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Improving Process Performances in Coal Gasification for Power and Synfuel Production M. Sudiro,*,† A. Bertucco,† F. Ruggeri,‡ and M. Fontana§ Department of Chemical Engineering (DIPIC), UniVersity of PadoVa, Italy and Foster Wheeler Italiana Spa, Milan, Italy ReceiVed October 18, 2007. ReVised Manuscript ReceiVed July 23, 2008
This paper is aimed at developing process alternatives of conventional coal gasification. A number of possibilities are presented, simulated, and discussed in order to improve the process performances, to avoid the use of pure oxygen, and to reduce the overall CO2 emissions. The different process configurations considered include both power production, by means of an integrated gasification combined cycle (IGCC) plant, and synfuel production, by means of Fischer-Tropsch (FT) synthesis. The basic idea is to thermally couple a gasifier, fed with coal and steam, and a combustor where coal is burnt with air, thus overcoming the need of expensive pure oxygen as a feedstock. As a result, no or little nitrogen is present in the syngas produced by the gasifier; the required heat is transferred by using an inert solid as the carrier, which is circulated between the two modules. First, a thermodynamic study of the dual-bed gasification is carried out. Then a dual-bed gasification process is simulated by Aspen Plus, and the efficiency and overall CO2 emissions of the process are calculated and compared with a conventional gasification with oxygen. Eventually, the scheme with two reactors (gasifier-combustor) is coupled with an IGCC process. The simulation of this plant is compared with that of a conventional IGCC, where the gasifier is fed by high purity oxygen. According to the newly proposed configuration, the global plant efficiency increases by 27.9% and the CO2 emissions decrease by 21.8%, with respect to the performances of a conventional IGCC process. As a second possibility, the same gasifier-combustor scheme is coupled with a coal-to-liquid (CTL) process to convert the syngas into synthetic fuels by a FT reactor. It is shown that, if compared with a conventional CTL plant, the mass yield of liquid synthetic fuel is increased by 39.4%, the CO2 emissions per unit of liquid fuel are decreased by 31.9% and energy efficiency increases by 71.1%.
1. Introduction In the 20th century the use of oil dominated the process industries, and new chemical technologies were developed in substitution of older coal-based organic chemistry processes. Simultaneously, the human impact on the natural world has been particularly disturbing for the last 50 years. Among other effects, the global use of energy has increased by approximately 70% from 1971, and it is foreseen to increase by more than 2% per year for the next 15 years. This means that greenhouse gas emissions could increase by 50% if drastic actions are not taken to obtain both a greater energy efficiency and a partial switch of energy production from fossil to renewable sources.1 It is also clear that the world fossil fuels reserves, which currently provide about 85% of the total energy demand, are not infinite, so it is time to look for a replacement of these energy sources. This is especially true for oil reserves, which are being consumed at such a high rate that it is already crucial nowadays to find out a replacement for oil as energy source, especially for transportation purposes (a sector that is almost totally dependent on refined oil, more than 50% of which is used to * Corresponding author e-mail:
[email protected]; phone: +390498275472; fax: +39-0498275461. † University of Padova. ‡ Foster Wheeler Italiana Spa. § Independent Consultant. (1) http://lists.peacelink.it/lavoro/msg00668.html.
this scope). Estimates of oil availability span from 40 to 60 years at the present rate of consumption.2 In any case, the International Energy Agency (IEA) foresees that fossil fuels will continue to dominate energy supplies in 2030, meeting more than 80% of the projected increase in primary energy demand. The transportation sector is expected to account for two-thirds of the growth, and global daily oil demand will possibly reach 115 million barrels per day in 2030.3 Considering the world’s insatiable appetite for energy and oil, the only reasonable large-scale conventional source left in the medium term will have to be coal. In fact, the currently known reserves of coal exceed those of crude oil by a factor of 25.4 At present, coal is a major source of energy, accounting for ∼25% of the world energy supplies and ∼40% of the world electricity generation.5 It is suggested that coal will continue to play an important role in meeting the world’s increasing energy demands in the future. However, in order to exploit its use it is necessary to reduce the considerable emissions of CO2, SOx, NOx, particulate matter, and hydrocarbons generated by coalbased processes, which lead to air pollution and climate change. In summary, the urgent need of exploiting coal to produce both electric power and liquid fuels is a strong motivation to study how to improve the related production processes. (2) www.ifp.fr/IFP/en/files/cinfo/IFP _Panorama05_06-CarburantsalternatifsVA. pdf (3) Lloyd Wright, T. Gasification 07, a Supplement to Hydrocarbon Processing; 2007; p 4. (4) Dry, M. E. Catal. Today 2002, 71, 227–241. (5) Yuehong, Z.; et al. Energy ConVers. Manage. 2006, 47, 1416–1428.
