aba process for microwave induced plasma gasification

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Ave. Eugenio Garza Sada 2501 Sur Col. Tecnológico C.P. 64849

Monterrey, N.L., México Tel. 8358-2000 y 8358-1400

TECHNOLOGICAL STATUS

“ABA PROCESS FOR MICROWAVE INDUCED PLASMA GASIFICATION”

MADE BY

CENTRO DE CALIDAD AMBIENTAL ITESM

CAMPUS MONTERREY

Attention:

Ing. Antonio León Sánchez ABA Research S.A. de C.V.

CONFIDENTIAL

Monterrey, N. L. October, 2011

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Executive Summary Upon request from ABA Research, S.A de C.V., an evaluation was performed on the ABA Process for Microwave Induced Plasma Gasification. For this evaluation, comparative analyses were performed among: foundations of similar technologies, evaluation of the results of experimental tests with different types of materials, computerized modeling, and potential applications for its exploitation. Presently, the technology is in the frontier of state-of-the-art technological developments. The results of the present evaluation are based on experimental tests performed on a medium-scale industrial plant (with capacity to process up to 10 metric tons per day), designed for the realization of pilot tests with raw materials of diverse types. The set of tests performed at such plant during the last 4 years show potentially lower energy consumption when compared to other gasification processes. Considering that the chemistry in the reactions that take place in the process of gasification is the same independently of the process being used, it is to be expected that there will be no significant differences in the composition of the syngas resulting from this process when compared with other technologies. However, the flow (or volume) of syngas would be influenced mainly by the characteristics of the materials to be treated. Several modeling studies following a variety of methods confirm the experimental results that were observed at the present scale, as well as the published results of other research groups. It is recommendable to verify the results of the present process on a continuous process with the purpose of demonstrating experimentally the increase in the real efficiency of the process, and the impact on its economic feasibility. It is to be expected that increases in the efficiency of the process may be achieved as it is scaled to larger capacities. Being this a state-of-the-art technology and realizing its potential, it is highly recommendable to continue the effort of investing in it, in order to reach the status of consolidated technology in the short run.

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Background ABA Research, S.A. de C.V. is a Mexican company founded in 2006 with the specific purpose of developing new technologies. Its origin dates back in the decade of 1990, when a group of independent Mexican scientists of different specialties, who had previously acted as researchers in different educational institutions undertook research work on this field. By their own initiative, they joined in the search for specific solutions to the production and generation of alternative non-conventional energy based on waste of urban or industrial origin, as well as biomass. Through the years, ABA Research has successfully developed the following products and achievements: 2006-2007 Development of four generations of lab-scale microwave induced plasma gasification

reactors. 2007 Development of a microwave induced plasma gasifier (Plasmatron). 2008 Development, construction and start-up of a microwave induced plasma gasification plant

with capacity to process up to 10 tons per day. 2008-2011 Development of numerous pilot tests for gasification of diverse raw materials. 2007 Patent application presented to IMPI, number MX/A/2007/008317. 2008 Patent application presented to PCT, number PCT/MX2008/000081. 2008 Patent application presented to US Patent Office, number 20100219062. 2008 Patent application presented to European Patent Office, number 08778971.5. 2009 Publication of Patent WO2009008693-A1 for the gasification process by WIPO (World

Intellectual Property Organization). The distinctive characteristic of the technology is the use of microwaves as source of energy for the gasification of mostly carbon base materials and with carbon-hydrogen in its molecular structure, which are predominantly converted into a gas stream whose main components are hydrogen and carbon monoxide. This gaseous mixture is known by the name of syngas. This product, the syngas, has a wide range of industrial applications, including: power and steam generation, production of synthetic gasoline and diesel, production of basic petrochemical substitutes and fertilizers, among others. Foundations • Typical Gasification Process. Gasification is a thermal process that takes place in a reductive atmosphere for the conversion of carbon base materials into a gaseous stream composed predominantly of hydrogen and carbon monoxide, known as syngas. Commonly, the reductive atmosphere is attained by feeding a mass, typically of oxygen, in a stoichiometric relation to the mass of carbon contained in the material to be treated. The global chemical reaction that occurs is a combination of exothermic and endothermic reactions, where the exothermic reaction produces the necessary heat that allows the endothermic reaction to produce the desired mixture of gases according to the following equations: Exothermic Reaction: HC + O2 CO2 + H2O + Heat (1) Endothermic Reaction: HC + H2O + Heat H2 + CO (2)

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Where HC represents the source of carbon • Reformation of crude syngas. In order to improve the ratio of hydrogen and carbon monoxide in the syngas, it is common to add a reactive gas to the process, such as steam, which will react with the incandescent carbon according to the following equation: C + H2O CO + H2 (3) • Conventional Gasification In the conventional gasification process, the combustion (exothermic) reactions are controlled by the addition of a stoichiometric amount of air or oxygen such that the combustion supplies only the necessary amount of energy in order to predominantly produce the syngas (endothermic reaction). Typical reaction temperatures for this process fluctuate between 800°C and 1,600°C. The solid residue of the process is ash or slag, and it depends on the temperature of the process being used. Normally, this residue is dispatched to land fields for its final disposal. • Plasma Arc Gasification The Plasma Arc gasification process is a thermal process of high temperature created by an electric arc similar to a torch where a gas is accelerated producing plasma. The typical temperature in a Plasma Arc gasification process fluctuates between 7,000°C and 15,000°C in the zone closest to the torch and is rapidly diffused towards the reactor walls providing a reaction temperature profile which is higher than is required by conventional gasification. Argon is normally used as the plasma gas generator; in certain cases air, oxygen or nitrogen is used for the same purpose, when carrying the process to an industrial scale. Separately to the plasma generator, the process also includes the addition of steam in order to increase the ratio of hydrogen and carbon monoxide in the syngas. The solid residue of the process is a vitrified slag composed of metals encapsulated in a matrix of molten silica. This slag does not produce leach and exceeds the highest standards of environmental control, and can therefore be recycled in the manufacture of different ceramic products including: tile, construction, insulating and decorative materials. • Microwave Induced Plasma Gasification There is little information regarding the phenomenon of microwave induced plasma generation. A research group from the Tokyo Institute of Technology reported in 2003 the process of reformation of hydrocarbons aided by steam plasma generated by a discharge of microwaves (Appendix 1). The lab-scale experiment used a microwave supply source at a frequency of 2.45 GHz. The experimental basis included measurement equipments in order to identify the generated species responsible for the observed phenomena. For the generation of plasma, the energy from the microwave source generates vibration in the chemical bonds of the steam molecules causing a substantial increase in temperature. There are no reports concerning the temperature reached by the process. Nevertheless, on the basis of modeling studies, it is estimated that it can achieve levels higher than 15,000°C. The chemical species detected in the experiment include free radicals of hydrogen (H.) hydroxyl (OH.) and oxygen (O., O2

.). Such species are highly reactive and explain the formation of products similar to those found in other gasification processes, even in the absence of pure oxygen. The research evaluated the reaction of hexane as a model molecule for hydrocarbons, resulting in the production of syngas of high purity. Considering that the temperature profile of microwave induced plasma gasification is similar to or higher than the Plasma Arc or plasma torch, the solid residue of the process would exhibit characteristics similar to those of a

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vitrified slag. Table 1 shows a comparison of the characteristic features of the conventional, Plasma Arc, and Microwave Induced Plasma Gasification Processes.

Table 1. Comparative Table of Different Plasma Generation Processes

Description of the ABA Process The continuous reactor for the ABA process is designed to operate at pressures ranging from 1 up to 28 bars, and at temperatures ranging from 1,000°C up to 1,300°C. The distinctive feature of the process lies in the design of the reactor and in the use of microwave plasmatrons. The design consists of two chambers placed one on top of the other. In its standard configuration, the first series of plasmatrons as well as the raw material intakes are located in the higher chamber. As the raw material reacts, it generates a stream composed of carbon monoxide and hydrogen, long hydrocarbon molecules, traces of carbon dioxide, and a solid fraction of incandescent carbon. This stream is transderred to the second chamber equipped with the second series of plasmatrons. In this chamber, super heated steam is added in a stoichiometeric relation. In this section, a reaction of reformation and rectification of the syngas takes place, increasing the ratio of hydrogen and carbon monoxide ensuring the production of gas rectified to syngas. The resulting gas stream from this second chamber is transferred to the cooling section where particles,

Parameter Conventional Gasification

Arc Plasma Microwave Plasma

Source Temperature 1,000‐1300 °C 7,000‐15,000 °C 7,000‐15,000°C

Reaction Temperature 1,000‐1,300 °C 1,000‐1,300 °C 1,000‐1,300 °C

Molecular Process Chemical Oxidation Physical Acceleration Vibrational and Physical Acceleration

Plasma Generator Fuel, O2 Electric Power, air, O2, Ar, N2

Electric Power Water Vapor

Oxidyzing Agent O2 Air, O2 Water Vapor

Oxidyzing Species O2 O2 OH., O+ radicals

Moisture Sensitivity High Medium Low

Residue Slag, Charcol Vitrified Slag Vitrified Slag

Energy Consumption Control

Constant Constant Variable

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sulphur, halogen, etc., are removed from the syngas. The solid fraction which does not react to syngas (metals, silicates, etc.) is ejected from the lower part of the reactor as vitrified slag. The sensible heat in these two fractions is recovered as steam. Applications In the previous sections, a description of the different gasification technologies was reviewed, as well as that corresponding to the ABA Process. In the following paragraphs, several ways of exploitation of the syngas are discussed. • Power Generation. Power generation is probably the first hand application for the exploitation of syngas, considering that existing electric power generation technologies can be adapted to burn syngas or mixtures of this gas with other fossil fuels. Currently, due to the increase in the cost of fossil fuels, manufacturers of equipment designed for electric power generation are focusing their main research efforts to the use of syngas derived from the gasification of low cost fuels such as coal, refinery residues, urban solid waste, and biomass, among others. Syngas has a calorific value that is approximately 50% as that of natural gas. Therefore, twice the volume of syngas would be required in order to generate the same amount of thermal energy to be used in power generation equipments. However, when using a larger volume, the mass of gas increases, resulting in a more efficient transformation to electric energy; resulting in lower costs per unit of electric energy generated and a decrease in greenhouse gas emissions. As an example, General Electric has undertaken research for the design of their turbines in order to use syngas (Appendix 2). For turbines with nominal capacity above 70 MW, their results show that by using syngas, power generation may be increased by as much as 20% as compared to turbines designed for natural gas. Such results show the short term potential for the exploitation of residues which presently are accumulated or confined, and which cause environmental pollution. • Synthetic Fuels. The Fischer-Tropsch (FT) process is a chemical process for the production mainly of liquid hydrocarbons (gasoline, kerosene, gasoil and lubricants) from syngas (CO and H2). It was invented by the German scientists Franz Fischer and Hans Tropsch in the 1920s. During the 1930s, and due to the absence of oil reserves in Germany, the FT process received a strong boost as the source of fuel for warfare machinery. The following major technological leap took place in the 1950s, when oil companies Texaco and Shell began the first plants for the gasification of coal, petroleum coke and mineral oil. Currently, South Africa is the world leader in the production of synthetic fuels based on the huge coal beds the country has. The FT process allows for the production of ultra-low sulphur fuels, as this substance is eliminated in the cleansing process of the syngas. Production of synthetic fuels from gasification of certain kinds of biomass is not economically feasible at low oil prices as those observed in the decades from 1970 to 1990. However, as oil prices soared in the last 10 years investment in these technologies has been considered as especially attractive opportunities. Several studies have been published on the feasibility for producing liquid fuels by FT from biomass. An article published by Tijmensen, et. al. (Appendix 3), shows that for a process of liquid fuels by FT a determined investment is required. Of this, 33% corresponds to the gasification plant, which is made up of

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the gasifier which represents approximately 18% of the total investment, and the oxygen plant that will supply the oxidizing agent which represents approximately 15% of total investment cost. Technological innovations such as the ABA process for microwave induced plasma gasification can improve the economic feasibility of projects as reported by the quoted source, because they allow improving the energy efficiency of the process, and also because they generally avoid the use of oxygen as an oxidant, which significantly reduces the total investment. • Environment. Gasification applications for the exploitation of general waste and toxic residues and non-toxic residues which contaminate the environment are endless. The performance of these materials in the gasification process would be the same as the observed by using a carbon based conventional fuel. Materials that can be treated by this process include: hydrocarbon sludge, cleaning sediments from pumping pits, drilling sludge and crude, out of specification crude, spent dispersants, spent oils and lubricants and PCB contaminated oil, among others. In our Working Group, we have developed wide experience in the specific case of exploitation of oil that is contaminated with PCBs by a conventional industrial gasification process (Appendix 4). The results of this research show the production of syngas with a hydrogen content of 45% and 34% carbon monoxide, with an efficiency of removal and destruction of PCBs above 99.99999% and emissions of dioxins and furans below the maximum permissible limit by a factor of 106. Similar results would be expected for the microwave induced plasma gasification process. Technological Status of the ABA Process Presently, ABA Research has a medium-scale industrial plant (with a capacity of processing up to 10 metric tons per day), designed to undertake tests with different raw materials, and located in the City of Monterrey, NL, Mexico. This plant has been useful for evaluating the conversion potential of diverse materials, including: oil-soaked sawdust, ground tire, sugar cane bagasse, agave bagasse, municipal solid waste, residues from food and paper industries, coal, and petroleum coke, among others. As part of the joint research effort, modeling studies have been performed using tools such as ASPEN Plus, COMSOL, and proprietary software. The results of these studies have confirmed the presence of highly reactive radicals similar to those published by other authors (Appendix 1). Such theoretical results confirm the experimental results found on the formation of syngas and the production of vitrified slag. The phenomenon of microwave induced plasma generation may be considered as a technology in the frontier of state-of-the-art technological developments with a high degree of exploitation of the applied energy. Experimental results have consistently shown lower energy consumption when compared with the calculation of energy requirements obtained by modeling, using the above mentioned tools. Likewise, the experimental results have reported energy requirements noticeable below than those reported by other technologies. The next logical step is the construction of a continuous process plant that confirms the results of the different modeling studies, and of the real process undertaken in the present plant.

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Conclusions and Recommendations This document shows the status of the development of the process of microwave induced plasma gasification and its potential application for the exploitation of carbon based materials. The technology is in the frontier of state-of-the-art technological developments. The results of the present evaluation, based on experimental tests, are indicative of lower energy consumption required to maintain a stable operation of the process in a continuous way. Considering that the chemistry of the reactions that take place in the gasification process is the same, it is expected that no significant differences are to be found in the composition of the syngas resulting from the gasification process. However, the flow (or volume) of syngas would be mainly influenced by the characteristics of the materials to be treated. Modeling studies confirm the observed experimental results, as well as the results of published research groups. It is recommendable to verify the present process results in a continuous process in order to demonstrate experimentally the increase in the real efficiency of the process, and their due impact on economic feasibility. Being, as it is, a technology in the frontier of state-of-the-art technological developments, it is highly advisable to continue the effort to invest in it, in order to reach the status of consolidated technology in the short term.

Prepared by: Porfirio Caballero Mata, Ph.D. Director Environmental Quality Center

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APPENDIX 1

Hidetoshi Sekiguchi, Yoshihiro Mori. Steam

plasma reforming using microwave discharge. Thin Solid Films 435 (2003)

44–48

Thin Solid Films 435(2003) 44–48

0040-6090/03/$ - see front matter� 2003 Elsevier Science B.V. All rights reserved.doi:10.1016/S0040-6090Ž03.00379-1

Steam plasma reforming using microwave discharge

Hidetoshi Sekiguchi*, Yoshihiro Mori

Tokyo Institute of Technology, Department of Chemical Engineering, 2-12-1 O-okayama, Meguro-ku, Tokyo 152-8552, Japan

Abstract

The purpose of the study was to prepare atmospheric pure-steam plasma using a microwave discharge and to apply the plasmato the reforming of hydrocarbon for hydrogen production. The experiment was conducted with 2.45-GHz microwave powersupply with a special wave-guide designed elsewhere. The results showed that the pure steam plasma could be stably sustained,and analysis of emission spectra indicated that O, H and OH existed in the plasma. Hexane, as a model of gasoline, was used forthe hydrocarbon reforming experiment. The results showed that H and CO were predominantly produced, as suggested from2

equilibrium calculations, and that reforming could be accomplished. The conversion of hexane and steam was affected by theplasma power, and the ratio and total flow rate of the reactants. A fuel-cell power system including the steam plasma reformerwas evaluated from experimental data and the results suggested that improvements are required for practical use of the plasmareforming method.� 2003 Elsevier Science B.V. All rights reserved.

Keywords: Steam plasma; Microwave discharge; Reforming; Hydrogen

1. Introduction

Recently, fuel cell systems have attracted much atten-tion for highly efficient and decentralized electric powersources. This power source can be widely applied incommercial and military uses. In particular, the instal-lation of such systems in vehicles is being competitivelydeveloped in many major motor companies. A majorconcern in developing fuel-cell systems is how togenerate hydrogen as fuel. The reformation of varioushydrocarbons, such as methanol, methane and gasoline,are being considered as hydrogen sources. Every hydro-carbon source has advantages and disadvantages fromthe point of view of reforming temperature, reactionrate, storage system, supply infrastructure, etc. Conven-tional reforming is carried out thermally with steam andoxygen. Partial oxidation of a hydrocarbon takes placeto provide reaction heat, because the reforming reactionwith steam is endothermic. Noble metal catalysts areusually required to enhance the reaction rate. Therefore,the reforming system is easily affected by the deactiva-tion of catalysts caused by impurities in the hydrocarbonand carbon deposits.One attractive method for reforming hydrocarbons is

to use plasmaw1,2x. The plasma contains highly active

*Corresponding author.

species, such as electrons, ions and radicals, which mayenhance the reforming reaction rate. High reactivity alsoeliminates the need for catalysts in the system. Theseadvantages, as well as its high energy density, lead tocompactness of the plasma reformer. Moreover, theplasma system can be adapted for various hydrocarbons,including natural gas, gasoline, heavy oils and biofuels.A fast response time can be also achieved because theplasma is operated by electricity. However, the utiliza-tion of electricity seems a disadvantage from the view-point of energy efficiency.Microwave discharge is one technique used to obtain

a non-equilibrium plasma, even under atmospheric pres-sure, at which the electron temperature is approximately4000–6000 K, while the heavy particle temperature isaround 2000 Kw3x. Discharge techniques under atmos-pheric pressure have been extensively studied elsewherew4–8x. The purification of noble gasesw9x and thedecontamination of radioactive wastesw10x have beenstudied using atmospheric microwave plasma. Whensteam is used as the plasma supporting gas in microwavedischarge, radicals such as H, OH and O are generated,as well as high-energy electrons, and both reductive andoxidative conditions are provided in the plasma, indi-cating that steam plasma is effective for various treat-ments of materials.

