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bioweb.sungrant.org » Technical » Bioproducts » Bioproducts from Syngas » Hydrogen
| Products from Syngas—Hydrogen (Metal Catalysts) |
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In its simplest form, syngas (also called producer gas, town gas, blue water gas, and synthesis gas among others) is composed of carbon monoxide (CO) and hydrogen (H2), which provide the building blocks to produce a number of organic compounds. During the 1800’s, coal gasification was used for lighting and heating. The production of fuels and chemicals from syngas began in the early 20th century. Today, hydrogen, along with methanol and ammonia, constitute the major chemicals commercially produced from syngas.
In principle, syngas can be produced from any hydrocarbon feedstock, including natural gas, naphtha, residual oil, petroleum coke, coal, and biomass. Under today’s conditions, the least expensive feedstock is natural gas. Using numerous synthesis pathways, a large number of organic compounds can be produced from syngas (figure 1). Hydrogen (Wender, 1996) is the principal product made from syngas and is produced as both a main product and as a by-product.
World consumption of hydrogen in 1999 was 15,864 billion ft3, 20% of which was consumed in the U.S. (Suresh, et al, 2001). About 60% of world consumption was use to produce ammonia, followed by capture and use in oil refineries (23%) and methanol production (9%). Only 8% was produced as merchant hydrogen. Presently, 77% of the world hydrogen production comes from petrochemicals (mostly natural gas-methane), 18 % from coal, 4 % from water electrolysis, and 1% from other sources (Häussinger, 2000). While current production is predominantly from natural gas, hydrogen can be produced from numerous feedstocks including coal, petroleum and petroleum products, biomass, ethanol, methanol, ammonia, etc. Currently, there are about a dozen companies building plants to produce hydrogen from methanol or ammonia (Suresh, et al, 2001). |
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| Hydrogen synthesis reactions |
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Steam methane reforming is the dominant technology used to produce hydrogen, and involves four steps--feed pretreatment, steam reforming, CO shift conversion, and hydrogen purification. For natural gas, pretreatment involves desulfurization using a hydrogenator followed by a zinc oxide bed.
The natural gas is then fed into a reformer reactor, where it reacts with steam to produce carbon oxides (CO, CO2) and H2. The reformer reactor consists of catalyst-filled tubes surrounded by a firebox that provides the heat needed for the endothermic reforming reaction (about 850°C, 1.5-3 MPa). The reaction takes the general form of equation 1, where CnHm is the hydrocarbon feedstock used (CH4 for methane) (Häussinger, 2000).
CnHm + nH2O à (n+m/2)H2 + nCO (equation 1)
The gas exiting the reformer subsequently undergoes water gas shift reactions (equation 2) (Leiby, 1994).
CH4 + H2O à 3H2 + CO ΔHr = 49.3 kcal/mol (equation 2)
CO + H2O à H2 + CO2 ΔHr = -9.8 kcal/mol
In the classical syngas to hydrogen process, the gas exiting the reformer is cooled to about 220°C and undergoes a water gas shift reaction in a low temperature shift (LTS) converter followed by CO2 scrubbing. About 65-75% of the CO and steam contained in the feed gas stream of an high temperature shift (HTS) reactor are converted to additional hydrogen and CO2 (Leiby, 1994) and about half of the hydrogen comes from the steam. The reforming reaction is highly endothermic and is favored by high temperatures and low pressures. Higher pressures tend to lower the methane conversion. Current commercial operations typically use a HTS converter where the gas that exits the reformer is cooled to about 350°C and then undergoes the water gas shift (WGS) reaction.
The gas exiting the reformer is then purified. Low temperature shift processes use a methanation reactor to remove trace amounts of CO and CO2 and produce hydrogen with a purity of 97-99%. About 80-90% of the CO can be additionally converted to hydrogen improving the overall hydrogen yield by about 5% (Leiby, 1994). High temperature shift processes purify the hydrogen (>99.99%) using a pressure swing adsorption (PSA) unit (Leiby, 1994). High hydrogen recovery rates (85-90%) are achieved at a minimum feed gas to purge gas pressure ratio of 4:1 and a purge gas pressure of between 17 to 20 psi (Leiby, 1994). Hydrogen recovery drops to 60-80% at high purge gas pressures (55-95 psi) (Leiby, 1994). Entrained liquids (water and condensed hydrocarbons) are removed prior to the syngas entering the PSA unit because they will permanently damage the carbon and zeolite adsorbents in the unit. This is usually accomplished by first cooling the gas and then passing it through a knock out drum with a mist eliminator. The PSA off-gas (which contains unreacted CH4, CO, CO2, and unrecovered hydrogen) is used to fuel the reformer (80-90% of the required heat) with the remaining heat requirement provided by supplemental natural gas (Leiby, 1994).