10.1021/ef800293h CCC: $40.75 2008 American Chemical Society Published on Web 09/17/2008
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Electricity production is a major challenge. The growing electricity demands foreseen in the coming years imply an expansion in the current power plant fleet. The achievement of this expansion, coupled with the need for significant reductions in greenhouse gas (GHG) emissions is a challenging task. Cleaner and more efficient fossil fuel-based power plant designs combined with CO2 capture and sequestration technologies constitute an attractive option to meet this challenge in the nearto-medium term. Integrated gasification combined cycle (IGCC) power plants have the lowest carbon dioxide emissions among coal power plants; if combined with CO2 capture by means of a physical absorption system, substantial GHG emissions reductions can be attained.6 Therefore, IGCC type installations are being developed worldwide to promote a cleaner and more effective use of coal. The numerous benefits of IGCC technology, such as high thermal efficiency; ultralow NOx, SOx, and solids emissions; as well as marketable byproduct coproduction, are driving it to become commercially competitive against conventional coalfired power plants. Furthermore, IGCC plants can reliably produce hydrogen and carbon dioxide by incorporating a catalyzed watersgas shift reaction in the process.6 Numerous private companies and research agencies worldwide are increasingly recognizing the above facts. For instance, the US Department of Energy’s FutureGen program has recently committed US $1 billion to build a 275 MW advanced IGCC plant by 2008.6 In their present form, IGCC systems, which can be also operated with feedstocks other than coal, are basically a combination of gasification with a power plant based on a gas turbine block, a heat recovery steam generator (HRSG), and a steam turbine (combined cycle plant). The advantage of integrating gasification into these plants is to couple the conversion of solid and residual liquid fuels into a form that gas turbines can accept (the syngas), making the best use of heat sources and sinks of the two processes. With a gasifier and the proper gas treating train behind it, one obtains a fuel that can be combusted as simply and as environmentally friendly as natural gas.7 Current IGCC systems include an air separation unit (ASU), a gasification, a gas cleanup system, and a gas turbine combined cycle power block and feature competitive efficiency and lower emissions if compared to conventional power generation technology.8 Such systems are not in widespread commercial use yet, mainly due to higher investment compared with conventional plants, and opportunities remain to be explored to improve system feasibility and capital expenditure reduction via improved process integration. Another obstacle to the success of IGCC plants has been, in some instances, the failure to recognize early enough the necessity to integrate two industrial cultures of different origin, viz. the one of process plant operation and the one of power plant operation.9 Typical efficiencies of the IGCC plant are 38-43%.7 The efficiency of gasification is at best about 80%, which, assuming also at best a 60% for the combined cycle (CC), implies that the overall efficiency of an IGCC will not be higher than 48%. Further, for all conventional gasifiers an oxygen plant is required and the gas treating also needs energy; hence, the efficiencies of the best first-generation plant are all below 45%. (6) Ordorica-Garcia; et al. Energy ConVers. Manage. 2006, 47, 2250– 2259. (7) Higman, C. , Van Der Burgt. M. Gasification.: Gulf Professional Publishing (Elsevier): Burlington (USA),2003. (8) Frey, H. C.; Zhu, Y. EnViron. Sci. Technol. 2006, 40, 1693–1699. (9) Lloyd Wright, T. Hydrocarbon Processing 2007, 13.