45H. Sekiguchi, Y. Mori / Thin Solid Films 435 (2003) 44–48

Fig. 1. Equilibrium composition for C H and H O. Initial amounts6 14 2

of C H and H O were 1 and 6 mol, respectively(OyCs1).6 14 2

Fig. 2. Effect of OyC ratio on equilibrium composition. Initial amountof C H was 1 mol;Ts1500 8C.6 14

The purpose of this study was to prepare atmosphericpure steam plasma using microwave discharge and toapply the plasma to the reforming of hydrocarbon forhydrogen production. The reforming ofn-hexane as amodel of gasoline was experimentally carried out usingsteam plasma. System analysis of a fuel-cell powersource including the plasma reformer was also carriedout using the experimental data.

2. Equilibrium compositions

Equilibrium compositions have been calculated for apreliminary investigation into the reforming, eventhough the microwave plasma is classified as non-thermal plasma and high-energy electrons are involvedin the reactions in the plasma. Calculations were per-formed for a mixture of steam andn-hexane by mini-mization of the Gibbs free energy, considering typicalspecies that contain C, H or O elementsw11,12x. Theresults are shown in Fig. 1, in which the CyO molarratio in the feed gas was equal to unity. In the temper-ature range between 1000 and 20008C, H and CO2

become dominant, while H dissociates into atoms with2

increasing temperature. The stoichiometric reaction canbe written with the reaction enthalpy as follows:

C H q6H O™6COq13H DHs1249 kJymol (1)6 14 2 2

Fig. 2 shows the effect of the OyC ratio on thecomposition at 15008C. Solid carbon exists up to OyCs1, at which both H and CO increase with the ratio.2

A slight decrease in CO and increases in both H and2

CO are observed above OyCs1, at which excess H O2 2

exists. The equilibrium calculation suggests that reform-ing should be carried out above a ratio of unity, whichis the stoichiometric condition indicated by Eq.(1).

3. Experimental

The experimental apparatus is shown in Fig. 3. Theexperiment was conducted with a 2.45-GHz microwavepower supply having maximum power of 2.8 kW. Thewave-guide used was as the same as that designed forother workw5x and which can efficiently generate plasmacolumns having high electron density. As mentionedabove,n-hexane was used as a model of gasoline forhydrocarbon reforming. Steam and hexane were heatedand introduced into a quartz tube reactor having adiameter of 12 mm and a length of 500 mm. The reactorwas inserted in the wave-guide, where electromagneticfield was concentrated. Tangential injection of the feedenabled stabilization of the steam plasma. The compo-sition of the product gas was analyzed by gas chroma-tography (GC). Analysis of the emission spectra wasalso carried out. The experimental conditions are sum-marized in Table 1.

4. Results and discussion

Emission spectroscopy indicated that spectra originat-ed from OH, O and H were observed in the pure steamplasma, indicating the dissociation of steam. The emis-sions of C and C were detected when hexane was2

injected.The effect of power applied on product compositions

is shown in Fig. 4, for which the feed rates of C H6 14

46 H. Sekiguchi, Y. Mori / Thin Solid Films 435 (2003) 44–48

Fig. 3. Experimental apparatus.

Table 1Experimental conditions

Plasma torchInner diameter 12 mmLength 500 mm

Feed flow rateC H6 14 0.37–1.00 mmolysH O2 4.86–12.00 mmolys

Molar ratio in the feed(OyC) 1–3Power 1.6–2.5 kW Fig. 4. Effect of power applied on product composition. Feed rates of

C H and H O were 0.81 and 9.72 mmolys, respectively(OyCs2).6 14 2

and H O were fixed. The product gas contains predom-2

inantly H , CO and H O, and the reforming process2 2

proceeds in the steam plasma. The amounts of H and2

CO increase with power, while H O decreases. Slight2

formation of solid carbon was estimated from GCanalysis. A small amount of carbon dioxide was alsodetected in the product gas.Fig. 5 shows the conversions of C H and H O6 14 2

defined by:

F yRC H C H6 14 6 14Conversion C H s (2)Ž .6 14 FC H6 14

F yRH O H O2 2Conversion H Os (3)Ž .2 FH O2

whereF and R denote the flow rates of the feed andthe product gas, respectively. The conversions of C H6 14

and H O show the same behavior as H production, as2 2

shown already. However, complete reforming of hexanewas not attained.The effect of steam feed rate on conversion is shown

in Fig. 6, for which the C H feed rate was fixed.6 14

47H. Sekiguchi, Y. Mori / Thin Solid Films 435 (2003) 44–48

Fig. 5. Effect of power applied on conversion. Feed rates of C H6 14

and H O were 0.81 and 9.72 mmolys, respectively(OyCs2).2

Fig. 6. Effect of steam flow rate on conversion. Feed rate of C H6 14

was 0.81 mmolys; power was 1.8 kW.

Hence, the increase in ratio implies an increase in steamfeed rate. The conversion of C H shows a peak for a6 14

ratio of approximately 1.5, while the conversion of H O2

decreases with increasing ratio, i.e. the steam feed rate.One reason for the maximum may be ascribed to thetemperature distribution in the reactor, as well as insuf-ficient mixing of steam and hexane. Further investigationwill explain these results.When the total feed rate was changed with both the

power and the OyC ratio set constant, the conversionsof C H and H decreased with total flow rate. More-6 14 2

over, a high C H feed rate enhanced the conversion6 14

of H O, but reduced the conversion of C H itself.2 6 14

5. Evaluation of fuel cell system

The plasma reformer proposed here consumes electricpower, and hence the performance of a fuel-cell powersystem including steam plasma reforming was evaluatedfrom the viewpoint of energy efficiency. The systemproposed is shown in Fig. 7. Two heaters were used forthe evaporation of both H O and C H . The plasma2 6 14

reformer investigated in this research provides hydrogenfor fuel cells. The shift reactor converts CO into CO2with H O and generates H simultaneously. The sepa-2 2

rator should be equipped due to the incomplete reactionof C H observed in the experiment. However, the6 14

separator can be eliminated if C H is reacted to6 14

completion. In the evaluation, the separator is not takeninto account. The fuel cell stack generates electric power.The type of the fuel cell is not specified and idealefficiency for the cell is assumed to evaluate systemperformance. The performance is evaluated accordingto:

W yWF Phs (4)

WF

where W and W are the power consumed by theP F

plasma reformer and generated by the fuel cell stack,respectively. The numerator indicates energy availablefrom the system. The energy required in the heaters(Q andQ ) and the shift reactor is not considered,H O C H2 6 14

because heat can be recovered from the exhaust gas ofthe shift reactor. The generation of H by the shift2

reactor is also added, assuming that the shift reactorcompletely converts CO into CO without additional2

heat. The calculation was performed with experimentaldata for which the highest efficiency for H production2

(H production rate divided by plasma power) was2

achieved. The results are indicated in Table 2, withanother case for which complete reforming of hexanewas assumed. The performance based on the experimen-tal data is too low to supply electric power because themagnetron efficiency is excluded in the estimation: atypical efficiency of up to 80% leads to negativeperformance of the system. Therefore, improvements arerequired to achieve complete conversion of hexane.Further evaluation with real data for each element inthe system will elucidate the effectiveness and require-ments for the steam plasma reformer.

6. Conclusion

Pure steam plasma could be stably obtained usingmicrowave discharge under atmospheric pressure. Theplasma contained radicals such as OH, O and H, whichwere detected by emission spectroscopy. The plasmawas applied to hexane reforming and the results showedthat the production of hydrogen could be achieved;

48 H. Sekiguchi, Y. Mori / Thin Solid Films 435 (2003) 44–48

Fig. 7. Fuel cell power system with plasma reformer.

Table 2System performance evaluated

Conversion WP WF h

of C H6 14 (W) (W)

Data from experiment 0.66 1800 2173 0.17Complete reforming 1.0 1800 3647 0.51

Feed rates of C H and H O were 0.81 and 6.08 mmolys,6 14 2

respectively.

however, the conversion of hexane was not sufficient.A fuel-cell power system including the plasma reformerwas evaluated and the performance was insufficientusing the experimental data, showing that improvementsare required for the plasma reforming technique.

Acknowledgments

This research was supported by the Ministry ofEducation, Science, Sports and Culture under Grant-in-Aid for Scientific Research(B) No 13558054.

References

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Sources Sci. Technol. 3(1994) 584.w8x M. Moisan, Z. Zakrrzewski, R. Etemadi, J.C. Rostaing, J.

Appl. Phys. 83(1998) 5691.w9x J.C. Rostaing, F. Bryselbout, M. Moisan, J.C. Parent, C.R.

Acad. Sci. Paris 1-IV(2000) 99.w10x H.F. Windarto, T. Matsumoto, H. Akatsuka, K. Sakagishi, M.

Suzuki, J. Nucl. Sci. Technol. 37(2000) 787.w11x H. Sekiguchi, T. Honda, A. Kanzawa, Proc. ISPC 10(1991)

1.5-2.w12x G. Eriksson, Acta Chem. Semicond. 25(1971) 2651.

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APPENDIX 2

General Electric Company. Syngas Turbine Technology. GEA18028 (09/2010)

GE Energy

Syngas Turbine Technology

2010

1990

2000

2x7F Syngas Coal IGCC (USA)

3x9E Refinery (Europe)

3x9E Steel Mill (Europe)

1x7FA IGCC (USA)

2x6F Syngas Refinery (Asia)

2x6FA Refinery (USA)

1x7FA IGCC (USA)

2 SYNGAS TURBINE TECHNOLOGY

GE turbines for syngas and low-Btu fuel

applications are operating at locations

around the world with more than one

million hours of total operation.

This vast experience covers operations

employing GE and other gasification

technologies, and a variety of fuels

including high- and low-sulfur coals and

petroleum coke. GE offers an unparalleled

edge in providing customers with well-

proven and experienced combined-cycle

technology for syngas applications.

Turbine Innovation Realized

GE Turbines On Low-Btu Fuels

2x9E Steel Mill (Asia)

Sources for generating power are becoming more varied, and more stringent emission requirements are fueling a need

for flexible solutions to meet growing energy demand. At GE, we’re developing solutions today that are flexible enough to

integrate into your diverse portfolio of power generating options, helping you to profitably guide the industry—and your

community—into the future.

As a leader in combined-cycle gas turbine technology, GE has invested its time, resources and expertise to develop a

range of efficient, reliable gas turbines to help energy providers meet these new challenges. GE’s versatile gas turbines

can operate on a variety of low-Btu fuels, in a wide variety of power applications, including hydrogen, low-rank steel

industry furnace gases, light distillates, heavy residuals from refining and syngas. Our solutions can help customers

enhance fuel utilization, reducing fuel costs and improving revenues.

Fuel Flexible Solutions

Many utilities look towards abundant supplies of relatively low-cost coal for power generation. Increasingly the use

of coal—and the emissions and carbon burning it produces—is coming under scrutiny, and many power generators

are turning to integrated gasification combined-cycle (IGCC) technology.

At the front end of IGCC is gasification, which takes a carbon-based fuel source such as coal, refinery residuals

or biomass, and under high heat and pressure, converts it into a synthesis gas (or syngas) comprised of H2 and

CO. Impurities and carbon can be removed easily and economically from the syngas stream on a pre-combustion

basis—leaving a hydrogen-rich fuel—before it is burned to create electricity.

Carbon capture technologies, which have been in commercial operation for many years, offer the ability to

efficiently and cost effectively remove carbon from syngas for permanent storage or use in enhanced oil recovery

before burning the fuel. The resulting gas is essentially a carbon-free, high hydrogen fuel available for combustion

within a combined-cycle power plant. GE’s syngas power turbines offer a powerful, reliable solution that can

operate on the high hydrogen fuels resulting from this carbon separation.

While today’s GE syngas turbines have been used

successfully on fuels with up to 50% hydrogen, we

continue to advance the capabilities of the next

generation of gas turbines for high hydrogen fuels.

We’re working on breakthroughs that will deliver cleaner,

efficient technologies to customers who may capture

carbon for storage.

Syngas Gas Power Generation in a Carbon Constrained World

SYNGAS TURBINE TECHNOLOGY 3

Our syngas turbine platforms are built upon GE’s extensive experience and rigorous engineering processes. Advances in

technology will deliver high efficiency and reliability. Among these advances is the Multi Nozzle Quiet Combustion (MNQC).

One of the key challenges of hydrogen fuel is the high flame speed. The MNQC, a diffusion flame-based system that is

free of the sensitivities to flame speed and combustion instability (combustion dynamics) that are inherent to lean pre-mix

combustion systems was developed to address this challenge.

GE’s MNQC system has been designed to run on low-Btu fuels and is capable

of operating on many varieties of syngas, including high H2 fuels. It is built for

high efficiency and offers superior benefits for customers operating in base load

applications. This combustor is also capable of operating on natural gas for

start-up and shut-down operations, and can operate at base load on natural

gas for extended periods of time if syngas is not available.

With MNQC technology, GE can offer a similar combustor configuration for

several turbine products using syngas and high hydrogen fuels, all based upon

a combustion system design that has been in use since the 1990s, and can

operate with un-shifted and shifted (hydrogen-rich) syngas.

Syngas Turbine Fuel Applications

9E

6FA

7EA

7F

9F

FUEL HEATING VALUE

LOWAir IGCC Syngas

Blast Furnace Gas

MEDIUMO2 IGCC Syngas

GTL Off-gas

HIGHHigh H2 for CCSHigh H2 for EOR

Challenges Met, Innovation Attained


Administrator

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Notes:

(1) Conventional gasification fuel, without CO2 capture.

(2) Performance at ISO conditions.

(3) No integration with process. Steam turbine and generator product fit TBD. Assumes multishaft configuration.

Gas Turbines for Syngas Applications

7EA

6FA

9E

7F

9F256 MW 285 MW

187 MW 232 MW

126 MW 140 MW

77 MW 92 MW

85 MW 85 MW SIMPLE CYCLE OUTPUT (MW)

NATURAL GAS

SYNGAS

Gas Turbines for IGCC Syngas Applications1

Gas Turbines Combined-Cycle

Model Nominal Syngas Power Rating2 Model Nominal Syngas Output Power3

6B 46 MW (50/60 Hz) 106B 70 MW (50/60 Hz)

7EA 80 MW (60 Hz) 107EA 120 MW (60 Hz)

9E 140 MW (50 Hz) 109E 210 MW (50 Hz)

6FA 92 MW (50/60 Hz) 106FA 140 MW (50/60 Hz)

7F Syngas 232 MW (60 Hz) 207F Syngas 710 MW (60 Hz)

9F Syngas 286 MW (50 Hz) 209F Syngas 880 MW (50 Hz)


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GE’s portfolio of syngas capable turbines, includes units for both 50 Hz and 60 Hz segments, simple-cycle

configurations with output ranging from 46–300 MW, and combined-cycle configurations with output ranging

from 70–880 MW, depending on fuel and site specific conditions.

6B…Reliable and rugged 50/60 Hz powerThis rugged and reliable gas turbine, a popular choice for mid-range power generation service, has a well-documented availability of 94.6%

and 99% reliability. With over 1,100 units worldwide, the dependable 6B features low capital investment and low maintenance costs. It

has accumulated over 60 million operating hours in a wide range of applications—including simple-cycle, heat recovery, combined-cycle,

and mechanical drive. Introduced in 1978, many upgrades are available to improve the performance of earlier versions, including rotor life

extension and combustion system retrofits that can deliver 5 ppm NOx when operating on natural gas. With its lengthy industrial experience

and high reliability, the 6B is an excellent fit for industrial and oil and gas applications, providing horsepower and high exhaust energy. The

6B has long operating experience on a variety of medium- or low-BTU fuels, including syngas produced from oil and steel mill gasses.

7EA…Proven performance for 60 Hz applicationsThe size of the versatile 7EA gas turbine enables flexibility in plant layout and fast, low-cost additions of incremental power. With high

reliability and availability, this unit provides strong efficiency performance in simple-cycle and combined-cycle applications—and is ideally

suited for power generation, industrial, mechanical drive, and cogeneration applications. 7E/EA units have accumulated millions of hours

of operation using crude and residual oils, and were featured in the first large scale IGCC demonstration plant at Coolwater that operated

in the mid 1980s.

9E…Flexible and adaptable performance for 50 Hz applicationsSince its introduction in 1978, GE’s 9E gas turbine fleet of 430+ units has accumulated over 22 million hours of utility and industrial

service—often in arduous climates ranging from desert heat and tropical humidity to arctic cold. Capable of operating on a variety of

medium- or low-BTU fuels, including syngas produced from oil and steel mill gasses, the 9E is a quick power solution also well suited for

IGCC or mechanical drive applications. This reliable, low first-cost machine has a compact design that provides flexibility in plant layout and

easy addition of incremental power when phased capacity expansion is required.

6FA (50/60 Hz)…Advanced technology mid-sized combined-cycle and cogenerationWith over 2.5+ million operating hours and more than 110 units installed or on order, the 6FA gas turbine is a good fit for local power for

industrial complexes. It delivers high efficiency and high availability, and provides the operating flexibility needed for harsh environments. A

direct down-scaling of the proven 7FA, the 6FA is rated at 85–95 MW when operating with syngas. Four 6FAs have been operating syngas

at two refinery cogeneration plants since the early 2000s.

7F Syngas…Large baseload syngas performance for 60 HzBuilding on GE’s F-class syngas experience, the 7F Syngas turbine was developed specifically for syngas operation. The configuration of

the 7F Syngas turbine combines materials with known syngas compatibility and turbine components designed for the increased mass flow

in syngas applications. These elements allow the 7F Syngas turbine to generate 232 MW on dry syngas at ISO conditions. This turbine—like

GE’s other syngas turbines—is capable of operating on syngas and on high hydrogen (carbon captured) fuels. The first two units shipped to

Duke Energy’s Edwardsport IGCC plant in 2010.

