks, cleaning and conditioning of the produced synthesis gas, and subsequent synthesis to liquid (or gaseous) biofuels. The Fischer-Tropsch process has been known since the 1920s in Germany, but in the past it was mainly used for the production of liquid fuels from coal or natural gas. However, the process using biomass as feedstock is still under development. Any type of biomass can be used as a feedstock, including woody and grassy materials and agricultural and forestry residues. The biomass is gasified to produce synthesis gas, which is a mixture of carbon monoxide (CO) and hydrogen (H2). Prior to synthesis, this gas can be conditioned using the water gas shift to achieve the required H2/CO ratio for the synthesis. The liquids produced from the syngas, which comprise various hydrocarbon fractions, are very clean (sulphur free) straight-chain hydrocarbons, and can be converted further to automotive fuels. Fischer-Tropsch diesel can be produced directly, but a higher yield is achieved if first Fischer-Tropsch wax is produced, followed by hydrocracking. Fischer-Tropsch diesel is similar to fossil diesel with regard to a.o. its energy content, density and viscosity and it can be blended with fossil diesel in any proportion without the need for engine or infrastructure modifications. Regarding some fuel characteristics, Fischer-Tropsch diesel is even more favourable, i.e. a higher cetane number (better




auto-ignition qualities) and lower aromatic content, which results in lower NOx and particle emissions.

For the production of Fischer-Tropsch diesel the main technological challenges are in the production of the synthesis gas (entrained flow gasifier). These barriers also apply to other gasification-derived biofuels, i.e. bio-methanol, bio-DME and biohydrogen. The synthesis gas is produced by a high-temperature gasification, which is already used for coal gasification. Biomass has different properties than coal and, therefore, several process changes are necessary. First, the biomass pre-treatment and feeding need a different process, because milling biomass to small particles is too energy-intensive.

Moreover, small biomass particles can also aggregate and plug feeding lines. Pre-treatment processes like torrefaction or pyrolysis (which produces a liquid oil) could be developed to overcome these problems. Second, due to the higher reactivity of biomass (compared to coal) the gasification temperature might be decreased, resulting in higher efficiencies, but this will require different gasification and burner design. Third, the ash composition in biomass is different from that in coal, which results in different ash and slag behaviour, which is an important factor in the gasifier and still needs to be studied thoroughly. This ash and slag behaviour is also important for the cooling of the syngas, for which innovative development is desired. Other research topics are the cleaning and conditioning of synthesis gas, development of several types of catalysts, and the utilisation of by-products such as electricity, heat and steam. In Germany, a pilot production facility for Fischer-Tropsch liquids from biomass is currently in operation.

Gasification Products and Applications

Chemicals and Fertilizers

Modern gasification has been used in the chemical industry since the 1950s. Typically, the chemical industry uses gasification to produce methanol as well as chemicals, such as ammonia and urea, which form the foundation of nitrogen-based fertilizers. The majority of the operating gasification plants worldwide produce chemicals and fertilizers. And, as natural gas and oil prices continue to increase, the chemical industry is developing additional coal gasification plants to generate these basic chemical building blocks.

Eastman Chemical Company helped advance the use of coal gasification technology for chemicals production in the U.S. Eastman's coal-to-chemicals




plant in Kingsport, Tennessee converts Appalachian coals to methanol and acetyl chemicals. The plant began operating in 1983 and has gasified approximately 10 million tons of coal with a 98 to 99 percent on-stream availability rate.

Power Generation with Gasification

Coal can be used as a feedstock to produce electricity via gasification, commonly referred to as Integrated Gasification Combined Cycle (IGCC). This particular coal-to-power technology allows the continued use of coal without the high level of air emissions associated with conventional coal-burning technologies. In gasification power plants, the pollutants in the syngas are removed before the syngas is combusted in the turbines. In contrast, conventional coal combustion technologies capture the pollutants after combustion, which requires cleaning a much larger volume of the exhaust gas. This increases costs, reduces reliability, and generates large volumes of sulfur-laden wastes that must be disposed of in landfills or lagoons.

Today, there are 15 gasification-based power plants operating successfully around the world. There are three such plants operating in the United States. Plants in Terre Haute, Indiana and Tampa, Florida provide baseload electric power, and the third, in Delaware City, Delaware provides electricity to a Valero refinery.

Substitute Natural Gas

Gasification can also be used to create substitute natural gas (SNG) from coal and other feedstocks, supplementing U.S. natural gas reserves. Using a "methanation" reaction, the coal-based syngas—chiefly carbon monoxide (CO) and hydrogen (H2)—can be profitably converted to methane (CH4). Nearly identical to conventional natural gas, the resulting SNG can be shipped in the U.S. natural gas pipeline system and used to generate electricity, produce chemicals/fertilizers, or heat homes and businesses. SNG will enhance domestic fuel security by displacing imported natural gas that is generally supplied in the form of Liquefied Natural Gas (LNG).

Hydrogen for Oil Refining

Hydrogen, one of the two major components of syngas, is used in the oil refining industry to strip impurities from gasoline, diesel fuel, and jet fuel, thereby producing the clean fuels required by state and federal clean air regulations. Hydrogen is also used to upgrade heavy crude oil. Historically, refineries have utilized natural gas to produce this hydrogen. Now, with the increasing price of natural gas, refineries are looking to alternative feedstocks to produce the needed hydrogen. Refineries can gasify low-value




residuals, such as petroleum coke, asphalts, tars, and some oily wastes from the refining process, to generate both the required hydrogen and the power and steam needed to run the refinery.


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