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On the other hand, a great challenge is also represented by the demand of fuels with high volumetric energy density, that is, liquid fuels, for transportation purposes (cars, trucks, ships, and planes). Biofuels, such as bioethanol and biodiesel, are receiving a lot of attention but are expected not to fulfill more than a few percent of the needs. Another viable alternative, that is, hydrogen, seems quite far away to be ready for large-scale application, as it is still under development at both the scientific and technological levels; in addition, the infrastructures and the logistics for fuel distribution will have to be rebuilt and changed if hydrogen becomes the main fuel for transportation. So, it is hard to predict that the switch from the present system to a new one will take place before 50-60 years from now. Under these circumstances, it is crucial and urgent to find an alternative to sustain the present transportation network in the transition period between now and then. A major candidate to bridge the gap is represented by liquid synthetic fuels. A number of gas-to-liquid (GTL) plants, where diesel and gasoline are produced from natural gas via a steam reforming process followed by water gas shift reactor and Fischer-Tropsch synthesis (FT), has recently been put into operation; one example is a plant in Qatar announced in July 2006 by Qatar Petroleum (QP) and Royal Dutch Shell for a production of 140 000 barrels of GTL products per day.10 A similar synthetic fuel production pathway can be devised starting from coal, via a process known as coal-to-liquid (CTL): it includes a coal gasification step, followed by a shift to adjust the H2/CO molar ratio in order to enter the FT reactor.11 Note that the process can be simplified as the shift can be avoided by performing the gasification with suitable amounts of both steam and methane.12 In spite of the high scientific interest toward CTL plants,13 industrial applications are still basically missing. A large scale plant of this kind has been operated since 1980 in South Africa, because of a previous international oil embargo, and the related technology was developed right after the second world war by the South African Coal Oil and Gas Corporation (today, Sasol). This plant uses coal gasification and FT synthesis as the basis of its synfuels and chemicals production. With the extensions made in the late 1970s, Sasol is the largest gasification center in the world.7 More recently, a number of CTL units are currently under design and construction in China: one of them, a $2 billion CTL plant, is already being built and is expected to be started soon.14 In summary, even though there are technologies other than gasification to obtain power and steam from coal, petroleum, and heavy oils, such as supercritical pulverized coal boilers and circulating fluidized bed boilers, these generally have air emissions significantly higher than gasification.15 Therefore, coal gasification seems a viable substitute for many processes that typically use natural gas as a feedstock, such as power generation, cogeneration of power and steam, production of hydrogen, ammonia, methanol, and other chemicals, such as FT fuels. (10) http://www.shell.com/home/content/aboutshell-en/our_strategy/major_projects/ pearl_gtl/ pearl_gtl_01112006.html. (11) Sudiro, M. and. Bertucco. A. Production of Synthetic Gasoline and Diesel Fuel by Alternative Processes using Natural Gas and Coal: Process Simulation and Optimization. In the Proceedings of the 20th ECOS International Conference Padova, Italy, June 25-28, 2007; pp 1361-1368. (12) Sudiro, M.; Bertucco, A. Energy Fuels 2007, 21, 3668–3675. (13) http://www1.eere.energy.gov/vehiclesandfuels/epact/pdfs/plg _docket/ statement_lowell_miller.pdf. (14) Coal-to-Liquids Coalition, Economy: CTL for a stronger economy. http://www.futurecoalfuels.org/economy.asp. (15) Fair, D. Supplement to Hydrocarbon Processing 2007, 14–15.
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The aim of this work is to develop and test by process simulation several gasification alternatives in order to improve the coal gasification process performances, to avoid the use of pure oxygen, to obtain a syngas free of N2 dilution, and to reduce the overall CO2 emissions.
literature related to this topic is quite rich and is continuously being updated, as can be seen, for example, in refs 21-23. The distinctive advantage of these staged gasification plants is the separation of combustion exhaust gases from gasification products. This allows the syngas to have high heat values and low intake of inert gases (usually N2 and CO2). When gasification with air is carried out directly in one stage, the presence of nitrogen decreases the efficiency, because of heat required by inerts to reach the reaction temperature: furthermore, nitrogen is contained in the product stream, where it reduces the heat value to levels that make subsequent combustion or reaction much more difficult. If we want to avoid this problem but keep using air instead of high purity oxygen, then the reactions of combustion and gasification must be run in different locations. The separation between the two sections, other than being spatial, with two physically distinct reactors or reaction zones may be also based on a time sequence, by means of a batch cyclic process.24 In this work, a dual-fluidized-bed gasification process has been considered and simulated in order to produce electricity via an IGCC process or synthetic fuels via a FT synthesis.