9F Syngas…Advanced turbine technology for 50 Hz applicationsThe latest addition to GE’s syngas turbine portfolio is the 9F Syngas turbine. This unit, based on the 9FA, building on the world’s most

experienced fleet of highly efficient 50 Hz large units. The 9F Syngas turbine can be arranged in a single-shaft or multi-shaft configuration

that combines one or two gas turbines with a single steam turbine. This turbine is capable of operating on syngas (non-carbon captured)

or a high hydrogen fuel (carbon capture).

GE Syngas Turbine Solutions


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Gasification technology combined with GE’s syngas turbines is an effective way to use refinery residuals and generate N2,

H2, steam and power in a petrochemical complex.

GE deploys its advanced gas turbine technology to deliver greater performance levels than ever before, offering

customers gas turbine solutions with a wide range of fuel and process integration flexibility. Based on its significant gas

turbine and syngas experience, GE is pleased to offer solutions that deliver high efficiency and reliability for advanced

IGCC and cogeneration plants.

Refinery Residuals for Cogeneration


Developing an IGCC plant or gasifier in a petrochemical complex is a capital-intensive project, so delivering results is important.

Seamlessly integrating the gasification and power islands will help enable operators of IGCC and cogeneration plants to derive

return on their investment. Our syngas turbines provide air extraction (air from the gas turbine compressor) to the process

plant, allowing for a reduction in the number of compressors required to supply air to gasifier, air separation unit, or other

plant-level process, delivering value to the operators.

Plant Integration

Syngas or high H2

N2 from Air Separation Unit for dilution

Process heat for fuel heating

High P, T Air to reduce compressor loads

GE offers expertise in the integration of the syngas turbine, including:

•Steam-sideintegration

•Nitrogenreturn

•Fullsteamandairintegration, including air extraction and nitrogen return

GE Energy provides innovative, technology-based products and service solutions across the full spectrum of the energy

industry and is committed to investing in a cleaner, smarter, and more efficient future. To put GE’s proven syngas turbine

technology to work for you, contact your local GE representative or visit http://www.ge-energy.com

GE Delivers


Flexibility of GE Syngas Turbine TechnologyGE leads the world in the application of its heavy duty gas turbines to gasification combined-cycle gas projects. Our

success with low- and medium-Btu fuel gases is a consequence of extensive full-scale laboratory testing on various fuels

for nearly 24 years at GE’s combustion laboratory in Schenectady, New York, and, since 2002, testing at the combustion

development laboratory in Greenville, South Carolina.

In these facilities, we develop and validate system components

and the impacts of impact of various characteristics on

performance of a combustion system. At our Greenville

test facility, for example, we are able to validate the 7F

syngas turbine combustion system, testing it at full pressure,

temperature and flows. The facility also has the capability

to blend a variety of syngas-like fuels. We can also test the

turbine on start-up fuel (natural gas) at full speed, no load

conditions. Typical test campaigns examine combustion full

and part load performance, including combustion dynamics,

emissions and exit profile. In addition, thermocouples, strain

gauges and thermal paint – combined with advanced

computational fluid dynamics and finite element analysis –

allow full durability validation of the system. Combustion lab

testing has evaluated performance over a range of fuel space

and load points. Results from these tests have confirmed that

the system will be able to meet customers’ performance goals.

© 2010 General Electric Company. All rights reserved.

GEA18028 (09/2010)

CAMPUS MONTERREY



APPENDIX 3

Michiel J.A. Tijmensen, Andre P.C. Faaij, Carlo N. Hamelinck, Martijn R.M. van Hardeveld.

Exploration of the possibilities for production of Fischer Tropsch liquids and power via biomass gasification. Biomass and Bioenergy 23 (2002)

129 – 152

Biomass and Bioenergy 23 (2002) 129–152

Exploration of the possibilities for production of FischerTropsch liquids and power via biomass gasi%cationMichiel J.A. Tijmensena, Andr,e P.C. Faaija ; ∗, Carlo N. Hamelincka,

Martijn R.M. van Hardeveldb

aDepartment of Science, Technology and Society, Utrecht University, Padualaan 14, 3584 CH, Utrecht, NetherlandsbShell Global Solutions International BV, Badhuisweg 3, P.O. Box 38000, 1030 BN, Amsterdam, Netherlands

Received 17 September 2001; received in revised form 22 February 2002; accepted 13 March 2002

Abstract

This paper reviews the technical feasibility and economics of biomass integrated gasi%cation–Fischer Tropsch (BIG-FT)processes in general, identi%es most promising system con%gurations and identi%es key R&D issues essential for thecommercialisation of BIG-FT technology.The FT synthesis produces hydrocarbons of di;erent length from a gas mixture of H2 and CO. The large hydrocarbons can

be hydrocracked to form mainly diesel of excellent quality. The fraction of short hydrocarbons is used in a combined cyclewith the remainder of the syngas. Overall LHV energy e?ciencies,1 calculated with the @owsheet modelling tool Aspenplus,are 33–40% for atmospheric gasi%cation systems and 42–50% for pressurised gasi%cation systems. Investment costs of suchsystems (367 MWth) are MUS$ 280–450,2 depending on the system con%guration. In the short term, production costs ofFT-liquids will be about US$ 16=GJ. In the longer term, with large-scale production, higher CO conversion and higher C5+

selectivity in the FT process, production costs of FT-liquids could drop to US$ 9=GJ. These perspectives for this route anduse of biomass-derived FT-fuels in the transport sector are promising. Research and development should be aimed at thedevelopment of large-scale (pressurised) biomass gasi%cation-based systems and special attention must be given to the gascleaning section. ? 2002 Elsevier Science Ltd. All rights reserved.

Keywords: Biomass; Gasi%cation; Fischer Tropsch synthesis; FT-liquids; Polygeneration; Diesel; Combined cycle

1. Introduction

1.1. General background

To prevent climate change induced by human activ-ity, greenhouse gas emissions must be dramatically

∗ Corresponding author. Tel.: +31-20-353-7643; fax: +31-30-253-7601.E-mail address: [email protected] (A.P.C. Faaij).

1E?ciency throughout this paper is on LHVwet basis, unlessindicated otherwise.

2All Cost numbers are in US$2000.

reduced. Renewable energy (e.g. solar, wind andbiomass) could play a major role in achieving this.Biomass is a renewable energy source when carbondioxide emissions caused by its use are absorbed bynewly grown biomass. Only biomass o;ers the possi-bility to produce liquid, carbon neutral, transportationfuels. Ethanol, methanol and synthetic hydrocarbons,as well as hydrogen can be produced from biomassand could o;er feasible alternatives for the transportsector on foreseeable term [1,2]. This is particularlyrelevant since transport is responsible for a large partof global CO2 emissions. The global trend is that

0961-9534/02/$ - see front matter ? 2002 Elsevier Science Ltd. All rights reserved.PII: S 0961 -9534(02)00037 -5

130 M.J.A. Tijmensen et al. / Biomass and Bioenergy 23 (2002) 129–152

Power

Pre-treatment:

- grinding- drying

feedstock ispoplar wood

Gasification:

- air or oxygen- pressurised or

atmospheric- direct/indirect

Gas Cleaning:

‘wet’ cold or‘dry’ hot

FT liquids

Off gas

Recycle loopfor unconverted syngas

(optional)

FT synthesis:

- reactor typeSlurry orfixed bed

Gasturbine

Gas Processing

- reforming,optional

CH4 → H2+CO- shift, optional

(adjusting theH2/CO ratio)

- CO2 removal(reducingamount of inert)optional

Fig. 1. A basic schematic view of the key components for converting biomass to FT-liquids combined with gas turbine (combined cycle)power generation.

the share of transport in the total energy consump-tion is increasing, especially in developing countries[3]. Some recent studies indicated that the use ofFischer-Tropsch (FT) technology for biomass conver-sion to synthetic hydrocarbons may o;er a promisingand carbon neutral alternative to conventional diesel,kerosene and gasoline [2,4].The FT process is a process capable of producing

liquid hydrocarbon fuels from syngas. The recentinterest in FT synthesis has grown as a consequenceof environmental demands, increased use of nat-ural gas from remote locations and technologicaldevelopments. First, FT-liquids are totally free ofsulphur and contain very few aromatics comparedto gasoline and diesel, which results in lower emis-sion levels when applied in internal combustionengines.Known reserves of natural gas have increased but

a signi%cant portion has been assigned ‘stranded’ [5].Conversion on location of natural gas into shippablehydrocarbon liquids is possible by syngas generationfollowed by FT synthesis. This is demonstrated on fullcommercial scale by Shell in Malaysia. Products madeby the FT synthesis, hydrocarbons of di;erent length,can be transported by the same means as oil. Shell(natural gas based) and Sasol (coal based) apply FTsynthesis on commercial scale. This growing marketfor FT technology also drives further technologicaldevelopment of this type of process. FT synthesis frombiomass-derived syngas, however, has received littleattention so far.

1.2. Rationale

In principle, numerous process con%gurations forthe conversion of biomass to FT-liquids are possible,e.g. depending on the gasi%er types, the FT process andthe gas cleaning process considered. A scheme of themain process steps to convert biomass to FT-liquids(and power) and possible variations is shown inFig. 1.Di;erent gasi%cation methods, covering atmo-

spheric and pressurised, air-blown and oxygen-blown,indirect and direct, can produce a wide range of syn-gas compositions, with H2=CO ratios varying between0.45 and 2. Any raw-biomass-derived syngas containscontaminants like H2S, NH3, dust and alkalis. Conse-quently, the syngas needs to be cleaned and processedto make it suitable for the FT synthesis. Several pro-cessing steps (like reforming and shift) can be appliedto manipulate the syngas composition prior to the FTreactor. The FT synthesis can be realised in di;erentreactor types. Furthermore, o;gas from the FT syn-thesis can either be recycled partially (full conversionmode) or used directly in a gas turbine for electricityproduction (once through mode).Last but not least, economies of scale are important

for this type of technology [e.g. 2]. Some process com-ponents may be more suited for upscaling than others,which may lead to di;erent ‘optimal’ technology fordi;erent capacities. In total, all those variables lead toa large number of possible process con%gurations toproduce FT-liquids from biomass.

M.J.A. Tijmensen et al. / Biomass and Bioenergy 23 (2002) 129–152 131

1.3. Objectives

The main objective of this study is to evaluate thedi;erent options to use biomass for the production ofFT-liquids. The main research questions are:

• To explore the technical feasibility and eco-nomics of biomass integrated gasi%cation—FischerTropsch (BIG-FT) processes in general, with spe-ci%c attention for gas cleaning requirements.

• To identify most promising system con%gurations;various biomass gasi%cation processes will be stud-ied in combination with FT-concepts in two maincategories:1. Full conversion FT with the possible use of a

gas turbine, focussed on a maximum amount ofFT-liquids.

2. Once through FT with co-%ring the o;gas in agas turbine.

• To investigate economies of scale of BIG-FT con-version concepts.

• To explore the technical and economic perspectivesof this route on the longer term.

• To identify key R&D issues for the commercialisa-tion of BIG-FT technology.

1.4. Methodology

The work consists of several steps: %rst, a technol-ogy assessment on gasi%cation, gas cleaning, syngasprocessing, FT conversion and combined cycle ismade. Besides information from literature, expertsfrom technology manufactures and research instituteswere consulted to identify the potential problemswith the use of FT processes for biomass-derivedsyngas. Manufacturers have been consulted for pro-cess data. The assessment includes some technologiesthat are not applied commercially at present, suchas advanced high temperature gas cleaning options.Second, promising system con%gurations were se-lected for further performance modelling with helpof the @owsheeting program Aspenplus. Aspenplus isused to calculate energy and mass balances. Third,an economic evaluation is performed. Again, manu-facturers have been consulted for cost data of variouscomponents. Fourth, an extensive sensitivity anal-ysis is performed, including economies of scale ofBIG-FT systems. And %nally, the various system con-

%gurations are compared, conclusions are drawn andrecommendations on R&D issues are formulated.

2. System description

2.1. The FT process

2.1.1. Reaction mechanism and selectivityThe FT reaction produces hydrocarbons of vari-

able chain length from a gas mixture of carbonmonoxide and hydrogen. Nowadays, this process isoperated commercially at Sasol South Africa (fromcoal-derived syngas) and Shell Malaysia (from natu-ral gas-derived syngas). The main mechanism of theFT reaction is

CO + 2H2 → –CH2– + H2O;

RH◦FT =−165 KJmol−1: (1)

The –CH2– is a building stone for longer hydro-carbons. A main characteristic regarding the perfor-mance of the FT synthesis is the liquid selectivity ofthe process. The liquid selectivity is determined bythe so-called ‘chain growth probability’. This is thechance that a hydrocarbon chain grows with anotherCH2− group, instead of terminating.The products made by the FT reaction are hydrocar-

bons of di;erent length. A high liquid selectivity (orC5+ selectivity: SC5+) is necessary to obtain a maxi-mum amount of long hydrocarbon chains. The yield inthe C1–C4 range decreases with increasing SC5+ ; anyC1–C4 in the o;gas may e?ciently be used in a gasturbine for power generation.The relation between the hydrocarbon yield and

the chain growth probability is described by theAnderson–Schulz–Flory (ASF) distribution [4,5,7].The ASF distribution describes the molar yield incarbon number as: fraction Cn = �n−1(1 − �), where� is chain growth probability and n the length ofthe hydrocarbon, which makes 1 − � the chancethat the chain growth terminates. Fig. 2 shows thehydrocarbon yields for di;erent values of chaingrowth probability.Selectivity is in@uenced by a number of factors, ei-

ther catalyst dependent (type of metal (iron or cobalt),support, preparation, pre-conditioning and age ofcatalyst) or non-catalyst dependent (H2=CO ratio inthe feed gas, temperature, pressure and reactor type).


Fig. 2. Product distribution for di;erent � for FT synthesis [31].

Fig. 3. Tubular %xed bed FT reactor [12].

The division in iron and cobalt is relevant becausethe water–gas-shift reaction, takes place only signi%-cantly over an iron catalyst.The FT synthesis uses H2 and CO at a ratio near

2:1:1, depending on selectivity. Since biomass gasi-

Fig. 4. Slurry bed FT reactor [12].

%cation in most cases leads to a signi%cantly lowerH2=CO ratio in the feed gas, a shift reaction may benecessary.The FT process is generally operated at pressures

ranging from 20 to 40 bar and at 180–250◦C. Higher

partial pressures of H2 and CO lead to higherliquid selectivity SC5+ . More inert in the syngaswill lower partial pressures of H2 and CO, therebyreducing SC5+ .


Table 1Di;erences between %xed bed and slurry FT synthesis processes

Fixed bed Slurry

EconomicO&M Maintenance and labour intensive and

long down time due to periodical catalystreplacement

Little down time due to on-line catalyst re-placement. Lower catalyst consumption [9,10]

Economies of scale Scale up is straightforward, by multiplyingtubes, economies of scale however limited [6]

Possible, but scale-up is di?cult and exacteconomies of scale not clearly reported [6,11]

Conversion e=ciencyOnce through conversion Up to 80% is assumed to be possible High average conversions (once through),

up to about 80% [10,11].C5+ selectivity ¿ 90% possible, negatively in@uenced by inert ¿ 90% possible, negative in@uence of inert

seems lower [8]Pressure drop 3–7 bar ¡ 1 bar [9]

Technical aspectsWax=catalyst separation Performed easily and at low costs More di?cult for commercial application;

although solutions are reported [10]Process control EasySulphur poisoning 1.5–2 times higher, so more thorough cleaning

required

StatusProven technology. Advanced reactors arelikely to have higher once through conversion

Overall considered proven technology;wax=catalyst separation is complex

2.1.2. FT reactorsThere are three main kinds of FT reactors: the @u-

idised bed reactor, the %xed bed reactor and the slurryphase reactor. The %xed bed (Fig. 3) and the slurryreactor (Fig. 4) are the most promising according tomany authors [e.g. 6], some favouring the slurry phasereactor [e.g. 4] and some favouring the %xed bed [7].Speci%c biomass related advantages for either %xedbed or slurry cannot be given clearly, though sensitiv-ity for inert (relevant for some biomass-derived syn-gas compositions) seems less in a slurry reactor. Themain disadvantage of the slurry reactor is the need forcatalyst=wax separation, on which no public informa-tion appears to be available. Table 1 summarises somekey di;erences between the %xed bed and slurry phasereactors [12].

2.1.3. HydrocrackingWhen diesel is the desired %nal product, the FT

product requires hydrocracking. Hydrogen is added toremove double bonds, after which the FT-liquids arecracked catalytically with hydrogen. Depending on thewax cracking conditions, mainly diesel or kerosene is

Table 2Typical product distribution for di;erent wax hydrocracking con-ditions, (in wt%). In addition a small percentage C3=C4-fractionis formed [8]

Product split Gasoil mode (%) Kerosene mode (%)

Naphtha 15 25Kerosene 25 50Gasoil (diesel) 60 25

produced. The overall carbon e?ciency of the hydroc-racking step is close to 100% [9]. Also, hydrocrackingconditions can be altered relatively simple to obtain adesired product mix (Table 2).The FT products are totally free of sulphur, ni-

trogen, nickel, vanadium, asphaltenes, and aromaticswhich all are typically found in mineral oil products.FT-diesel, with a very high cetane number, 3 can alsobe used as a blendstock to improve the quality of

3 Cetane number is a primary measure of diesel fuel quality. Itis essentially a measure of the delay before ignition. The shorterthe delay the better—and the higher the cetane number.


normal diesel. The FT naphtha has a much lower oc-tane 4 number than ‘normal’ naphtha. FT-kerosene foraviation still needs approval of several product specs.Based on the current product speci%cations and re-quirements, these products could therefore have lessvalue than ‘normal’ naphtha and kerosene. But likeFT-diesel they contain no sulphur or other contami-nants. Besides reducing emissions to air, FT-liquidsare expectedly well suited for use in fuel cell vehi-cles (FCVs), which require very clean fuel to preventdamage to fuel cell catalyst. This is a very impor-tant characteristic for the somewhat longer term whenFCVs start penetrating the market [13], as %rst gen-eration FCVs are likely to onboard reform diesel orgasoline. The diesel markets may be the %rst applica-tion of FT-fuels however.