The PSA efficiency is affected by adsorption temperature with fewer impurities adsorbed at higher temperatures due to the decreasing equilibrium capacity of the molecular sieves. Hydrogen recovery rates are reduced by the presence of nitrogen in the gas stream (by as much as 2.5% for a 10-ppm nitrogen concentration). Figure 2 illustrates the methane steam reforming process.
In industrial reformers, the reforming and shift reactions result in a product composition that closely approaches equilibrium. A number of side reactions also occur in the steam reformer, and produce carbon (equation 3).
2CO à C(s) + CO2 (Boudouard coking) (equation 3)
CO + H2 à C(s) + H2O (CO reduction)
CH4à C(s) + 2H2 (Methane cracking)
The steam to carbon molar ratio is usually between 2 and 6, depending on the feedstock and process conditions. Excess steam is used to prevent coking in the reformer tubes. The shift reaction is exothermic and favors low temperatures. Since it does not approach completion in the reformer (usually there is 10-15 vol% CO, dry basis, in the reformer effluent), further conversion of CO is performed using shift conversion catalysts. |
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| Hydrogen synthesis catalysts |
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Catalysts play a pivotal role in syngas conversion reactions. The basic concept of a catalytic reaction is that reactants adsorb onto the catalyst surface, rearrange, and combine into products that then desorb from the catalyst surface. One of the fundamental functional differences between syngas synthesis catalysts is whether or not the adsorbed CO molecule dissociates on the catalyst surface. For higher alcohol synthesis, CO dissociations are a necessary reaction condition. For hydrogen synthesis, the hydrogen acts as both a necessary reactant for CO hydrogenation, and also is used to reduce the metalized synthesis catalysts and activate the metal surface.
Conventional steam reforming catalysts are 10 to 33 wt% NiO supported by minerals (alumina, cement, or magnesia). The methanantion reaction typically uses a nickel oxide catalyst in combination with chromium oxide. Heavy feedstocks tend to coke the reforming catalyst but promoters (potassium, lanthanum, ruthenium, and cerium) can be used to reduce the problem by increasing the steam gasification of solid carbon which reduces coke formation. Reforming activity may also be reduced however (Leiby, 1994). Nickel-free catalysts containing mostly strontium, aluminum and calcium oxides have been successfully tested on feedstocks heavier than naphtha, however, the gas produced contains high levels of methane which requires a secondary reformer to remove (Häussinger, 2000).
High temperature shift (HTS; 300-450°C) catalysts have an iron oxide-chromium oxide basis while the major component of low temperature shift catalysts (LTS; 180-270°C) is copper oxide usually in a mixture with zinc oxide (Häussinger, 2000). LTS reactors often operate near condensation conditions and this catalyst is sensitive to changes in operating conditions. Typical lifetimes for both HTS and LTS catalysts are 3-5 years.
Sulfur compounds are the main poison of reforming catalysts. The catalyst can begin to deactivate at sulfur concentrations as low as 0.1 pap. To maintain a 3-year lifetime, the sulfur concentration in the reformer feed gas should be less than 0.5 ppm (Leiby, 1994). Natural gas generally contains only small amounts of sulfur compounds (usually H2S). In most commercial facilities (SMR plants), sulfur compounds are converted to H2S in a hydrogenator followed by desulfurization on a ZnO bed. Any remaining organic sulfur compounds or carbonyl sulfides are partially cracked and also absorbed on the zinc oxide bed (Häussinger, 2000). Chemical or physical scrubbing is required to remove sulfur at concentrations of greater than 1% in the feed gas. LTS catalysts are highly sensitive to sulfur, while HTS catalysts can tolerate sulfur concentrations up to several hundred parts per million although their catalytic activity declines. Uranium oxide or chromium oxide are used as promoters with some catalysts to provide a higher tolerance to sulfur poisoning (Häussinger, 2000). Additionally, sulfur tolerant (dirty shift) catalysts have been developed that are better able to handle larger sulfur concentrations. ICI Katalco makes sulfur tolerant catalysts consisting of cobalt and molybdenum oxides which operate at temperatures between 230 and 500°C. The ratio of steam to sulfur in the feed gas and the catalyst temperature are the controlling factors. In addition to sulfur, chloride is a LTS catalyst poison and phosphorus, silicon and unsaturated hydrocarbons in the presence of NOx are HTS catalyst poisons Häussinger, 2000). Reforming catalyst suppliers include BASF, Dycat International, Haldor Topsoe, ICI Katalco and United Catalysts (Leiby, 1994).
Hydrogen synthesis reactors. Numerous reformer designs exist and can be used in a number of process configurations. The main components of the reformer furnace include an air/fuel combustion system, a radiant heat transfer section, and a convection section. The combustion and radiant sections combust the air/fuel mixture and transfer the heat to the catalyst tubes. The convection section recovers heat by cooling down the flue gases. Reformer furnaces are not very efficient and only about half of the heat in the radiant section is absorbed by the furnace tubes.