2. Dual-stage Gasification: State of the Art
3. Gasification with Air: Reference Process
In coal gasification, technologies that are able to separate the drying, devolatilization, gasification, and combustion zones are called “multi-stage” processes. Various “multi-stage” processes are currently under development or are already in operation. A suggested approach is to divide the mass stream into at least two partial streams that are processed in several parallely arranged reactors.16 The heat needed for gasification can be separately produced using air for combustion without affecting the gas quality of the gasification reactor, as shown in Figure 1. Combustion and gasification reactors are kept separated and are interconnected by heat transfer only. In principle, a pyrolysis stage is necessary to split the fuel into gas and char. To provide the heat necessary for autothermal operation, the char or part of the pyrolysis gas can be oxidized outside of the pyrolysis reactor. This principle can be realized in at least two ways: by using one reactor or by using two reactors. The first configuration is proposed, for instance, by Murakami.17 On the other hand, an example of a two-reactors system is the FERCO’s SILVAGAS process, which consists of two circulating fluidized beds as the primary process vessels. One is a gasification reactor where the biomass is converted into gas and residual char, and the second is a combustion reactor that burns the residual char to provide heat for gasification. Heat transfer between reactors is accomplished by circulating sand between the two sections. This kind of system is claimed to perform very well.18 A commercialscale demonstration plant of 200 t/day capacity of biomass feed is currently in operation.19 To our knowledge, this plant has been tested only with biomass and not with coal. Other “multistage” processes based on the concept of Figure 1 are the socalled “staged reforming” and the two-stage parallel-arranged gasifier Herhof-IPV-Verfahren.16 A detailed and interesting review on dual-fluidized-bed biomass gasifier has been published recently.20 Note that the
Figure 2 shows a block flow diagram of the theoretical twostage configuration in a continuous mode of operation, which has been taken as the reference for our process simulation. We have assumed the use of two fluidized beds. In the first one (combustor of Figure 2), combustion of coal with air occurs; in the second one (gasifier of Figure 2), coal is gasified with steam. The heat needed by the second endothermic reaction is supplied by a thermal vector, that is, an inert, that continually moves between the two sections. Pressures in the two reactors must be different, both to avoid the contamination of syngas, and to keep the two environments apart from each other. The fluidization agent, in the oxidative stage, is the same air used for the pneumatic transport of the inert solid, whereas in the gasification stage it is steam, introduced saturated or, better, superheated at the gasifier pressure. In our process, coal and saturated steam at 20 bar are fed to the gasifier. The heat carrying the mixture of inerts and ash from the combustor enters the gasifier from the top of the reactor. The syngas produced exits from the top whereas unreacted char and inerts exit from the bottom by gravity and are carried back to the combustor by means of compressed air. In the combustor, coal is burnt to supply the heat needed to take the inert back to the temperature of combustion. Syngas is routed to a cyclone to remove dust and inerts for which, because of unavoidable losses, a makeup is needed. A gas expander is fed by combustion gases and operates between the combustor pressure and near-atmospheric conditions. Power from the expander is recovered to run the air compressor. In principle the coupling between air compressor and gas expander may be realized by a conventional gas turbine cycle, with combustion carried out outside the machine. In practice, the use of a real gas turbine would heavily constrain the scheme, as well as the gas physical conditions (pressure, temperature, residual particle content, etc). Air stoichiometric flow rate is fixed by the reaction, where an excess of 10% has been assumed to reach a complete combustion. The resulting air flow has been checked to be
Figure 1. Two-stage double-line gasification approach, adapted from 16.
(16) Hamel, S.; et al. Energy 2007, 32, 95–107. (17) Murakami, T. Fuel 2007, 86, 244–255. (18) Guangwen, X.; et al. Ind. Eng. Chem. Res. 2006, 45, 2281–2286. (19) http://fercoenterprises.com/downloads/asme010604.pdf; http:// fercoenterprises.com/ downloads/amsterdam021619.pdf. (20) Corella, J.; et al. Ind. Eng. Chem. Res. 2007, 46, 6831–6839.