2.2. Biomass gasi>cation

2.2.1. Pre-treatment of feedstockA wide variety of biomass resources can be used as

feedstock. Wood, agricultural wastes, organic wastes,and sludges are each potential fuels. However, in thisstudy clean (poplar) wood is assumed to be used asfeedstock. Clean wood gives a relatively clean syngas,with low levels of contaminants. On the longer termwood from dedicated plantations may become a majorsource of renewable biomass [see e.g. [14]].Pre-treatment prior to gasi%cation is required and

generally consists of screening, size reduction, mag-netic separation, ‘wet’ storage, drying and ‘dry’ stor-age [15]. Moisture content of the ‘wet’ poplar chipsdelivered is assumed to be 30%. Drying is generallythe most important pre-treatment operation, necessaryfor high cold gas e?ciency at gasi%cation [16]. Dryingreduces the moisture content to 10–15%. Drying caneither be done with @ue gas or with steam. Since, aswill be explained, signi%cant amounts of low-qualitysteam are generated in the FT process, steam dry-ing is preferable (e.g. a Niro steam dryer [17]). Also,steam drying results in (very) low emissions and may

4 Octane number is a quality rating for gasoline, indicating theability of the fuel to resist premature detonation and to burn evenlywhen exposed to heat and pressure in an internal combustionengine. Normal gasoline has a octane number of 87–89.

eventually be safer with respect to risks for dust ex-plosion.

2.2.2. Gasi>cationConversion of biomass to an H2 and CO containing

feed gas that is suited for FT synthesis takes placesthrough gasi%cation. Gasi%cation can take place at dif-ferent pressures, either directly heated or indirectlyheated (lower temperatures), and with oxygen or withair. Direct heating occurs by partial oxidation of thefeedstock, while indirect heating occurs through a heatexchange mechanism. Since for economic and e?-ciency considerations, the capacities investigated inthis analysis start at 100 MWth, only CFB gasi%ershave been taken into consideration [1,2,18,19]. Somekey advantages and disadvantages of each gasi%cationmethod are shown in Table 3. To cover the wide rangeof gasi%cation methods, di;erent gasi%ers currentlyavailable and=or under development were selected forfurther study (see Table 4).These gasi%ers produce a wide range of syngas com-

positions representing the reasonably maximum pos-sible variation in CO : H2 ratios that can be obtained.The syngas produced by the di;erent gasi%ers

contain various contaminants: particulates, condens-able tars, alkali compounds, H2S, HCl, NH3, HCNand COS [23]. However, no full data sets of syngascompositions including all these contaminants areavailable for the gasi%ers considered. Therefore,some estimations and assumptions are required(Section 2.5).

2.3. Syngas processing

The syngas, produced by the gasi%cation ofbiomass, consists mainly of H2, CO, CO2 and CH4.Their shares in the syngas can be tailored to the needsof the FT process by methane reforming (convertsCH4 with steam to CO and H2), a shift reaction (ad-justs the H2=CO ratio by converting CO with steamto H2 and CO2) and CO2 removal, which reducesthe amount of inert gases for the FT synthesis. Formethane reforming, the autothermal reformer (ATR)has been selected. An amine treating process is usedfor CO2 removal. More extensive descriptions oncomponent performance data are given in backgroundreports [18,24,19].


Table 3Main technical aspects gasi%cation method

Pressurised Atmospheric+ Pressurised downstream equipment is smaller and generallymore economical at larger scales (see Section 4.1)

− Larger downstream equipment needed

− Higher costs of gasi%er at small scale + Less costs at small scale (see Section 4.1)− High risk in keeping constant mass @ow in gasi%er, operationalexperience so far limited to demonstration projects [20]

+ Signi%cant commercial experience with airblowndirect systems

Oxygen Air− Air separation plant needed, especially at small scales relativelyexpensive

+ Cheaper

+ No dilution of syngas by N2 −N2 diluted syngas, has negative in@uence on C5+

selectivity− Larger equipment needed downstream

Direct Indirect+ Less tars produced; the presence of tars in the syngas is one ofthe biggest problems when gasifying biomass

+ No N2 dilution even if air is used

− Bigger tar problem− ¿ Currently demonstrated (BCL)

2.4. Power generation with a combined cycle

It is possible to use the o;gas from the FT reac-tor in a gas turbine (combined cycle) for additionalelectricity production. At high pressure, the o;gas ismixed with pressurised air and combusted at about1100–1300◦C. Expansion of the resulting hot @ue gasgenerates power. Part of the power is used to drive theair compressor.In case of BIG-FT systems, the caloric value of the

o;gas may be too low for (direct) combustion in agas turbine. Typically, reasonable minimum heatingvalues for commercial gas turbines are 4–6 MJ=Nm3,assuming some modi%cations on burners and fuelmanifolds [15,25]. Co-%ring of natural gas avoidsproblems by raising the heating value of the gas,and increases the thermal e?ciency due to the largerscales of the turbine that are possible with co-%ringcompared to o;gas utilisation alone. Co-%ring istherefore included in this analysis.Various (gas) streams in the whole process require

cooling, e.g. the exhaust gas from the gas turbine andthe syngas after gasi%cation. Superheated steam canbe generated at these places and expanded in a (partly)condensing steam turbine to generate electricity. Lowtemperature steam can also be used: for drying andother steam demanding processes such as the shiftreactor.

2.5. Gas cleaning

2.5.1. GeneralThe syngas produced by the gasi%cation process

contains di;erent kinds of contaminants, viz. particu-lates, condensable tars, alkali compounds, H2S, HCl,NH3 and HCN [23]. These contaminants can loweractivity in the FT synthesis due to catalyst poisoning.Sulphur is an irreversible poison for the cobalt andiron catalysts (and to a smaller extent for the shift andreformer catalysts), because it will stick to active site.Tolerance for contaminants is low and ‘deep’ clean-ing is required. Two distinct routes of cleaning will beconsidered in this study: ‘wet’ low temperature clean-ing and ‘dry’ high temperature cleaning.

2.5.2. Conventional ‘wet’ low temperature cleaningConventional ‘wet’ low temperature cleaning

(Fig. 5), as described in [15,23], is being proposedapplied to clean the fuel gas for BIG=CC installations.However, cleaning requirements for the FT synthesisare much more stringent than for BIG=CC systems.Speci%cations for FT are given in Table 5 and com-pared to syngas compositions typical for CFB gasi-%cation of clean wood. Since at present, relativelyclean natural gas is the common feedstock for FT syn-thesis, actual cleaning speci%cations are not known

136M.J.A

.Tijmensen

etal./B

iomassand

Bioenergy

23(2002)

129–152

Table 4Operating characteristics of the gasi%ers evaluated in this paper, based on poplar wood

Gasi%er name: BCL IGT IGT+a EP TPS(Batelle Columbusgasi%er) [1]

(Institute of GasTechnology) [18]

(IGT with processadjustment, basedon estimates) [21]

(Enviro Power withdolomite tar cracker)[15]

Termiska Processerwith dolomitetar cracker) [19]

Gasi%er process type Indirect, airblown,atmospheric

Direct, oxygen blown,pressurised

Direct, oxygen blown,pressurised

Direct, airblown,pressurised

Direct, airblown,atmospheric

CharacteristicsP (bar) 2b 34 20.3 22 1.3T (K), exit 1136 1255 1241 1223 1173Moisture dry biomass 10% 15% 15% 15% 15%Pilot size (dry tons=day) 200 100 (Knight 1999) No pilot —c 270Flowrate dolomite (kg=kg wet)c —c 0 0 0.0095 0.0268Flowrate air=oxygend 1:46 kg=kg dry 0:3 kg=kg dry 0:3 kg=kg dry — 1:4 kg=kg wetSteam (kg=kg wet input) 0.19 0.34 0.6 0.34b 0.34b

Yield (kmol=dry tonne) 45.8 82.0 123.1 113.3 112.1LHV syngas (MJ=Nm3 wet gas) 13.9 7.3 4.8 5.8 5.2Gasi%er e?ciencye 86.8 80.7 80.9 88.6 80.0H2=CO ratio 0.45 1.39 2.0 0.73 0.77

Composition (mol% [dry])H2O 19.9 [0] 31.8 [0] 50.6 [0] 13.55b [0] 13.55 [0]H2 16.7 [20.8] 20.8 [30.5] 15.68 [31.7] 10.03 [11.6] 13.25 [15.3]CO 37.1 [46.3] 15.0 [22.0] 7.83 [15.85] 13.83 [16.0] 17.22 [19.9]CO2 8.9 [11.1] 23.9 [35.0] 17.71 [35.9] 15.4 [17.8] 12.22 [14.1]CH4 12.6 [15.7] 8.2 [12.0] 5.73 [11.6] 7.26 [8.4] 2.82 [3.26]C2+ 4.8 [6.0] 0.3 [0.5] 0 0.48 [0.62] 0.96 [1.11]C2H4 4.2 [5.2] 0.94C2H6 0.6 [0.74] 0.02N2 + Ar 0 0.40 [0.8] 0.40 [0.8] 38.9 [45.3] 39.20 [45.3]Others ¡ 0:3 ¡ 0:3 ¡ 0:3 ¡ 0:3 ¡ 0:3

aTwo gas compositions are included for pressurized, oxygen blown gasi%cation: one is at ‘standard’ conditions (IGT), the other at operating conditions leadingto maximized hydrogen production, which is obtained by increased steam addition and reduced pressure. This is a more theoretical case, but allows for exploringthe consequences for having a more optimal CO:H2 ratio at the cost of higher steam consumption, lower pressure and a lower heating value of the (wet) syngas.

bAssumption.cNot available.dOxygen of 99.5% purity is used; production is assumed to require 305 kWh per tonne oxygen for 95% purity. This is somehow scale-dependent [22]. Oxygen

of 99.5% purity will require 15% extra energy [22].eGasi%er e?ciency is de%ned as [energy content syngas=energy content biomass input], based on LHV. Energy content of steam and air=oxygen added is not

taken into account.


Tar cracker Cycloneseparator

Bag filter(optional:second bagfilter)

Scrubber(water + NaOH)

COShydrolisation(not if Aminetreating isused)

Scrubber(with H2SO4)

ZnO guard bed

Fig. 5. Schematic view of ‘wet’ low temperature cleaning.

Table 5Contaminant concentrations (wt%) and their maximum values for FT synthesis (ppb)

Contaminant presentin dry feedstock(in syngas)

poplar woodadapted from[18]

AssumedcleaningrequirementsFT in ppb

Cleaninge?ciencyrequired

Required cleaning steps(‘wet’ low temperature cleaning)

Results+= requirementachieved ?=some uncertainty

Ash (particulates) 1.33 0 ¿ 99:9% Cyclone separator, bag %lters=scrubber

+

N (HCN + NH3) 0.47 20 ¿ 99:9% Scrubber (possibly with H2SO4),Sul%nol D also removes HCN andNH3

+?

S (H2S + COS) 0.01 10 ¿ 99:9% Scrubber, possibly COS hydrolisa-tion unit or Sul%nol D necessary,ZnO guard bed

++, ZnO guard bedsare also used for nat-ural gas based FT

Alkalis 0.1a 10 ¿99.9% During cooling down alkalis con-dense on particulates, possibly alsoon vessels (and thereby pollutingthem)

+?

Cl (HCl) 0.1 10 ¿ 99:9% Absorbed by dolomite in tarcracker (if used), reaction withparticulates in bag %lter, scrubber(possibly with NaOH)

+

Pb and Cu 0a Not known — Condense on particulates, but ac-tual behaviour has not been studied

?

Tars —b 0 ¿ 99:9% Condense on particulates and ves-sels (and thereby polluting them)when syngas is cooled below500◦C

potential tar prob-lem, limited experi-ence with completeremoval or conver-sion for biomass

aAdapted from [16] for miscanthus; value would be lower for clean wood.bNot known, but order of magnitude is g=Nm3.

for some speci%c biomass contaminants. Therefore,some speci%cations are estimates. The speci%cationfor sulphur, however, is explicitly known, since it isalso present in natural gas and known to irreversiblypoison the FT catalyst.Although with proper sizing and maybe addition

of active coal %lters it is likely that the speci%ca-tions can be met, this needs to be tested and veri-%ed in practice. In particular potential problems with

tars give rise to discussion and further research isrequired.

2.5.3. Advanced ‘dry’ hot gas cleaningHot gas cleaning consists of several %lters and sep-

aration units in which the high temperature of the syn-gas can (partly) be maintained, potentially resulting ine?ciency bene%ts and lower operational costs. Hot gascleaning is speci%cally advantageous when preceding


Table 6Possible choices in system components leading to di;erent system con%gurations for BIG-FT systems

Gasi%er Gas cleaning Reforming Shift CO2 removal FT system FT data

BCL Low temp. ATR Intern (iron) Yes Full conversion once �IGT High temp. No ATR Extern (cobalt) No through Fixed bed slurry Once through e?ciencyIGT+EPTPS

a reformer or shift reactor, because these process stepshave high inlet temperatures. When FT synthesis isapplied directly after the gas cleaning, the syngas hasto be cooled to 200◦C anyway, and the potential ben-e%ts are expectedly less apparent. Hot gas cleaningafter atmospheric gasi%cation does not improve e?-ciency, because the subsequent essential compressionrequires syngas cooling anyway.Hot gas cleaning is not a commercial process yet;

some unit operations are still in the experimentalphase. Disadvantageous for the application of hot gascleaning in this case is the high puri%cation require-ments of FT synthesis (see Table 7). It is uncertain ifhot gas cleaning can meet these standards in a fore-seeable timeframe. Research so far is mainly focussedon developing hot gas cleaning to meet the require-ments for BIG=CC installations, for which fuel gasrequirements are less severe. There are no commer-cial processes for the high temperature removal ofnitrogen compounds, halides, alkali metals and heavymetals yet, although various solutions are worked on[15,23,27].

2.5.4. DiscussionConventional ‘wet’ low-temperature syngas clean-

ing is the preferred technology in the short term[23]. This technology will have some e?ciencypenalties though and requires additional waste-watertreatment but there is little uncertainty at presentabout the cleaning e;ectiveness of such systems withrespect to IG-CC installations, both for coal andbiomass-%red facilities [25]. However, actual testingwith biomass=FT systems is still necessary to ensurethe e;ectiveness for these systems.Within 10 years hot gas cleaning may become com-

mercially available for BIG-CC installations [15,28],but opinions di;er. Even when BIG-CC requirementsare met, signi%cant improvements are necessary to

meet the much more severe FT requirements. As aresult, hot gas cleaning is considered as an advancedoption for the longer term in this analysis. To showthe possible e;ect of hot gas cleaning on the perfor-mance of BIG-FT systems, it is included in the systemmodelling work.

2.6. Potential system con>gurations and selection

2.6.1. Key elementsIn theory, a large number of system con%gurations

to convert biomass to FT-liquids and power is possible(Table 6). We make a %rst distinction between twomain categories %rst:

1. Full conversion FT with the possible use of a gasturbine, aimed at maximised FT-liquids production.

2. Once through FT, with co-%ring of the o;gas withnatural gas in a gas turbine.

For all concepts an external shift reactor will beused, implying the use of a cobalt catalyst for FT.Since it is di?cult to predict a speci%c SC5+ forbiomass-derived syngas, e.g. due to di;erent inertpercentages, a realistic SC5+ range of 73.7–91.9% ismodelled. This corresponds to chain growth proba-bilities � of 0.8–0.9. Higher C5+ selectivity seemsunlikely to be obtainable for biomass syngas. As aconventional option a CO conversion of 40% perpass is assumed for the full conversion concepts. Toincrease the overall CO conversion, gas recycle hasbeen employed. As an advanced option 60% and80% once through CO conversion is assumed for theonce through concepts. Advanced FT reactors, either%xed bed or slurry are expected to obtain higher oncethrough CO conversion [8].After the FT synthesis cooling to 50◦C makes it

possible for the C5+ fraction to be separated as liquid.


Further cooling to separate C3 and C4 could be done,but whether this economically attractive is question-able. In the concepts modelled, the C1–C4 fraction isassumed to be used in a gas turbine (combined cycle)for power generation.

2.6.2. Full conversion FT, with possible use of agas turbineThe goal of the full conversion concepts is to max-

imise the yield of FT-liquids (and to a smaller ex-tent on power production). Systems modelled bothinclude and exclude reforming, to study the pay o; be-tween higher FT yield and lower capital investments.The IGT plus option is modelled without reformer andshift, otherwise the basic idea of creating a syngaswith a ‘perfect’ H2=CO ratio would not make sense.In case of the direct atmospheric gasi%cation systems,reforming with air will lower the H2 and CO contentin the syngas because some H2 and CO have to beburned to obtain the necessary process heat. There-fore, this con%guration is not modelled.Amine-based CO2 removal was included in all

con%gurations, as less CO2 allows for a high C5+

selectivity and will therefore increase the amount ofFT-liquids produced. But on the other hand, CO2

removal is an expensive process and it is questi-onable if the high costs are justi%ed by the increasedproduction of FT-liquids. The impact of in- and

Fig. 6. Base Aspen Plus @owsheet used for the calculation of the mass and energy balances.

excluding CO2 removal is therefore investigatedfurther.

2.6.3. Once through FT, with co->ringin a (150 MWe) natural gas-based gas turbineThe once-through concepts produce both FT-liquids

and power. All gasi%ers are modelled without ATRand without CO2 removal, so FT synthesis is not max-imised. This may result in lower capital costs and pos-sibly somewhat higher overall energy e?ciencies. TheIGT gasi%ers, in turn, are also modelled with an aminetreating process, because of their high CO2 content oftheir syngas.