In most reformers the feed gas flows upward through the catalyst tubes, but reformer furnaces can also be side-, terrace-, top-, or bottom-fired (Johansen, 1992). Top-fired reformers are generally suited for larger production units. For small units of < 24 tubes, side-fired units are more economical. The terrace-fired reformer is a variation of the side-wall design. Bottom-fired reformers are the least common of the four designs (Leiby, 1994). The shift converters and methanation reactors are fixed bed reactors.
BASF was the first company to develop steam methane reforming in the early 1900s (Nirula, 1995). From the mid-1930s through the 1950s, steam reforming was developed for heavier hydrocarbon feedstocks. Thereafter, energy efficiency improvements were made, creating a mature technology by the 1980s. Today there are numerous firms that license various components of the steam reforming process (table 1) and supply PSA units (table 2).
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| Commercial production of hydrogen from syngas |
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World consumption of hydrogen in 1999 was 15,864 billion ft3, 20% of which was consumed in the U.S. (Suresh, 2001). Information regarding delivered hydrogen contract prices is not readily available, and prices vary substantially depending on the type of delivery, the quantity required, and the delivery distance. Pipeline delivery is the most economical form of transport followed by bulk liquid hydrogen delivery. SRI indicates a list price for liquid hydrogen of $45/GJ with considerably lower average purchase prices (Suresh, 2001). For large-volume, bulk liquid deliveries, prices typically range between $18-$24/GJ (Suresh, 2001).
The cost of producing hydrogen from natural gas in large-scale, central production facilities (at a psi of 400) is estimated to be about $5-$8/GJ. Processing difficulties, and thus capital costs, increase progressively as the feedstock changes to light hydrocarbons, heavy hydrocarbons, and to solid feedstocks. Table 3 summarizes the estimated costs of producing hydrogen from natural gas, coal, and biomass and table 4 provides a detailed description of the estimated costs of producing hydrogen from biomass syngas. All costs are plant gate costs.
Hydrogen itself is a clean burning fuel. However, depending upon the feedstock used, its production can generate a considerable amount of CO2. Additionally, steam reformers produce NOx from fuel combustion. In California, selective catalytic reduction units are used in combination with low NOx burners to meet the state’s strict air regulations (Baade, 2001). Controlling emissions becomes increasingly difficult as the feedstock becomes less hydrogen-rich (from heavy fuel oil, coke, or coal). These feedstocks also contain other impurities such as sulfur and heavy metals.
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| References |
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Amick, P.; Geosits, R.; Kramer, S. (2003). 225th ACS National Meeting. New Orleans, Louisiana. March 23-27. Fuel Chemistry Preprints. 48 (1) pg. 199-204.
Baade, W.F.; Parekh, U.N.; Raman, V.S. (2001). "Hydrogen." Kirk-Othmer Encyclopedia of Chemical Technology, John Wiley and Sons, Inc.
British Government Panel on Sustainable Development . July 1999.
Grégoire Padró, C.E.; Putsche, V. (1999). Survey of the Economics of Hydrogen Technologies. 57 pp.; NREL Report No. TP-570-27079.
Häussinger, P.; Lohmüller, R.; Watson, A.M. (2000). "Hydrogen." Ullmann's Encyclopedia of Industrial. Wiley-VCH Verlag GmbH and Co.KGaA.
IEA Greenhouse Gas Rand Programme (1999) Hydrogen – Today and Tomorrow.
IEA Bioenergy Task 33: Thermal Gasification of Biomass, Spring 2001, Task Meeting.
Johansen, T.; Raghuraman, K.S.; Hackett, L.A. (1992). “Trends in hydrogen plant design”. Hydrocarbon Processing.
Leiby, S.M. (1994). Options for Refinery Hydrogen. SRI Report No. 212. Menlo Park, CA.
McKinley, K.R.; Browne, S.H.; Neill, D.R.; Seki, A.; Takahashi, P.K. (1990). “Hydrogen Fuel from Renewable Resources”. Energy Sources. Vol. 12. pp. 105-110.
Nirula, S.C. (1995). Synthesis Gas. SRI Report No. 148A. Menlo Park, CA.
Spath, P.L. and D.C. Dayton, Preliminary screening—technical and economic assessment of synthesis gas to fuels and chemicals with emphasis on the potential for biomas-derived syngas, National Renewable Energy Laboratory, NREL/TP-510-34929, December, 2003.
Spath, P.L.; Lane, J.M; Mann, M.K; Amos, W.A. (April 2000). Update of Hydrogen from Biomass - Determination of the Delivered Cost of Hydrogen. NREL Milestone report.
Suresh, B.; Gubler, R.; Sasano, T. (2001). "Hydrogen." Chemical Economics Handbook Product Review, SRI International, Menlo Park, CA. Report number 743.5000.
Wender, I. (1996). "Reactions of synthesis gas." Fuel Processing Technology 48(3): 189-297. |
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