(21) (22) (23) (24)
Matsuoka, K.; et al. Energy Fuels 2008, 22, 1980–1985. Deng, Z.; et al. Energy Fuels 2008, 22, 1560–1569. Cousins, A. Energy Fuels 2008, ASAP article. Levenspiel, O. Ind. Eng. Chem. Res. 2005, 44, 5073–5078.
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Figure 2. Scheme of the gasification process with air using two reactors.
consistent with hydrodynamic transport of solid inerts and fluidization requirements. 4. Gasification with Air: Preliminary Analysis As a first calculation, a theoretical study at high temperature has been done in order to perform a comparison with conventional gasification with oxygen, which occurs at high temperatures (e.g., Texaco gasifier works up to 1500 °C7). In this theoretical study a gasification temperature of 1100 °C has been assumed, considering that the combustion reactor temperature is around 1400 °C. 4.1. Inert Flow Rate. The inert solid mass flow rate W needed for the pneumatic transport is calculated from the following relation, Q ) Wcp∆T
(1)
where Q is the thermal power needed by the gasifier (kW), W is the inert mass flow rate (kg/h), cp is the inert’s specific heat (kJ/kg°C), and ∆T is the difference between the gasifier temperature and the combustor temperature (°C). The value of specific heat for inert, for example, sand, at a temperature of 1000 °C is 1.32 kJ/kg°C,25 and its variation with temperature is low, so an assumption of constant specific heat with temperature is reasonable. Values of Q and ∆T are obtained from process simulation. The choice of sand as thermal carrier depends on material cost and supply. Figure 3 shows the relationship between the inert mass flow rate needed for the thermal transfer and the temperature difference between the gasification and combustion sections. The curve parameter is the gasification temperature. It is clear that the mass flow rate increases quickly with the decrease of the temperature difference. To have a technically viable value, this difference should be around 200 °C; consequently, the maximum temperature for the gasification section is on the order of 1100 °C. (25) Perry, R. H. and Green. D. W. Perry’s Chemical Engineers’ Handbook, 7th ed; McGraw-Hill Book Co.: New York, 1998. (26) Ong’iro, A. O.; et al. Heat RecoVery Systems CHP 1995, 15, 105– 113.
The simulation, from which Figure 3 was obtained, has been performed by assuming that coal consists of only C (graphite) and that the gasification reactions do not achieve the equilibrium conditions. To take into account this fact, the “temperature approach approximation” was used. The temperature approach is defined as the difference between the temperature at which the chemical equilibrium is calculated and the actual reactor temperature. Thus, the nonequilibrium compositions are calculated as equilibrium values at a lower temperature, rather than going through kinetic calculations that are not warranted at a preliminary stage of assessment. The following compounds have been assumed as products: H2, CO, CO2, H2O, CH4, and N2 as an inert. Two independent reactions have been selected: CH4 + H2O T CO + 3H2 [methane steam reforming] (2) CO + H2O T CO2 + H2 [water-gas shift]
(3)
For the reaction of steam reforming of methane, eq 2, a temperature approach of 200 °C was assumed, whereas for the water-gas shift reaction, eq 3, the temperature approach was considered to be negligible. 4.2. Syngas Yield. The maximum temperature for the gasification section, which is on the order of 1100 °C as concluded above, is not far from the one that gives the maximum achievable syngas yield ηC, which is defined by eq 4, ηC )
nH2 + nCO nC
(4)
where nH2 and nCO are molar flow rates of H2 and CO produced in the gasifier, respectively, and nC is the molar flow rate of carbon (C) consumed in the gasifier and in the combustor. In fact, Figure 4 displays the (iso-ηC) curves versus the temperature of the two reactors, with the constraint that the H2/ CO ratio out of the gasifier is around 2. The maximum of the curve suggests the minimum value of inert circulation to obtain the related yield. The gasification temperature corresponding to the peaks is almost constant and is around 1070 °C for all values of yield considered. Also reported are the mass flow ratios between inert circulation and total carbon used. These are between 20 and 30 for the range of yields shown in the diagram.