3. System calculations

3.1. Modelling and results

Modelling of the various concepts has been per-formed with the @owsheeting program Aspenplus. Abasic @owsheet is presented in Fig. 6. The gasi%cationprocesses have however not been modelled in Aspen,because the fuel gas compositions resulting from mostbiomass gasi%cation processes are determined by ki-netics instead of equilibrium conditions and thereforevery hard to model. Thus, fuel gas compositions fromliterature are used as starting point for the calcula-tions. The base capacity for all system calculations


Table 7Input data for Aspen modelling. Pressures given in bar

Dryer: per tonne biomass 0:41 tonne steam needed for drying to 10% moisture content, 0.33 for drying to 15%.‘Wet’ cold gas cleaning: Tinlet = 400◦C, Toutlet = 40◦C below dew point, Rp = −0:5 at p¿ 30, Rp = −0:3 at 10¡p¡ 30,Rp=−0:2 at p¡ 10

Hot gas cleaning: Toutlet = 450◦C, Rp=−1ATR: p= 33–44, Rp=−0:5, Tinlet = 400–450◦C, Toutlet = 950◦C, Tair = 600◦C, Toxygen = 300◦C

Shift: 15¡p¡ 70, Rp=−0:5, Tinlet = 330◦C

FT reactor: p = 40, Rp = 5, Tinlet = 200◦C, Toutlet = 240◦C,e;ective H2=COoutlet¿ 0:4, recycle rate (mol@ow recycle=mol@owfresh) ¡ 2, FT steam at p= 22 and T = 230◦C.

Gas turbine: T = 1200◦C but if LHV¡ 6 MJ=Nm3 than T = 1100◦C, expander: isentropic e?ciency = 0:89 (0.9 co-%red)mechanical = 1, compressor: isentropic e?ciency = 0:91 mechanical = 1, pout = 1:2 (0.2 needed for heat exchanger), T@ue gas (afterheat exchanger) ¿ 170◦Ca

Steam turbine: pressure=temperature combinations (T in ◦C): 70=500, 41.4=440, 22=375 (230◦C for FT steam), steam to dryer:p=12, steam to gasi%er: p=1–34, steam for shift: p=15:5–43, steam for ATR: p=20–44, outlet pressure of steam turbine=0:04

Heat exchangers: Rp=−0:5 at p¿ 30, Rp==− 0:3 at 10¡p¡ 30, Rp=−0:2 at p¡ 10, maximum syngas. Syngas heatingis 400◦Cb

aTaken from [15]. Minimum outlet temperature is due to environmental restraints.bDue to coking problems at higher temperatures [26].

Table 8Overall energy e?ciencies (LHV) of the full conversion (40% per pass) concepts and net power (expressed in MWe) and FT-liquidsoutput (expressed in MWth). � = 0:8 corresponds with SC5+ = 73:7%; 0.85 with 83.5%; 0.9 with 91.1%

Concepta BCL BCLR BCL IGT IGT IGT IGT+ EP EP EP TPSR R-nt R R-hg R R-nt

�= 0:80 e;% 45.1 30.1 35.9 44.7 46.1 46.0 44.6 41.6 25.4 42.4 32.9FT-liquids (MWth) 123.9 123.9 66.8 129.9 132.6 81.1 78.4 100 100 64.6 83.1Power (MWe) 41.4 −13:6 65.0 34.2 36.6 87.5 85.4 52.5 −6:7 90.9 37.6�= 0:85 e;% 47.0 33.5 37.1 47.7 49.1 47.4 44.9 44.8 29.4 43.4 34.5FT-liquids (MWth) 139.1 139.1 75.9 150.7 153.4 91.9 89.8 113.3 113.3 73.2 94.2Power (MWe) 33.3 −16:3 60.4 24.4 26.8 82.2 75.0 50.9 −5:5 86.2 32.5�= 0:90 e;% 48.0 38.2 38.1 50.1 51.5 48.2 47.3 45.4 32.2 44.5 35.8FT-liquids (MWth) 154.8 154.8 83.4 168.7 171.4 101.7 97.9 124.6 124.6 80.5 103.6Power (MWe) 21.3 −14:6 56.5 15.2 17.4 75.1 75.7 42.0 −6:5 82.9 27.6

aExplanation of used codes: BCL, IGT, IGT+, EP and TPS = gasi%er names, R = reformer used, nt = no gas turbine, hg =hot gas cleaning.

is %xed at 367 MWth LHVwet (80 tph biomass d.b., at30% moisture).Table 7 summarises the key data used for Aspen

modelling. The overall energy e?ciencies 5 of the fullconversion concepts are presented in Table 8. Here,a distinction is made between outputs by means ofFT-liquids and by net power production (or use).

5 The overall energy e?ciency of the systems is de%ned as:sum of all outputs=total biomass input.

The BCL-R and the EP-R concepts produce o;gaswith a caloric value probably too low for (direct) usein a gas turbine, as part of the methane and ethaneis converted to FT-liquids. The gas turbine is of par-ticular importance for those concepts because withoutthe gas turbine, a substantial amount of energy, in theform of light hydrocarbons (C1–C4) or compressedN2, would be wasted. Co-%ring with natural gas couldbe necessary for these concepts in any case, to upgradethe heating value of the o;gas.


Table 9Overall energy e?ciencies (LHV) of the 60% conversion once through concepts and net power (expressed in MWe) and FT-liquids output(expressed in MWth). � = 0:8 corresponds with SC5+ = 73:7%; 0.85 with 83.5%; 0.9 with 91.1%

concepta BCL IGT IGT-A IGT+ IGT+-A EP TPS

�= 0:80 e;% 35.8 44.1 43.9 43.5 43.6 43.6 33.9FT-liquids (MWth) 49.9 58.9 58.9 57.8 57.8 54.8 69.3Power (MWe) 81.3 103.0 102.2 101.9 102.4 105.1 55.2�= 0:85 e;% 37.2 44.6 44.5 44.6 44.7 44.6 35.2FT-liquids (MWth) 56.6 66.8 66.8 65.4 65.4 62.0 78.5Power (MWe) 79.8 97.0 96.4 98.1 98.8 101.8 50.7�= 0:90 e;% 38.0 45.6 45.4 45.4 45.7 45.5 36.3FT-liquids (MWth) 62.2 73.5 73.5 72.0 72.0 72.0 86.3Power (MWe) 77.2 93.7 93.1 95.0 95.6 98.6 47.0

aExplanation of used codes: A= Amine treating used.

Table 10Overall energy e?ciencies (LHV) of the 80% conversion once through concepts and net power (expressed in MWe) and FT-liquids output(expressed in MWth). � = 0:8 corresponds with SC5+ = 73:7%; 0.85 with 83.5%; 0.9 with 91.1%

Concept BCL IGT IGT-A IGT+ IGT+-A EP TPS

�= 0:80 e;% 37.7 46.4 46.2 45.6 45.7 47.2 36.5FT-liquids (MWth) 66.6 78.6 78.6 77.0 77.0 73.0 92.4Power (MWe) 71.9 91.5 91.0 90.4 90.8 100.4 41.5�= 0:85 e;% 38.9 47.8 47.7 47.0 47.1 48.6 38.2FT-liquids (MWth) 75.4 89.1 89.1 87.3 87.3 82.7 104.6Power (MWe) 67.4 86.3 85.9 85.3 85.8 95.7 35.6�= 0:85 e;% 40.4 49.0 48.9 48.2 48.3 49.8 39.7FT-liquids (MWth) 82.9 98.0 98.0 96.0 96.0 91.0 115.1Power (MWe) 65.3 81.9 81.6 81.0 81.4 91.6 30.5

The overall energy e?ciencies of the once throughconcepts are presented in Tables 9 and 10. All oncethrough concepts make use of a 150 MWe gas tur-bine, so that a certain degree of natural gas co-%ring isnecessary. The net power output in the table is there-fore allocated to the fraction of the energy input ofbiomass-derived o;gas.

3.2. Discussion of results

The modelled concepts give the following insights:

1. The concepts with high overall energy e?ciencyare based on pressurised gasi%ers. When high C5+

selectivity (91.9%) is assumed, IGT-R has anLHV e?ciency of 50.1%, when hot gas cleaningis used 51.5%. The 80% once through conceptsshow that e?ciencies of near 50% are obtainablefor the EP and the IGT gasi%ers, even without theuse of a reformer.

2. CO2 removal has little e;ect on overall energye?ciency—but does have an e;ect on the amountof inert and thus on liquid selectivity. Questionremains if the investment is justi%ed by the im-provement of selectivity.

3. Higher C5+ selectivity leads to higher overall ef-%ciency for all concepts. The obtainable SC5+ isuncertain, but will be in the given range (73.7–91.9%). When much inert is present (as is the casewith air gasi%cation), SC5+ will probably end up inthe lower part of the used range. When little inertis present SC5+ will be higher.

4. The concepts with 80% conversion have higher ef-%ciencies than the concepts with 60% conversion.So a high overall CO conversion has a bene%ciale;ect on e?ciency.

5. Pressurised concepts have higher overall e?cien-cies than atmospheric concepts. The di;erence isabout 10% points. This is mainly due to the highelectricity consumption of syngas compression


when direct, air-blown, atmospheric gasi%ers areused.

6. Methane reforming concepts are most sensitive toC5+ selectivity and only improve e?ciencies whenSC5+ is high. For the BCL concepts methane re-forming does even improve e?ciency at low SC5+ ,due to the high C2+ content of the syngas.

7. Hot gas cleaning improves the e?ciency for pres-surised concepts, with an average of 1–2% points.

The main energy losses in the model are caused bythe gasi%cation section (thermal e?ciency ∼ 80%),the shifting and reforming section (�th ∼ 90%), theFT section (�th ∼ 78% for the converted CO and H2)and the combined cycle (�th ∼ 50%). It is importantto note that the small hydrocarbons (C1–C4) formedin the FT synthesis and used in the gas turbine, leadto energy losses both in the FT section and in thecombined cycle. Also, from the FT section (35 baroutlet pressure) to the gas turbine (14–16 bar inlet) thesyngas loses pressure without producing electricity.An expansion turbine could possible be used to reducethis energy loss, but is not included here.

4. Economics

4.1. Basic principles

The costs for each system con%guration are basedon cost data on component level, which were obtainedfrom literature, vendor quotes and personal commu-nication with experts. For components also present inBIG-CC installations, the free on board (FOB) priceis multiplied with speci%c percentages to obtain theinstalled costs, see Table 11. For some componentsand installations, it is assumed, as a rule of thumb, thatthe FOB price should be tripled to obtain the installedcosts (see Table 11).The capacity or scale of each component is derived

from the energy and mass balances obtained throughthe Aspen modelling. The speci%c costs of most sys-tem components are a;ected by their capacity. Thegeneral relation

Costsb=Costsa = (Sizeb=Sizea)R

applies, where R is the scaling factor. For most systemcomponents used here, the value for R usually liesbetween 0.6 and 0.8.

A maximum size for each unit is taken into account,above which increasing scale is no longer (economi-cally) attractive (see Table 11). When the total capac-ity of a conversion unit exceeds this maximum compo-nent capacity, cost %gures are composed by assumingthat multiple units are built to meet the desired capac-ity. Therefore, overall scale factors are used for mak-ing cost estimates for much larger and smaller scalescompared to the base capacity of 367 MWth.The gasi%ers used have di;erent maximum sizes.

The maximum size of a gasi%er is mainly determinedby two factors: whether the gasi%er operates at ele-vated pressure and whether the plant is located neara harbour. If road transport is considered, the dimen-sions of the road are of importance. When transport ofthe gasi%er to location can be done over water, muchlarger single units can be installed. For the TPS, BCL,IGT and EP gasi%ers, the maximum sizes assumedare 122, 200, 400 and 400 MWth HHV, respectively[21,30,13]. Exact maximum scales cannot be givenbecause existing plants of such size are not yet re-alised in practice, but it can be expected that larger sin-gle pressurised gasi%cation reactors can be built thanassumed here. This is an aspect that requires furtherresearch to enable more exact projections.

4.2. Calculation of production costs of FT-liquids

4.2.1. Investment costsThe calculation of the overall total investment costs

is done on basis of the cost data as presented in Table11. Straightforward discounting is applied by annuity(interest rate of 10% and depreciation period of 15years). Table 12 presents the total calculated invest-ment costs for the various concepts.As an example, the breakdown of the capital costs

for the IGT pressurised gasi%cation concepts is shownin Fig. 7. The pre-treatment, gasi%cation with oxygenand gas cleaning sections account for almost 75% oftotal capital costs. The use of an amine treating processfor CO2 removal will add more than 10% to totalcapital costs.

4.2.2. Production costs of FT-liquidsThe calculated energy e?ciency and overall total

investment costs are used to calculate the productioncosts of pure FT-liquids %rst (without hydrocracking).Key assumptions regarding interest rate and variable


costs are presented in Table 13. The breakeven costsassume a power price of 0.057 US$=kWh (includ-ing a premium for green electricity applicable in theDutch context). Electricity from the grid costs 0.03US$=kWh.Production costs of FT-liquids in full conversion

concepts, are presented in Fig. 8. Production costs forthe 60% and 80% conversion once through conceptsare shown in Figs. 9 and 10. The costs vary for the dif-ferent concepts between 13 and 30 US$=GJ. For bothconcept categories (once through and full conversion),the pressurised (IGT) gasi%er, seems to turn out best.Pressurised systems have a big advantage over atmo-spheric systems. Also, the use of a gas turbine reducesproduction costs.To calculate costs including hydrocracking, a crack-

ing unit is assumed to have installed costs of MUS$8.1 per 2000 bbl=day. Using 13.1% annual deprecia-tion this comes down to 0.26 US$=GJ FT-liquid. Thee?ciency of the hydrocracking process is assumed tobe 98% and the H2 consumption is 176 g=GJ FT-liquid(0.17 US$=GJ FT-liquid). Overall costs for hydroc-racking become 0.72 US$=GJ, being about 5% on topof the FT-liquids production costs.CO2 removal has a strong impact on overall pro-

duction costs. For this reason production costs arealso calculated without the amine treating process,for the same e?ciencies and selectivities. The caloricvalue of the o;gas, however, will be lower due tothe higher CO2 content. This could hinder direct useof the o;gas in the gas turbine, but co-%ring is stillpossible.The concepts cannot be compared directly. De-

pending on the amount of inert in the FT reactor,C5+ selectivity will di;er. For example, the EP oncethrough concept seems slightly better than the IGTonce through concept. But the IGT process, with littleinert in its syngas, is more likely to have high liquidselectivity than the EP process, which has a largeamount of inert in its syngas.From Fig. 8 it appears that CO2 removal is a bad

option for all full conversion concepts. However, ifthe reduction of inert by means of CO2 removal resultsin a liquid selectivity rising from 73.7 to 91:9 (� =0:8 → 0:9), it does have a positive e;ect on productioncosts. The quantitative impact of the amount of inert onSC5+ is not known, however, and needs further detailedstudy and testing.

It is more e?cient to produce FT-liquids (78% ther-mal e?ciency) than power (approximately 55% ef-%ciency using state-of-the-art combined cycles). Ifonly C5+ is separated as liquid, it becomes more e?-cient to produce power when the C5+ selectivity dropsbelow 35%.When comparing once through with full conversion

concepts one should realise that the once through con-cepts make use of more advanced FT reactors, withhigher conversion per pass. The once through optionsalso make use of a co-%red gas turbine. The co-%redgas turbine has higher energy e?ciency and bene%tsfrom lower speci%c investment costs.

4.3. Sensitivity analysis and longer termperspectives

4.3.1. Sensitivity analysis of key parametersThe parameters that a;ect the %nal FT fuel costs

strongest are shown in Table 14, including the po-tential range between which these parameters mayvary. A sensitivity analysis has been performed forthese parameters over the given range. Fig. 11 showsthe results of doing so for the IGT-R concept atSC5+ = 83:5% (in which case 14% of the total en-ergy output is power). Overall total investment costsfor this concept are about 380 MUS$ and O&M isabout 14 MUS$ annually. When power output ishigh (54% of the total energy output for the EP fullconversion concept at SC5+ = 83:5%), the sensitivityto the electricity value is much stronger. When allparameters are set at their ‘base’ value, productioncosts of FT-liquids are 14 US$=GJ. This value can becompared to the current production costs of around5 US$=GJ for diesel.Economies of scale have a considerable in@uence

on overall production costs. When scale is between100 and 400 MWth the overall scaling factor for theentire plant (with respect to overall total investmentcosts) is approximately 0.74. When capacities go be-yond 400 MWth, the average scaling factor increasesto 0.91 (indicating decreasing cost reductions). Theresults for doing so are shown in Fig. 12 for the IGT-Rconcept. Based on the component data and assump-tions made, it can be concluded that scale e;ects levelo; at very large capacities. Scale up reduces costs from14 US$=GJ at 400 MWth to 12 US$=GJ at 1600MWth,a reduction of 14%. When the capacity is smaller


Table 11Basic costs for all units used with their maximum size (base costs are in relation to base scales). Costs expressed in MUS$

Base cost Scale factor Base scale Unit maximum size(for scales considered)

Pre-treatmentConveyersa 0.33 0.8 69:54 MWth LHV 367Grindinga 0.43 0.6 69:54 MWth LHV 367Storagea 1.05 0.65 69:54 MWth LHV 367Dryera 7.71 0.8 69:54 MWth LHV 367Iron removala 0.33 0.7 69:54 MWth LHV 367Feeding systema 0.38 1 69:54 MWth LHV 367

Gasi>ersGasi%er TPSa 3.24 0.7 69:54 MWth LHV 105Gasi%er BCL (incl. feeding)b 13.0 0.7 400 MWth HHV 200Gasi%er EPc 400Gasi%er IGTc 30 0.7 400 MWth HHV 400

Gas cleaningTar crackera 3.24 0.7 69:54 MWth LHV 105Cyclonesa 2.57 0.7 69:54 MWth LHV 367Gas coolinga 2.95 0.7 69:54 MWth LHV 367Baghouse %ltera 1.62 0.65 69:54 MWth LHV 367Condensing scrubbera 2.57 0.7 69:54 MWth LHV 367Hot gas cleaningd 14.3 400 MWth HHV None

CompressorsCompressore 12.0 0.85 13:2 MWe None

Combined cycleGas turbinea 7.7 0.7 25 MWe NoneModi%cations turbine LCV gasa 8% 0.7 69:54 MWth LHV NoneHRSGa 3.38 0.8 47:5 tonne=h NoneSteam turbine + condensera 4.48 0.7 12:3 MWe NoneWater + steam systema 0.43 0.9 49:5 tonne=h NoneCoolinga 0.95 0.3 50:5 tonne=h None

Sub1: Total hardware costsInstrumentation and controlf 5% of hardwareBuildings 1.5% of hardwareGrid connections 5% of hardwareSite preparation 0.5% of hardwareCivil works 10% of hardwareElectronics 7% of hardwarePiping 4% of hardware

Sub2: Investment costsEngineeringg 15% of investment costs

Sub3: Total installed costsh

Oxygen planti 23.0 0.75 24 tonne=h NoneATR reactorj 30.3 0.7 400 MWth NoneShift reactork 0.45 0.6 2400 kmol=h NoneAmine treatingl con%dential 0.65 400 MWth InputFT reactorm 16.7 1 100 MW FT-liquid NoneZnO bedsn 0.13 1 None

aCosts %gures based on %rst generation BIG=CC installations, taken from Faaij (1998).bCosts %gures taken from [29].


Table 12Overall total investment costs in MUS$ for all concepts (367 MWth input; LHV wet (biomass supplied at 30% moisture content)

Full conversion concepts BCL-R BCLnt BCL IGT-R IGT-hg IGT IGT+ EP-R EP-R-nt EP TPS

Total investment costs 395 363 312 387 358 339 341 449 417 364 386Idem without Sul%nol D 366 334 292 349 320 305 316 396 363 322 344

Once through concepts, 60% and 80% BCL IGT IGT-s IGT+ IGT+-s EP TPSTotal investment costs 281 305 338 297 310 325 331

than 400 MWth, costs strongly increase, however, andsmall-scale production of FT-liquids is economicallynot feasible.

4.3.2. Short- and long-term perspectiveResults so far represent technology and perfor-

mance that could be realised on shorter term. How-ever, on the longer term various improvements may befeasible. These include: increasing C5+ selectivity, in-creasing scale, lowering feedstock costs, reductionofinvestment and O&M costs through technologicallearning, and application of hot gas cleaning. For the

←−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−cThe Enviro Power gasi%er and the IGT gasi%er, both operating at elevated pressure, have likewise designs. Therefore, costs are assumed

to be the same for both types of gasi%ers. Cost %gures for IGT taken from [29].dThese costs are an assumption. No real world data are available.eVendor quote (Sulzor).f Percentages take from Faaij [16], valid for BIG=CC installations. Adding these percentages to capital costs (free on board, FOB) will

result in installed costs.gEngineering is already included in the installed costs for the oxygen plant, ATR, shift, Amine treating, FT and ZnO units.hFor the units below the percentages as discussed in footnote f are probably not valid. Therefore installed costs were calculated directly

or the FOB price was tripled to obtain the installed costs.i576 t=d oxygen production of 95%v purity has a capital cost of 31,000 US$ per t=d, for 1008 t=d the costs are 27,000 per t=d [22].

Oxygen of 99.5% purity requires 5% extra capital costs [22]. Costs are indexed to 1999 US$ using a Consumer Price Index of 0.816.jFOB price for the ATR is 10.1 million US$ [29]. Multiplying with three gives the installed costs.kCalculations were done on basis of Nm3 @ow and necessary reactor height. Given base unit gives a good representation of this.lCalculations were done on basis of Nm3 @ow and necessary reactor height.mCalculated for a %xed bed reactor. No cost data are available for slurry reactors. Main factor used is the amount of CO converted to

FT-liquids (in MW, HHV based). One catalyst loading is included in these costs.nAssuming 1% wt of S (excluding N2) entering the ZnO bed, two guard beds of 3 m3 are necessary. This will take about

2300 kilos of steel. Using a steel price of US $9.5=kilo, each guardbed will cost US $22,000 (FOB) or US $66,000 installed.

To calculate overall total investment costs on top of the installed costs were increased with the following percentages [15]:

Building interest. 1st yearo 25% Installed costs× interest rateBuilding interest. 2nd year 75% Installed costs× interest rateProject contingency 10% Installed costs× interest rate

Sub 4: Total investment costsFees=overheads=pro%ts 10% of total investmentStart-up costs 5% of total investmentOverall total investment costs

oInterest rate used is 10%.

short and long term the key assumptions made aresummarised in Table 15. The type of assumptions forthe short and longer term reasonably represent a %rstcommercial plant and a plant that could be built aftera period of 1–2 decades from now.The cost-breakdown for the short and long term is

given in Fig. 13. Capital costs represent about 50%of the overall production costs of FT-liquids. Reduc-tion of these capital costs for a third-generation plant,due to scaling up (12%) and technological learning(15%) therefore have a considerable impact on overallproduction costs. O&M costs may decrease almost


pre-treatment

21%

gasifier18%

oxygenplant15%

cleaningsection

18%

FT reactor6%

gas turbine7%

HRSG11%

others4%

shift1%

Fig. 7. Breakdown of installed costs for the IGT 80% conversionconcept (367 MWth LHV).

proportionally with the reduction of the capital costs.The share of biomass feedstock costs (on themselvesassumed to remain constant for the short and longterm, see footnotes under Table 15) will decrease perGJ FT-liquid due to an increase of overall energy ef-%ciency. Overall energy e?ciency will be higher fora third-generation plant, due to higher C5+ selectivityand higher (once through) CO conversion.As a result of the reduction in capital costs and

biomass costs per GJ FT-liquid, production costs ofFT-liquids could drop from over 14 to 9 US$=GJ.

Table 13Main assumptions for calculating the overall production costs of FT-liquids

Cost factor Unit Input for 427 MWth

Annual depreciationa 13.1% of investmentBiomass costsb 2 US$=GJ (LHV) 10 560 000

Operational costsMaintenance 3% of investmentPersonnelc 0.7 MUS$=100 MWth LHV 367Dolomited 47.6 US$=tonne 25 728Waste-water treatmente 0.21 MUS$l=75 MWth LHV 367NaOH consumptione 1.3 KUS$=tonne NaOH 44 800ZnO consumption [31] 33.3 KUS$=yearFT cat. consumption insurance 1% of annual depreciation Con%dential

areal interest rate = 10%; depreciation period = 15 years.b11:55 GJ=tonne wet, 30% moisture, load factor = 8000 h=year.c[15] a scaling factor of 0.25 is used.d[15] dolomite is only used when by a tar cracker is applied.e[15] waste water treatment and NaOH consumption only if low temperature gas cleaning is applied.

It can be concluded that in the short term pres-surised BIG-FT systems have production costs ofFT-liquids higher than 14 US$=GJ. Atmospheric,air-blown gasi%cation-based systems result in muchhigher production costs. None of the concepts, eitheratmospheric or pressurised, have production costs thatare competitive with current diesel costs of around5 US$=GJ. By including a number of improvementoptions, production costs of FT-liquids can drop toaround 9 US$=GJ. This is still above current dieselcosts. Obviously, biomass-derived FT-liquids becomemore attractive with rising oil prices. Although pro-jections for the future oil price development are highlyuncertain, expected price ranges for diesel in 2020go up from 5.5 to 7 US$=GJ [30]. Considering theinherent uncertainties in price estimates as composedfrom data reported in this study, the fact that not allimprovement options for biomass-based FT synthesisare considered in this study, the longer term economicperspectives for biomass-derived hydrocarbons in thetransport is not unattractive.In addition it must be stressed that biomass-derived

FT-liquids have very di;erent characteristics thandiesel from mineral oil. FT-liquids contain littleor no contaminants (like sulphur and aromates)and are therefore suited for use in FCV when onboard reforming (by means of partial oxidation) isapplied. Such technology is already demonstratedat present, but requires very clean fuel to avoid


0

5

10

15

20

25

30

35

BCL-R BCL-R-nt BCL IGT-R IGT-R-h IGT IGT+ EP-R EP-R-nt EP TPS

US

$/G

J F

T li

qu

id

alpha=0.85

alpha=0.9

ex-sulfinol

ex-sulfinol

ex-sulfinol

level

low premium

high premium

alpha=0.8

Fig. 8. Production costs per GJ FT-liquid for the full conversion concepts (40% conversion per pass), assuming a power price of 0.057US$=kWh. Scale used is 367 MWth LHV. � = 0:8 corresponds with SC5+ = 73:7%; 0.85 with 83.5%; 0.9 with 91.1%. ex-CO2 representconcepts where CO2 removal is omitted.

0

5

10

15

20

25

30

BCL IGT IGT-S IGT+ IGT+-S

EP TPS

US

$/G

J F

T li

qu

id alpha=0.8

alpha=0.85

alpha=0.9

level

low premium

high premium

Fig. 9. Production costs per GJ FT-liquid for the 60% conver-sion once through concepts, assuming a power price of 0.057US$=kWh. Scale used is 367 MWth LHV. � = 0:8 correspondswith SC5+ = 73:7%; 0.85 with 83.5%; 0.9 with 91.1%.

poisoning of the fuel cell catalyst. On longer term, thiscan allow higher vehicle e?ciency compared to cur-rent diesel %red internal combustion engine vehicles[e.g. 2, 13]. In total, the real value of FT-liquids canthan be considered to be higher than conventionaldiesel due to inherent higher e?ciency utilisation and(much) lower emission levels for e.g. sulphur, sootand other contaminants. The carbon neutral charac-ter of FT-liquids is of course the key di;erence withconventional diesel. Altogether, this may providea basis for a premium on ‘green’ biomass-derived

0

5

10

15

20

25

BCL IGT IGT-s IGT+ IGT+-s

EP TPS

US

$/G

J F

T l

iqu

id alpha=0.8

alpha=0.85

alpha=0.9

level

low premium

high premium

Fig. 10. Production costs per GJ FT-liquid for the 80% conver-sion once through concepts, assuming a power price of 0.057US$=kWh. Scale used is 367 MWth LHV. � = 0:8 correspondswith SC5+ = 73:7%; 0.85 with 83.5%; 0.9 with 91.1%.

FT-diesel compared to conventional transport fuels(or kerosene).In the case of the Netherlands (but similar systems

are observed throughout Western Europe), a premiumis paid for green electricity varying between 0.024 and0.038 US$=kWh (on top of the grid price of 0.028US$=kWh). This is equivalent to a premium between6.7 and 10.5 US$=GJ fuel on energy basis. Normal pro-duction costs of diesel are around 5 US$=GJ, depend-ing on oil prices. Assuming that a similar premiumis paid for ‘green’ FT-liquids as is done for ‘green’electricity, ‘green’ diesel, naphtha and kerosene must


Table 14Main parameters used and ranges for the sensitivity analysis

Parameter Value Range

Biomass costs US $2=GJ 2.1–8.4Capital costs MUS $380 50–175%

(varies per concept)Electricity value US $0.057=kWh 0.03–0.07Load factor 8000 h=year 7588–8760Real interest rate 10 6.25–15Depreciation period 15 years 9.4–22.5

have production costs between 10.7 and 14.5 US$=GJto be competitive. These values are also shown inFigs. 8–10. Such premium levels would make produc-tion of FT-liquids from biomass already economicallyattractive on the short term. It is interesting to note that

5

10

15

20

25

50% 75% 100% 125% 150% 175% 200%

parameter variation

US

$/G

J F

T li

qu

id

biomass costs

capital costs

electricity value (lowoutput)electricity value (highoutput)load factor

real interest rate

depreciation period

Fig. 11. Sensitivity of production costs of the IGT-R concept to parameters used.

0

5

10

15

20

25

30

35

40

100

500

1000

1600

US

$/G

J F

T li

qu

id

scale (MWth)

Fig. 12. E;ect of scale on the production costs of FT-liquids; production costs of 14 US$=GJ are assumed at 400 MWth. Biomass feedstockcosts are assumed constant here, where in practice biomass costs could slightly increase for larger scales due to higher logistic costs [32].

the premium for green energy is lower than current theDutch excise duty on diesel (as is the case for manyother European countries). On the long term required‘premiums’ could be far lower or even unnecessary tomake biomass-derived FT-fuels cost competitive withdiesel per kilometer driven.

5. Conclusions and recommendations

This study presented a broad exploration of thepossibilities to produce synthetic hydrocarbons frombiomass via gasi%cation and Fischer Tropsch synthe-sis. A wide variety of potential conversion systemcon%gurations has been evaluated including energye?ciencies and economics.


Table 15Assumptions for the short and long term

Short term (%rst commercial plant) Long term (third generation)

IGT full conversion (40% once through, ex-Sul%nol) is thebest concept

IGT once through 80% conversion (with high e?ciency gasturbine) is the best concepta

Obtainable �= 0:8 Obtainable �= 0:9Scale of the system is 400 MWth Scale of the system is 1600 MWth

b

Biomass costs are US $2=GJ Biomass costs are US $2=GJc

Technological learning reduces capital costs with 15%d

aHot gas cleaning has not been modelled for this concept since only a shift reaction is used for this concept. In that case stillsome cooling down is needed after the hot gas cleaning and consequently e?ciency advantage will be smaller.

bAn overall scaling factor of 0.91(with respect to overall total investment costs) is used.cIn the longer term biomass costs may be lower, but larger scales will increase costs again [32].dTechnological learning can be assumed on longer term. This can be expressed by a progress curve; such curves are determined

by a progress ratio. A progress ratio of x implies that each doubling of cumulative output leads to a (1− x)× 100% reduction incosts. A progress ratio of 0.9 is used, applied for a third generation plant built. This results in 15% lower capital costs [e.g. 15].

0

5

10

15

20

short term long term

US

$/G

J Biomass

O&M

Investment co sts

Fig. 13. Cost breakdown for production of FT-liquids from biomass(excluding hydrocracking) for the short and the long term.

Systems applying pressurised gasi%ers (IGT andEP) have much better overall energy e=ciencies(42–50% LHV) than atmospheric systems (33–40%).This is mainly due to the high electricity consumptionof the syngas compressors when atmospheric gasi%ersare used.High CO conversion, either once through or after

recycle of unconverted gas, and high C5+ selectivityare important for high overall energy e?ciencies.In the short term, production costs of FT diesel,

naphtha and kerosene could be about 14–16 US$=GJ.Capital costs represent about 50% of the overall pro-duction costs of FT-liquids. The pre-treatment, gasi-%cation (with oxygen) and cold gas cleaning accountfor almost 75% of total capital costs. Biomass costsare 30% of total production costs (assuming a biomassprice of 2 US$=GJ), and operation and maintenanceabout 20%.

In the longer term with large-scale production, highC5+ selectivity, high CO conversion and technolog-ical learning, production costs of FT-liquids coulddrop to 9 US$=GJ. Reduction of capital costs for athird-generation plant, due to scaling up and techno-logical learning have a signi%cant impact on overallproduction costs. Feedstock costs per GJ FT-liquid de-crease due to an increase of overall energy e?ciency,especially because of higher C5+ selectivity and higher(once through) CO conversion. When diesel is thedesired %nal product (besides 60% diesel, 40% naph-tha and kerosene are produced), the FT product re-quires additional hydrocracking. Hydrocracking willadd about 5% to production costs. Production costs of‘green’ FT-diesel, naphtha and kerosene are not com-petitive with conventional diesel prices, which costabout 0.14 US$=litre or 5 US$=GJ. In the longer termconventional diesel prices could go up due to higheroil prices, but still ‘green’ FT-liquids (9 US$=GJ)will not be competitive with expected diesel prices(5–7 US$=GJ).There are several uncertainties with respect to the

technology status. A very critical step in the wholesystem is gas cleaning. It still has to be provenwhether the gas cleaning section is able to meetthe strict cleaning requirements for FT synthesis,especially the high temperature concepts which arerequired to obtain the desired higher energy e?cien-cies. Possibly amine-based CO2 removal is requiredfor cleaning purposes, thereby raising productioncosts. The used syngas compositions as produced


by the di;erent gasi%ers have strong in@uence onoverall results. Most data are taken from literatureand based on pilot-scale operating experience. Thereliability of these data for large-scale gasi%ers is notknown in great detail. Pressurised (oxygen) gasi%ca-tion systems, having most promising economics andadvantages of scale, still need further development.At present, only atmospheric air gasi%cation systems,operating at relatively small scale, have proved to bereliable.Not all possible concepts have been investigated

though. Separating the C3–C4 fraction as liquid prod-uct from the FT synthesis could be more advantageousthan combustion of this fraction in a gas turbine. Alsovariable gasi%cation temperatures could make otherreforming methods possible, like partial oxidation andsteam reforming, due to a di;erent C2+ content. Forthe concepts modelled, however, reforming did not re-sult in lower production costs. Lowering the pressurein the FT reactor will cause selectivity to drop, but onthe other hand compression costs will also be lower.Using an iron catalyst could reduce production costsdue to an internal shift reaction. This is to be inves-tigated further. In the long term, the e?ciency of theconcepts will be higher if high selectivity can be com-bined with high once through conversion. This couldbe realised in either %xed bed or slurry reactors. Costsfor slurry reactors, which are not available yet, couldbe lower than for %xed bed reactors and are very likelyto have better economies of scale. Heat integration ofthe total plant can also be improved. Power generationin the gas turbine will improve if the scale is largerand when on the longer term more e?cient turbineswill enter the market [15].This study did include co-%ring with natural gas

for power generation with combined cycles as an‘improvement’ option. Co-feeding FT synthesis wasnot included but could lead to some e?ciency andscaling bene%ts as well.The overall energy e?ciency, a critical parameter

in obtaining good economic performance when moreexpensive cultivated biomass is proceeded, may be in-creased by optimised gas turbine technology [e.g. 15]and also improved selectivity for the FT process ap-plied. With further catalyst and process developmenthigher selectivities may be obtained, improving thenet yield of the most valuable commodity of the pro-cess: transport fuel.