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Figure 3. Inert mass flow rate vs the temperature difference between gasification and combustion section in order to obtain a H2/CO molar ratio of 2 (Figure obtained using pure graphite (C) and not coal within the simulation).
Figure 4. Relationship between yield (ηC) and temperature of gasification and combustion (Figure obtained using graphite (C) and not coal). Dotted lines show the (H2 + CO)/Ctot molar ratio (values from 0.91 to 0.95), and solid lines show the mass ratio between inert flow rate and Ctot (values from 20 to 30).
The obtained results confirm that the operating condition in the gasifier corresponds to a minimum value of inert circulation, independently of the yield value. This is good because a minimum value of inert flow rate implies lower operating costs. 5. Simulation of Coal Gasification in a Dual-bed Configuration The operating temperature in a fluidized bed should be kept lower than 1000 °C in order to avoid ash softening and
agglomeration in coal processing. Combustion simulations have thus been carried out assuming a bed temperature of 980 °C. For the dual bed to operate under the conditions outlined above, that is, with gasification endothermicity sustained by sensible heat transferred by solids circulation, the temperature in the gasifier should be low enough to require a reasonably low circulation. Literature7 indicates that gasification can take place at temperatures as low as 700 °C.
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Table 1. Main Elemental Chemical Composition (in wt %), Low Heating Value (in MJ/kg), and Elemental Molar Ratios of H/C and O/C for Bituminous Coal, South Africaa. proximate analysis
% mass ar
ultimate analysis
% mass on mafb coal
fixed carbon volatile matter water ash LHV (MJ/kg maf coal)
51.3 32.7 2.2 13.8 34
C H O N S
83.8 4.8 8.4 2.0 1.0
a Higman, C., M. Van Der Burgt (2003). Gasification. Gulf Professional Publishing (Elsevier), Burlington (USA). b Moisture ash free.
Table 2. Comparison between Dual-stage Coal Gasification and Conventional Gasification, Aimed at a Product Gas with H2/CO )2 dual-stage gasification Kg CO2/kg H2 + CO steam/carbon molar ratio steam/H2 + CO molar ratio H2 + CO/C molar ratio H2/CO molar ratio thermal yield % inerts flow rate (kg/h) inerts/Ctotal on weight basis product gas (% mol. dry basis) H2 CO CO2 CH4 N2 H2S + COS
conventional gasification + shift
1.7 1.7 1.0 1.2 2.0 78.2 134543 48.7
1.6 0.8 0.5 1.4 2.0 76.4 a
54.0 27.0 13.0 5.4 0.4 0.2
48.3 23.8 27.4 0.0 0.5 0.0
a All the parameters, except thermal yield, are evaluated at the output of a water-gas shift where the H2/CO molar ratio equal to 2 is obtained. Thermal yield is evaluated after the gasification section because this parameter is always relative to the gasification section.
Table 3. Efficiency of the Plant Equipment ηisoentropic ηmechanical
gas turbine
steam turbine
compressor
0.92 0.99
0.88 0.975
0.85 0.9
Although it is theoretically more convenient to operate at higher temperatures if a syngas with a high yield in H2 + CO and small methane content must be produced, when syngas is routed to downstream chemical conversions (such as ammonia or methanol production) it is possible to perform gasification at a lower temperature. For electric power production, the gasification temperature may be as low as practical. At lower temperature, the syngas obtained is indeed heavier and richer in methane and other heavier hydrocarbons. This is not a problem, because methane usefully contributes to syngas combustion ahead of the gas turbine. In our simulation, a gasification temperature of 850 °C has been used. The scheme of Figure 2 has been simulated using Aspen Plus. Material and energy balances were accounted for and solved for every process unit, whereas no chemical kinetic models were considered in the reactor simulation. A coal with a fixed composition, reported in Table 1, was used in the model. A chemical equilibrium condition has been assumed for the gasifier, which was simulated by two units: a yield reactor and (27) Donatini, F. Supercritical Water Oxidation of Coal in Power Plants with Low CO2 Emissions. In Proceedings of ECOS07 20th International Conference on Efficiency, Cost, Optimization, Simulation and EnVironment Impact of Energy Systems, Padova, Italy, June 25-28, 2007; Volume II, pp 1315-1322.