Technological learning over time and economies ofscale were roughly included in the cost projections forlonger term, but not investigated in great detail. Es-pecially, for pressurised gasi%cation larger scales mayprove to be more attractive than projected here andcombinations with enriched air gasi%cation (eliminat-ing the expensive oxygen production assumed in thisstudy) may also reduce costs further.Altogether, the full technological improvement po-

tential requires further study. Another key variable isthe feedstock costs. (Cultivated) biomass is assumedto cost 2 US$=GJ. At present, this is low for West-ern Europe, but high compared to Brazilian biomassproduction costs (from Eucalyptus). Production ofFT-liquids in regions where biomass feedstock ischeap (or by using co-products or biomass residues)will positively a;ect the economics of FT productionfurther.It can be concluded that in the short term pres-

surised BIG-FT systems have production costs ofFT-liquids higher than 14 US$=GJ. Atmospheric,air-blown gasi%cation-based systems result in muchhigher production costs. None of the concepts, eitheratmospheric or pressurised, have production costscompetitive with current diesel costs of around 5US$=GJ. By including a number of improvementoptions, production costs of FT-liquids can drop toaround 9 US$=GJ. This is still above current dieselcosts. Obviously, biomass-derived FT-liquids becomemore attractive with rising oil prices. Projections forthe diesel price in 2020 range from 5.5 to 7 US$=GJ[13]. Considering the inherent uncertainties in priceestimates as composed from data reported in thisstudy, the fact that not all improvement options forbiomass-based FT synthesis as discussed above areconsidered in this study, the longer term perspectivefor biomass-derived hydrocarbons for the transportsector is promising.In addition, it must be stressed that biomass-derived

FT-liquids have very di;erent characteristics thandiesel from mineral oil. FT-liquids contain little orno contaminants (like sulphur and aromates) and aretherefore suited for use in fuel cell vehicles when onboard reforming is applied. On longer term, this canallow a higher vehicle e?ciency compared to cur-rent diesel %red internal combustion engine vehicles[e.g. 2, 13]. In total, the real value of FT-liquids canthan be considered to be higher than conventional


diesel due to inherent higher e?ciency utilisation and(much) lower emission levels for e.g. sulphur, sootand other contaminants.Recommendations for further actions and research

are:

• The gas cleaning section needs special attention.Proper data sets of contaminants in the syngas mustbe made, with high detection accuracy. Deep, hotgas cleaning is promising as such, but will requireeven more development before su?cient cleaningis guaranteed.

• Pressurised biomass gasi%cation must be developedfor large-scale FT plants, but require demonstrationat full scale.

• For the use of biomass syngas in the FT synthesis,high liquid selectivity is desirable. The FT process(either a %xed bed or a slurry process) needs to becon%gured to ful%ll this need.

• Development of sustainable forestry is necessary toensure a large enough supply of clean wood. E;ortsmust be made to create a working biomass marketand reduce prices of biomass, from various sources,over time.

• Markets should be explored to determine what theoutlets are for FT naphtha and kerosene, and if a‘green’ fuels premium will be paid for these prod-ucts, which is particularly relevant for the shortterm.

Acknowledgements

The authors would like to thank all experts whoassisted in providing comments, insights and infor-mation: Mr. Hogendoorn from Foster Wheeler, RickKnight from the Institute of Gas Technology USA,Mr. Mitchell from IEA Coal Research UK, Kari Salofrom Carbona Oy Finland, Mr. Vosloo from SasolSouth Africa and various other experts consulted forthis study.Shell Global Solutions, Amsterdam, the Nether-

lands, is thanked for supervising part of and contribut-ing to the research activities carried out in this study.The Netherlands Energy Research Foundation ECN(Ren,e van Ree, Herman den Uil) is thanked for struc-tural collaboration and exchange in this area. Samen-werkingsverband Duurzame Energie SDE (Professor

Kees Daey Ouwens) and Shell International (PeterKwant) are thanked for co-funding part of the work.

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[22] Hogendoorn J. Project manager at Foster Wheeler. Writtencommunication on biomass gasi%cation, 2000.

[23] Van Ree R, Oudhuis ABJ, Faaij A. Modellingof a biomass-integrated-gasi%er=combined-cycle (BIG-CC)system with the @owsheet simulation program Aspen-plus.

Petten, The Netherlands: Netherlands Energy ResearchFoundation ECN, 1995.

[24] Tijmensen M. The production of Fischer-Tropsch liquidsand power through biomass gasi%cation. Utrecht, TheNetherlands: Utrecht University=Science Technology andSociety, 2000.

[25] Consonni S, Larson ED. Biomass-gasi%er=aeroderivativegas turbine cycles. Part A: technologies and performancemodelling. Part B: performance calculations and economicassessment. Cogen Turbo Power 1994. Portland, Oregon,USA, 1994.

[26] Williams RH, Larson ED, Katofsky RE, Chen J. Methanol andhydrogen from biomass for transportation, with comparisonsto methanol and hydrogen from natural gas and coal.Princeton, NJ: Princeton University=Center for Energy andEnvironmental Studies, 1995.

[27] Mitchell SC. Hot gas cleanup of sulphur, nitrogen, minor andtrace elements. London, UK: IEA Coal Research, 1998.

[28] Mitchell SC. Expert at IEA Coal Research. Writtencommunication on advanced gas cleaning systems. 2000.

[29] Salo K. Director of Carbona Oy Finland. Written com-munication on biomass gasi%cation, 2000.

[30] Statistical Review of World Energy 1999. BP Amoco. 1999.[31] www.shell.com. 1999.[32] Jager B. Developments in Fischer-Tropsch technology.

Dymmy 1997;107:219–24.

http://www.shell.com.

CAMPUS MONTERREY



APPENDIX 4

Alberto Mendoza, Porfirio Caballero, Juan A. Villarreal and Ricardo Viramontes. Performance of a Semi-Industrial Scale Gasification Process

for the Destruction of Polychlorinated Biphenyls. J. Air & Waste Manage. Assoc. 56 (2006) 1599–

1606

Performance of a Semi-Industrial Scale Gasification Processfor the Destruction of Polychlorinated Biphenyls

Alberto MendozaDepartment of Chemical Engineering, Instituto Tecnologico y de Estudios Superiores deMonterrey, Monterrey, Mexico

Porfirio CaballeroCenter for Environmental Quality, Instituto Tecnologico y de Estudios Superiores de Monterrey,Monterrey, Mexico

Juan A. Villarreal and Ricardo ViramontesTernium Hylsa, San Nicolas de los Garza, Nuevo Leon, Mexico

ABSTRACTA semi-industrial scale test was conducted to thermallytreat mixtures of spent oil and askarels at a concentrationof 50,000 ppm and 100,000 ppm of polychlorinated bi-phenyls (PCBs) under a reductive atmosphere. In average,the dry-basis composition of the synthesis gas (syngas)obtained from the gasification process was: hydrogen46%, CO 34%, CO2 18%, and CH4 0.8%. PCBs, polychlo-rinated dibenzo-p-dioxins, and polychlorinated dibenzo-furans (PCDDs/PCDFs) in the gas stream were analyzed byhigh-resolution gas chromatography (GC)-mass spec-trometry. The coplanar PCBs congeners 77, 105, 118, 156/157, and 167 were detected in the syngas at concentra-tions �2 � 10�7 mg/m3 (at 298 K, 1 atm, dry basis, 7%O2). The chlorine released in the destruction of the PCBswas transformed to hydrogen chloride and separated fromthe gas by an alkaline wet scrubber. The concentration ofPCBs in the water leaving the scrubber was below thedetection limit of 0.002 mg/L, whereas the destructionand removal efficiency was �99.9999% for both testsconducted. The concentration of PCDDs/PCDFs in thesyngas were 8.1 � 10�6 ng-toxic equivalent (TEQ)/m3 and7.1 � 10�6 ng-TEQ/m3 (at 298 K, 1 atm, dry basis, 7% O2)for the tests at 50,000 ppm and 100,000 ppm PCBs, re-spectively. The only PCDD/F congener detected in the gaswas the octachloro-dibenzo-p-dioxin, which has a toxicequivalent factor of 0.001. The results obtained for otherpollutants (e.g., metals and particulate matter) meet the

maximum allowed emission limits according to Mexican,U.S., and European regulations for the thermal treatmentof hazardous waste (excluding CO, which is a major com-ponent of the syngas, and total hydrocarbons, whichmainly represent the presence of CH4).

INTRODUCTIONThermal destruction of hazardous and nonhazardouswaste through incineration processes is a technology thathas been used for some time. Incinerators are designed tooptimize the possibility of complete oxidization of thewaste and generate, mainly, CO2 and water in the com-bustion gases and ash in the remaining solid phase. Anundesirable characteristic of incinerators is that they tendto produce and/or emit toxic compounds, such as heavymetals and polychlorinated dibenzo-p-dioxins (PCDDs)and polychlorinated dibenzofurans (PCDFs).1–5

Other thermal technologies are available to explorethe treatment of hazardous and nonhazardous waste, likegasification.6 Thermal destruction of a carbonaceous ma-terial can occur under three main conditions based on theavailability of oxygen: (1) combustion (oxidizing atmo-sphere), (2) gasification (limited oxygen producing a re-ductive atmosphere), and (3) pyrolysis (absence of oxy-gen). Gasification has multiple benefits that make itsuperior to incineration, the most important being thedestruction of waste material and the production of asynthesis gas or syngas (CO � H2) that can be used as rawmaterial for other processes or energy generation.6,7 Anadditional benefit is that the probability of producingPCDDs/PCDFs can be reduced because of the high tem-peratures and reductive atmosphere inside the equip-ment, particularly with waste having high-chlorine con-tent. Pyrolysis has also being explored as an alternative toincineration.8 Depending on the feedstock, a pyrolysisprocess can produce three main products: char (or coke),pyrolysis oil, and synthesis gas, whereas gasification willonly produce synthesis gas as its main product. Pyrolysishas been used, for example, for production of coke fromplastics,9,10 syngas from easily degradable oil wastes,11

IMPLICATIONSGasification technology has in the past few years gainedrenewed interest because of its flexibility to be used inclassical petrochemical processes, in the energy sector, orto valorize waste products. Here we present an applicationwhere gasification is used to treat contaminated oil withPCBs, obtaining high-destruction efficiencies and a com-mercially valuable effluent. The technology could be ex-tended to treat other hazardous waste, making it a feasiblealternative to incineration or other technologies.

TECHNICAL PAPER ISSN 1047-3289 J. Air & Waste Manage. Assoc. 56:1599–1606

Copyright 2006 Air & Waste Management Association

Volume 56 November 2006 Journal of the Air & Waste Management Association 1599

and valuable liquid organic compounds from waste oils.8When using pyrolysis to treat hard-to-degrade waste, typ-ically a considerable amount of char is produced that canbe of value or is sent to a gasification step to completeits destruction.12,13 Here, a high yield for synthesis gaswas established and, thus, gasification was favored frompyrolysis.

The treatment of waste contaminated with polychlo-rinated biphenyls (PCBs) is a serious problem around theworld. Several technologies that depart from classic incin-eration have been published in the open literature to treatwaste contaminated with organic compounds, and par-ticularly PCBs, including steam plasma14–16 and solventextraction,17 followed by chemical dehalogenation or ra-diolitic dechlorination,18,19 chemical oxidation,20–24 elec-trochemical dehalogenation,25 and biodegradation.26,27

In the United States, the U.S. Environmental ProtectionAgency (EPA) has considered an exclusion from the Re-source Conservation and Recovery Act for secondary oil-bearing refinery materials when processed in a gasifica-tion system.6,28 The industry has suggested that EPAinclude gasification of any carbonaceous material in suchan exclusion. Here we explore the gasification of mixturesof oils contaminated with PCBs as an additional cost-effective alternative to safely manage PCBs. The experi-ments were conducted in a facility located in Monterrey,Mexico. The facility used for the test is now a commercialsite dedicated to treat spent oils contaminated with PCBs.

Gasification ProcessesGasification is a technology that thermally breaks downsolid or liquid organic material (in fact, any carbonaceousmaterial) to simple molecules (CO � H2) under an atmo-sphere poor in oxygen, that is, a reductive atmosphere, bysupplying a gasification agent (typically steam).7,29 Thegas stream produced is known as synthesis gas or syngas.The gasification process has been studied extensively,and, in practice, the syngas obtained is used as fuel togenerate electricity and steam and as raw material in theproduction of a vast amount of chemical compounds,such as methanol and ammonia.6,30

If PCBs are present in the feedstock of a gasifier, aconsiderable amount of chlorine will be present in the

reacting mixture, and, thus, the fate of such chlorinemolecules is of interest because of their potential partici-pation in the formation of PCDDs/PCDFs. It has beenobserved that gasification products in real applicationstend to closely follow model predictions that assume ther-modynamic equilibrium.31 If this is the case, one canargue that the reductive conditions in the gasificationreactor thermodynamically favor the chlorine beingpresent in the HCl form (i.e., the Deacon process reaction2HCl[g] � 1⁄2O2[g] 7 Cl2[g] � H2O[g] will tend to the left-hand side product because of the absence of O2 and thepresence of H2O as the gasifying agent), limiting theamount of Cl2 produced, and thus reducing the probabil-ity of chlorination of aromatic ring structures and conse-quently the formation of PCDDs/PCDFs.6,32 At the end ofthe process, gas-phase HCl present in the syngas can eas-ily be absorbed in water to generate an aqueous solutionof hydrochloric acid. In fact, the fate is the same for otherorganic compounds. Other authors have demonstrated ordocumented that gasification of chlorinated solvents33

and, in general, municipal solid waste34 and hazardouswaste, is feasible,6 and in theory such compounds, likechlorofluorocarbons and pesticides, could also be treatedby this technology.

Process DescriptionThe gasification reactor used in this study is a 3.8-m3

vertical reactor, originally manufactured by M.W. Kellog,Co., and made of carbon steel ASTM 285 – Grade C, withfour different insulation covers (two of concrete, refrac-tory brick, and ceramic fiber). The total length of thereactor is 7.35 m. The main body of the reactor is acylinder of 4.20 m in length and 0.89 m in i.d. On theextremes, the reactor narrows to accommodate on oneside the burner (top) and on the other (bottom) aquencher that is incorporated to the exit pipeline. Thedesign pressure is 1240 kPa, and the design temperature ofthe metal shell is 345 °C. The gasification burner is adevice of proprietary design, specifically designed to in-sure proper mixing of the oxygen, steam (the gasifyingagent), and oil (the carbon source) in the feed.

Figure 1 depicts the gasification process. The systemwas started by enabling the cooling water circuit (closed

Figure 1. Simplified flow diagram of the gasification process: (1) auxiliary combustion chamber and (2) gasification burner.

Mendoza et al.

1600 Journal of the Air & Waste Management Association Volume 56 November 2006

system) that provides water to different equipment, in-cluding the wet scrubber. Next, pressure tests were exe-cuted under nitrogen atmosphere to the reduction circuitfollowed by testing of the flow meters. The pressure in thegasification reactor (R-1) was maintained at 310 kPathroughout the operation. The start-up sequence contin-ued with the preheating of the reactor, burning naturalgas and oxygen in an auxiliary combustion chamber (lo-cated in 1 on Figure 1). At the same time, steam (thegasification agent) was fed to the gasification burner (lo-cated in 2 on Figure 1). When the temperature in R-1reached the desired level, the gasification burner startedto operate. To accomplish this, steam, oxygen, and spentoil were fed to the gasification burner. Once it was con-firmed that the gasification burner was working, the gasburner was shut down. The temperature reading of theclosest point in the wall to the burner was �1140 °C atsteady state. The residence time of the gases in the reactorwas estimated in �42 sec. The residence time was main-tained high to give enough time to the feed to gasify andreduce the possibility of releasing undestroyed PCBs. Atthe exit of the reactor, the quencher reduced the temper-ature of the syngas, which was then sent to a scrubberbefore leaving the system. The temperature of the syngasleaving the quencher and the scrubber was �40 °C and35 °C, respectively. For the particular application de-scribed here, a significant amount of HCl was producedfrom the chlorine present in the PCB molecules and wasabsorbed in the water fed to the scrubber. If required, thisHCl can be recovered from the solution for other appli-cations. Here, the cooling/absorbing water had to be con-tinuously neutralized with a sodium hydroxide solutionbecause of the continuous accumulation of HCl in thewater given the closed nature of the water circuit.

The oil feeding system consisted of a series of tankswhere the feed mixtures were prepared. The spent oil(without PCBs) was contained in a “day tank”; the oilreceived by this tank came from a main storage tank thatcollects oil from a variety of sources. The oil with PCBswas contained in a double-wall tank. The mixtures wereprepared in a second double-wall tank. Oil flowed bygravity from the tanks containing the spent oil and thecontaminated oil with PCBs to the mixing tank, and therequired amounts were controlled by a series of valvesconnected to the distributed automatic control system ofthe plant. The amount required to be mixed was con-trolled by measuring the added weight from each tank.The feed mixture was then sent by gravity to the feedingtank, where finally the mixture was pumped to R-1.

EXPERIMENTAL WORKThe plant started operations in the morning of May 11,2003, and reported stable conditions in the reactor in theafternoon of that same day. Sampling of the exit gasstream, the feedstock, and the water streams started onMay 12 and continued until May 14. The feed of the firstday was spent oil with no PCBs, the second day the oil wasprepared to have 5% PCBs, and the third day the feed had10% PCBs. The spent oil was a mixture of residual hydrau-lic oils from typical process equipments (pumps, compres-sors, mills, etc.), whereas the oil contaminated with PCBscame from unused electric transformers. To minimize

risks, the feed of PCBs was suspended during the breakbetween the sampling of the gas stream under the 5% and10% PCBs conditions. After completing the test with oilcontaining 10% PCBs, uncontaminated oil was onceagain fed to the system, which remained operating 24additional hours to eliminate any residues of PCBs in theequipment.

The syngas produced was sampled and its composi-tion analyzed, as well as the oil mixtures fed to the reactorand the quality of the water leaving the scrubber. Figure 1illustrates the location of the water and gas streams sam-pled. The gas was analyzed for CO2, CO, O2, N2, H2, CH4,nitrogen oxide (NOx), SO2, HCl, total hydrocarbons(THCs), total suspended particulate (TSP) matter, metals(As, Cd, Co, Cr, Cu, Hg, Mn, Ni, Pb, Se, Sn, and Zn), PCBs,and PCDDs/PCDFs. The feed was analyzed for PCBs, andthe water was analyzed for PCBs, chlorides, and PCDDs/PCDFs.

The samples were obtained and analyzed followingstandard Mexican methods and, where applicable, EPAmethods (Table 1). In particular, for PCBs and PCDDs/PCDFs in the stack, EPA Method 23 was used, imple-mented with an isokinetic source sampling system (Envi-ronmental Supply Company, Inc., model CS-5000) asdescribed in EPA Method 5 and augmented with Method23 extension glassware. The preparation of samples andposterior analysis was conducted by Alta Analytical Per-spectives. Capture resins (XAD-2) were spiked with surro-gate standards as follows: for PCDD/PCDF, 20 �L of a0.2-ng/�L solution was used, whereas for PCBs, 40 �L of a0.1-ng/�L solution was used. Capture solutions containedhigh-performance liquid chromatography-grade solu-tions of water, methylene chloride, toluene, and acetone.A high-resolution gas chromatograph/high-resolutionmass spectrometer (VG 70SE High-Resolution Double Fo-cusing Mass Spectrometer) system was used to analyze theextracts obtained. Method 1668A, a water method modi-fied by the analytical laboratory, was used in the high-resolution analysis of PCBs in the stack. Three 1-hr sam-ples and a field blank were obtained for each operationcondition, and an average of 1.2 m3 passed through thesampling train. The reported values were calculated as anaverage of the three samples, corrected by the value ob-tained for the field blank. Sampling for each operationcondition started once the system was considered to havestabilized (�1 hr after the transition to the operationcondition).