an equilibrium reactor at fixed temperature. In the first one, coal is broken down into its elements H2, N2, O2, S, C (solid), ash, and water as moisture, whereas in the second unit the equilibrium compositions are calculated, based on Gibbs free energy minimization, and assuming as products the following compounds: H2, CO, CO2, H2O, CH4, O2, C(solid), S(solid), H2S, COS, and N2 (inert). In Table 2, results of simulation are summarized and are compared with conventional gasification with oxygen; both processes are aimed to obtain a syngas with H2/CO ) 2. As indicated in Table 2, the amount of CO2 released per kg of (H2 + CO) produced is slightly higher than that of conventional gasification but thermal efficiency is higher, neverthless expensive pure oxygen is not required in the dual bed configuration. Thermal efficiency, known as cold gas efficiency, is defined by eq 5. Cold gas efficiency [%] ) Heating value in product gas [MW] × 100 (5) Heating value in feed stock [MW] The heating values used in this work are lower heating values (LHV). 6. Double-stage Gasification Combined with an IGCC Plant A process simulation model was developed for IGCC systems with double-stage gasification, thus avoiding the ASU unit, with reference to Figure 5. The syngas from the gasifier is cooled and sent to a purification section in order to remove ash and then H2S and COS; a part of the heat recovered cooling the syngas is used to generate high pressure steam at 100 bar. The syngas is fed to a combustor with air (excess of about 250%), and combustion gases at 1285 °C are sent to a gas turbine to produce electric power. The gas is expanded down to atmospheric pressure and, to recover its high energy content (573 °C), it is used to produce more steam at 100 bar in a heat recovery steam generator (HRSG). The steam from this section and from syngas cooling is sent to a steam turbine to produce more electric power. Exhaust steam is condensed and then pumped to produce high pressure steam. A part of the steam generated in this way is used in the gasifier. In addition, gas from the coal combustor can also be sent to a gas expander to produce electric power. Values of efficiencies for gas and steam turbines and compressors, used in the simulation, are summarized in Table 3 (taken from ref 26 for gas turbine and from ref 27 for steam turbine and compressors). The conventional IGCC process with oxygen has also been considered, according to the block flow diagram of Figure 6. Note that the difference between Figures 5 and 6 is in the syngas generation section: in the first case there is a dual-bed gasifier, whereas in the second one a conventional gasifier is used, with pure oxygen as feed. Results of the simulations are summarized in Table 4. Here the cold gas efficiency, in the case of conventional gasification with oxygen, has been calculated taking into account also the electric power needed for the ASU unit. The use of oxygen requires about 380 kWh per ton of oxygen produced by this unit.28 (28) Prins, M. J.; et al. Energy 2007, 32, 1248–1259.
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Figure 5. Block flow diagram of the IGCC plant simulated with a double-bed gasifier, with all main results and mass flow rates of the input streams.
Figure 6. Block flow diagram of the IGCC plant simulated with a single gasifier fed by coal, steam, and oxygensproduced by an ASU unitswith all main results and mass flow rates of the input streams. Table 4. Comparison between Performance of an IGCC Plant Coupled with a Dual-stage Gasification and a Standard IGCC Plant.
global plant efficiency % cold gas efficiency % kg CO2/MWh produced Inert flow rate (kg/h) Inerts/Ctotal(weight basis)
coal energy input gas turbine power steam turbine power ASU power need auxiliary power needs net power output
dual-stage gasification
gasification with oxygen
43.1 80.1 754.0 117001 44.0
33.7 73.4 964.3
MW
MW
30.0 22.3 3.5
24.9 12.0 2.9 1.0 5.6 8.3
12.9 12.9
It is clear from the results in Table 4 that the performances of the process are improved with the newly proposed configuration. In fact, the global plant efficiency, defined by eq 6, Global plant efficiency [%] ) Net power produced [MW] × 100 (6) Feed stock energy input [MW] increases by about 27.9% and the CO2 emissions decrease by about 21.8%, compared with a conventional IGCC process. Also, the values of cold gas efficiency are higher than
Table 5. Comparison between Dual-stage Gasification Applied to a CTL Process and a Conventional CTL One11 kg CO2/kg synfuel mass yield % global energy efficiency %
dual-stage gasifier
conventional CTL
2.88 45.31 70.5
4.23 32.50 41.2
conventional IGCC (80.1% for dual bed vs 73.4% for conventional gasification). 7. Double-stage Gasification Combined with a CTL Plant Synthesis gas from a coal gasification processes can be used for the consequent production of chemical feedstocks or hydrocarbon liquids via FT synthesis. To convert coal into synthetic fuels, the configuration with two separate reactors (gasifier-combustor) has been coupled with a CTL process to convert the syngas into synthetic fuels by means of a FT reactor. Figure 7 shows the block flow diagram of such a process. The model used for simulation of this process is the same developed for the conventional CTL one, discussed elsewhere.11 The dual gasifier consists of two fluidized beds (e.g., bubbling fluidized bed, BFB), so temperatures are lower than in conventional gasifiers. Because the syngas obtained is rich in methane (with a small amount of heavier hydrocarbons), before entering FT these compounds must be removed from the syngas stream in order to avoid decreasing of the yield of FT reactions. The methane removal can be
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Figure 7. Simplified block flow diagram of a CTL plant simulated with a double-bed gasifier.
obtained using the technology proposed by Bonnot29 based on a pressure-swing-adsorption (PSA) unit with activated carbon. In this way, the CTL process produces not only liquid fuels but also synthetic natural gas (SNG). Table 5 summarizes simulation results, in terms of mass yield, CO2 production of the global processes, and energy efficiency of the process, defined by eqs 7-9: mass yield ) synfuels(GPL - gasoline - diesel - SNG)[kg/h] × 100 (7) feedstock(coal)[kg/h] CO2 production ) CO2 generated[kg ⁄ h] (8) synfuels(GPL - gasoline - diesel - SNG)[kg ⁄ h] Global energy efficiency [%] ) Heating value in synfuels [MW] × 100 (9) Heating value in feedstock [MW] where the heating value is the LHV, and synfuels are LPG, gasoline, diesel, and SNG in dual-bed gasification coupled with CTL and are LPG, gasoline, and diesel in a conventional CTL process. The differences with respect to such a CTL process simulated elsewhere11 are also reported in Table 5. Compared with a conventional CTL, the mass yield of synthetic fuel (eq 7) is increased by 39.4%, and the CO2 emissions per unit of fuel (eq 8) are decreased by 31.9%, whereas the global energy efficiency (eq 9) is increased by 71.1%. We note that CTL could be a useful solution from the economic point of view if it is located close to the extraction site of coal. In this way, only the final products, that is, liquids and gases with high volumetric energy density, would need to (29) Bonnot, K.; et al. Chem. Eng. Res. Des. 2006, 84, 192–208.
be moved, and the environmental issues due to the transportation of coal could be avoided. 8. Conclusions The technical evaluation of a number of alternatives with respect to the conventional coal gasification was carried out in order to improve the process performance, to avoid the use of pure oxygen, and to reduce the overall CO2 emissions. The process flow-sheets considered are based on dual-bed reactors scheme: a gasifier and a combustor, which are thermally coupled by the circulation of an inert solid. Aspen Plus models of dual-bed configurations were developed, and the efficiency and overall CO2 emissions of the process were calculated and compared with conventional gasification. The coupled reactors scheme was then applied to an IGCC process, which was simulated and compared with a conventional IGCC one, which uses high purity oxygen as oxidizing agent and is operated at high temperature. With the new process, the global plant efficiency increased by 27.9% and the CO2 emissions decreased by 21.8%. Finally, the gasifier-combustor system was coupled with a CTL process to produce synthetic fuels via FT synthesis. It was shown that, with respect to a conventional CTL plant, the mass yield of synthetic fuels is increased by 39.4%, the CO2 emissions per unit of liquid fuel are decreased by 31.9%, and the energy efficiency increases by 71.1%. The new process configuration, here considered to improve conventional coal gasification in a single bed using oxygen, can represent a valuable alternative route to obtain syngas both for electric power generation and for synthetic fuels production. EF800293H