Metals/TSP, HCl, and SO2 samples were also collectedusing isokinetic source sampling systems. As for the pre-vious case, for metals/TSP, three 1-hr samples and a fieldblank were obtained for each operation condition, and forHCl and SO2, two 1-hr samples and a field blank werecollected. An average of 1.2 m3 was also sampled for thesespecies. Metals were analyzed by Inductively CoupledPlasma Atomic Emission Spectrometry (Thermo JarrellAsh Corp., model Atom Scan 16), except Hg, which wasanalyzed by Cold Vapor Atomic Absorption (Varian Spec-tra, model Spectra AA). HCl and SO2 were analyzed by ionchromatography ([IC] Dionex, model DX-100).

NOx, O2, CO, CO2, and THC were measured semicon-tinuously during the whole sampling period. NOx was

Mendoza et al.


monitored using a chemiluminescence device (Thermo-Environmental Instruments, Inc., model 42-H), O2 byelectrochemical cells (Bacharach, model PCA), CO andCO2 by nondispersive infrared technique (Milton Roy,model ZRH), and THC by flame ionization (RosemountAnalytical, model 400A). In addition, instantaneous sam-ples were collected on an hourly basis in metal bulbs andanalyzed for H2, N2, CO, CO2, and CH4 by GC (conduc-tivity detector). The results for CO and CO2 comparedwell with the continuous samples.

Finally, PCBs in water samples and feed oil were an-alyzed by GC-electron-capture detector (Agilent, modelHP5890), chlorides in water by IC, and PDCC/PDCFs byhigh-resolution GC-mass spectrometry as the stack sam-ples. Feed oil samples were a composite obtained throughthe corresponding operation condition period, whereaswater samples were instantaneous samples collected atthe middle of each condition period.

RESULTSUltimate analysis of the dilution oil indicated an averagecomposition of 83.4% carbon, 10.5% hydrogen, 3.1% ash,1.8% oxygen, 0.6% sulfur, and 0.6% humidity. Tracequantities of chlorine (0.05%) were also present. Theheating value obtained for the oil was 10,710 kcal/kg.Chemical analysis of the transformer oil contaminatedwith PCBs indicated a heating value of 5150 kcal/kg, acontent of PCBs of 66.8% and 40% of chlorine.

The characterizations of the mixtures fed to R-1 arereported in Table 2. The heating value of the mixturedecreased, as expected, as more PCBs were present. Re-garding the metals, Zn was the most abundant of thoseanalyzed, whereas As, Cd, Co, Se, Sn, and Hg were notdetected. In all of the cases, the content of metals de-creased as the PCBs content increased because of dilutionof the spent oil with the contaminated oil with PCBs,which had less metal content. Of note, given that theexperiments were conducted at a semi-industrial scale,during different days, with spent oil acquired from differ-ent sources and, thus, with different quality related to theamount of trace metals present, it is not expected that theamount of trace metals correlates well with the dilutionfactors of each test (i.e., 5% and 10% dilution). The ap-propriate amount of spent oil and contaminated oil used

to generate each mixture was corroborated with the aver-age amount of PCBs actually present in the feed to thereactor. The concentration of PCBs in the feed that con-tained only spent oil was �0.4 mg/kg; for the 5% condi-tion the actual average concentration was 4.9%, and forthe 10% condition it was 11%.

Table 3 summarizes the amount of oil (with andwithout PCBs), steam, and oxygen fed during the gasifi-cation tests, whereas Table 4 presents the average compo-sition of the syngas obtained. As shown, the syngas ob-tained is of very good quality with a high concentrationof reducers (H2 and CO). In general, the syngas obtainedhas a higher concentration of H2 and less CO2 comparedwith the one produced by other authors for the gasifica-tion of municipal solid waste35 or motor oil,31 mainlybecause of differences in operating temperature andchemical composition of the feed. The result obtained forHCl is of particular interest, because the analyses indicateconcentrations lower than the detection limit of themethod (�0.03 mg/m3). As indicated earlier, thermody-namic considerations31 indicate that the chlorine presentin the PCBs will preferably be transformed into HCl. This

Table 1. Sampling and analysis methods used.

Source Method Description

Stack gas NMX-AA-09-1993-SCFI Determination of stack gas velocity and volumetric flow rate (pitot tube method)NMX-AA-54-1978 Determination of stack gas humidity content (gravimetric method)NMX-AA-10-SCFI-2001, EPA 5 Determination of particulate emissions from stationary sourcesNMX-AA-55-1979 Determination of sulfur dioxideEPA 3A, EPA 10 Determination of CO2, CO, and O2 (instrumental)EPA 25A Determination of total hydrocarbons (flame ionization)EPA 26A Determination of halogens and hydrogen halidesEPA 7E Determination of NOx (chemiluminescence)EPA 23 Determination of PCDD/PCDFsEPA 29 Determination of metals

Liquid samples EPA 300.1-1999 Determination of inorganic anions (chlorides) in water (IC)EPA 8081-1994 Determination of organochloride pesticides and PCBs as Aroclor (GC–capilar column)EPA 9253 Determination of chlorine in aqueous solution

Table 2. Average chemical characterization of the mixtures fed to thegasification reactor by operation condition.

Parameter Units 0% PCBs 5% PCBs 10% PCBs

Heating value kcal/kg 10,710 10,280 9850Chlorine % 0.05 3.23 5.28Sulfur % 0.61 0.64 0.53Water % 0.60 0.54 0.53As mg/kg �7 �7 �7Cd mg/kg �0.4 �0.4 �0.4Co mg/kg �1 �1 �1Cr mg/kg 10 �5 �5Cu mg/kg 23 18 16Mn mg/kg 50 44 41Ni mg/kg 4 �2 �2Pb mg/kg 14 13 12Se mg/kg �8 �8 �8Sn mg/kg �5 �5 �5Zn mg/kg 1370 1270 1220Hg mg/kg �0.05 �0.05 �0.05

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is in part corroborated by experimental results from thegasification of other types of waste.32 That being the case,the fate of the HCl would be in the water of the scrubber,as was the case.

Analysis of particulate matter and heavy metals in theclean syngas also indicated low concentrations for thesespecies. Total particulate matter concentrations were 6.3,2.1, and 2.7 mg/m3 for the conditions of 0%, 5%, and10% PCBs, respectively. Pb, Cr, Cu, As, Se, Co, and Cdwere not detected on the syngas. The rest of the metalsreported their highest concentration under the 0% PCBcondition (Zn 0.127, Ni 0.002, Mn 0.002, and Sn 0.078mg/m3), with the exception of Hg, which had its highestconcentration (0.0002 mg/m3) under the 10% PCB con-dition. These results are in general agreement with themetal content in the oil fed in each test. Results obtainedhere corroborate experimental and modeling results thatindicate that a wet scrubbing system should be effectivefor removing these elements from the gas (except Hg,which in any case was undetected in the feed).36 All of thevalues reported for particulate matter and metals are atnormal conditions of temperature and pressure (298 K, 1atm), dry basis, and 7% O2.

Detailed results of PCBs in the syngas are reported inFigure 2. Highest concentrations were reported for tri-PCBs, although in the test with 10% PCBs in the feed,mono-PCBs and di-PCBs dominated the total concentra-tion. Speciation of PCBs by congeners is reported in Table

5. The selected congeners are considered of equivalenttoxicity to PCDDs/PCDFs because of their coplanar mo-lecular structure. The detected congeners have toxicityequivalent factors (TEFs) in the range of 0.0001 to 0.1with respect to the most toxic known dioxin (2,3,7,8tetrachloro dibenzo-p-dioxins). Of the listed species, onlyPCB-77, -105, -118, -156/157, and -167 were detected, andPCB-118 (TEF � 0.0001) was the one reported with thehighest concentration in all of the operation conditions.A similar analysis was conducted for PCDDs/PCDFs con-geners, although the only species detected was the octa-chloro-dibenzo-p-dioxin (OCDD), which has a TEF of0.001. OCDD concentrations and corresponding relativestandard deviations were 6.5 � 10�6 (64%), 8.1 � 10�6

(120%), and 7.1 � 10�6 ng/m3 (90%) TEQ (normal con-ditions, dry basis, 7% O2), under the 0%, 5%, and 10%PCBs conditions, respectively. Mean recovery of extrac-tion standards for the OCDD was 84% (N � 13), and ingeneral the mean recoveries were in the range of 81–90%.

The water used in the scrubber/quencher was ana-lyzed for PCBs, dissolved chlorine (Cl2), chlorides, andPCDDs/PCDFs, and the results are shown in Table 6. Dis-solved Cl2 and PCBs were below the detection limit of themethod in all of the cases (0.09 and 0.002 mg/L, respec-tively). The increment in the concentration of chlorides isbecause of the closed nature of the cooling water system,thus, accumulation of chlorides and PCDDs/PCDFs is ob-served. As discussed earlier, HCl is produced in the reac-tor, which is then captured in the scrubber. The onlyPCDDs/PCDFs detected were the OCDD (as in the case ofthe syngas samples) and 2,3,7,8-tetra-chloro-dibenzofu-ran, with TEF of 0.001 and 0.1, respectively. The rest ofthe congeners were not detected. The European Cooper-ation Community rules (CE 2000/C25-02) consider a ref-erence limit of 0.3 ng-TEQ/L of PCDDs/Fs in the waterfrom control devices of hazardous treatment processes.The maximum concentration obtained in the test was0.0084 ng-TEQ/L.

DISCUSSIONA feasibility study on the gasification of PCBs was presented.The results obtained indicate that the technology has thepotential to be used in the conversion of contaminated oilswith askarels to a clean syngas. The test demonstrated thatsmall quantities of pollutants, and particularly air toxics, arepresent in the syngas. Polyaromatic hydrocarbon formation,

Table 3. Summary of average oil, steam, and oxygen feeding rates to the gasification system.

Operation Condition

Operation Timeof the Operation

Condition (hr)Steam(scmh)

Oxygen(scmh)

Oil Consumption(kg/hr)

Dilution Oil(0% PCBs)

Oil with PCBs(66.83% PCBs)

Start-up 13.0 72.6 61.9 56.00% PCBs in the oil feed 24.0 74.8 62.8 56.95% PCBs in the oil feed 14.0 73.4 61.5 53.9 4.3Intermediate condition (0% PCBs in the oil feed)a 10.0 71.8 62.7 57.010% PCBs in the feed 14.0 77.0 62.8 51.7 8.9Final condition/cleanup (0% PCBs in the oil feed)a 24.0 77.8 63.0 56.7

Notes: scmh � standard cubic meters per hour. aNo sampling conducted during this operation condition.

Table 4. Characterization of the syngas for each operation condition.

Parameter Unitsa,b 0% PCBs 5% PCBs 10% PCBs

H2 %V 46.7 46.1 45.6CO %V 33.4 34.2 34.6CO2 %V 18.7 18.5 18.9O2 %V 0.05 0.09 0.09CH4 %V 1.0 0.9 0.6N2 %V 0.2 0.3 0.4NOx mg/m3 1.7 1.9 2.8SO2 mg/m3 1.9 2.2 1.1HCl mg/m3 �0.03 �0.03 �0.03Total PCBs mg/m3 2.2 � 10�5 3.4 � 10�5 9.0 � 10�4

PCDDs/Fs ng-TEQ/m3 6.5 � 10�6 8.1 � 10�6 7.1 � 10�6

Notes: aPercent volume is on a dry basis; bmg or ng per m3 are at 298 K, 1atm, dry basis, and corrected to 7% O2.

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which could be of concern in the ash as demonstrated in thegasification of other types of waste,37 was not addressed.

During the tests conducted, the oil feed rate increasedfrom 56.9 to 60.6 kg/hr, which, in turn, represented adecrease in the heating value and an increase in the chlo-rine of the feed mixture, with a corresponding decrease inthe relative amounts of carbon and hydrogen present inthe oil. Overall, the mixture became harder to gasify asmore PCBs were present. This condition had to be com-pensated with an increase in the steam-oxygen volumet-ric flow ratio, which started at 1.19 and ended at 1.23,because steam increases the reactivity of the gasifyingmixture.31,38 With this, more gasifying agent was intro-duced to insure proper destruction of the feedstock,gasification of carbon, and limit to the production ofparticulate matter. A consequence of having more PCBs in

the feedstock was the decrease of H2 and CH4 being pro-duced and an increment of CO and CO2. Also, the non-destroyed amounts of PCBs in the syngas increased, par-ticularly under the condition with a feed of 10% PCBs.The profile of PCBs by class (Figure 2) under the 5%condition resembles well background (blank) conditions;however, mono-PBCs and di-PBCs are present with con-centrations of �2 orders of magnitude larger under the10% condition. Although the total amount of ungasifiedPCBs increased by �1 order of magnitude during the lastoperation condition, the destruction efficiency was stillvery high, as discussed later. Finally, decreasing PCDD/PCDF concentrations correlated well (R2 � 0.77) withincreasing steam-to-oil feed ratios indicating a decreasingtendency to produce these toxic compounds under morereductive conditions in the gasification reactor.

Figure 2. PCBs characterization in the syngas by PCB class for each operation condition (concentrations are at normal conditions, dry basis,and corrected to 7% O2).

Table 5. PCB congeners in the syngas (all concentrations are reported as mg/m3 at 298 K, 1 atm, dry basis,and 7% O2).

CongenerToxicity Equivalent Factors

(WHO mammals/humans)0% PCBs(mg/m3)

5% PCBs(mg/m3)

10% PCBs(mg/m3)

PCB-77 0.0001 4.7 � 10�8 3.0 � 10�8 4.2 � 10�8

PCB-81 0.0001 �3.5 � 10�9 �3.4 � 10�9 �3.0 � 10�9

PCB-105 0.0001 4.8 � 10�8 2.5 � 10�8 3.5 � 10�8

PCB-114 0.0005 �3.0 � 10�9 �3.1 � 10�9 �3.4 � 10�9

PCB-118 0.0001 1.8 � 10�7 8.5 � 10�8 9.6 � 10�8

PCB-123 0.0001 �3.2 � 10�9 �3.2 � 10�9 �3.6 � 10�9

PCB-126 0.1 �1.7 � 10�9 �2.8 � 10�9 �4.5 � 10�9

PCB-156/157 0.0005 6.2 � 10�9 9.6 � 10�10 5.7 � 10�9

PCB-167 0.00001 1.4 � 10�9 �1.9 � 10�9 1.7 � 10�9

PCB-169 0.01 �2.5 � 10�9 �2.7 � 10�9 �2.2 � 10�9

PCB-189 0.0001 �3.3 � 10�9 �3.4 � 10�9 �3.1 � 10�9

Notes: WHO � World Health Organization.

Mendoza et al.


The performance of the gasification process was com-pared with emission rules available in Mexico, the UnitedStates, and Europe. It needs to be noted that the rules wereintended for application to the combustion gases emittedby incineration processes. In the case of a gasificationprocess, the synthesis gas obtained is not emitted to theatmosphere, because it can be further used in other pro-cesses. Thus, it is no longer a residue. The comparisonpresented here used the rules for incineration only as aguideline.

Table 7 presents the comparison of the syngas com-position with respect to Mexico’s MRP-6 official docu-ment on hazardous waste treatment processes. CO datawere not included, because it is precisely the objective ofthe gasification process to produce this compound. In thesame line, most of the THC is present as CH4. These twocompounds are not residues of the process, but productsthat can be used in other processes. Table 7 indicatescompliance of the rest of the parameters with respect tothe Mexican rule. Emissions of PCDDs/PCDFs indicate 5orders of magnitude lower than the maximum emissionlimit. The measured values for PCDDs/PCDFs of �0.01ng/m3 (normal and dry conditions) were further reducedbecause of the small amount of O2 present in the exitstream (a factor of 0.67 because of the correction to reportat 7% O2) and because of the fact that the only PCDD/PCDF detected was the OCDD, which has a toxic equiv-alent correction factor of 0.001. Comparisons of the levelsof PCDDs/PCDFs obtained in this work with values re-ported in the literature indicate lower concentrations forthese tests. For example, lower-limit levels of 0.001 ng/m3

TEQ have been reported in the gasification of highly

chlorinated feedstocks,6 and the presence of OCDD in fluegas from the gasification of municipal solid waste hasbeen reported at 0.17 ng/m3 (at 11% O2).34 The destruc-tion and removal efficiency, with respect to the totalamount of PCBs fed, was �1 order of magnitude abovethe minimum allowable.

A similar analysis was conducted using as guidelinesTitle 40 of the U.S. Code of Federal Regulations, Part 60and Common Position (CE) No. 7/2002, Annex V of theEuropean Community. In 1999, EPA published the docu-ment “NESHAPS: Final Standards for Hazardous Air Pollut-ants for Hazardous Waste Combustors, Final Rule,” based onevaluations of the maximum Achievable Control Tech-nology Rule. The maximum allowable emission limitswere established at standard conditions (293 K, 1 atm),dry basis, and 7% O2. The difference in temperature withrespect to the Mexican rule produces a correction factor of1.017 in the concentration reported in Table 7. The max-imum allowable emission limits by the European regula-tion cited above were established using the followingconditions: dry basis, 273 K, 101.3 kPa, and 11% oxygen.The temperature produces a correction factor of 1.091;meanwhile, the oxygen produces a correction factor of0.784 from the values reported in Table 7. Thus, a com-parison of measured values against the limits imposed byU.S. and European regulations can be obtained directlyand is not shown for brevity.

The results obtained from this analysis indicate thatthe syngas obtained would meet the maximum allowedemission limits set by Mexican, U.S., and European regu-lations for the thermal treatment of hazardous waste forthe following parameters: particulate matter, NOx, SO2,HCl, metals, PCCDs/PCDFs, and destruction efficiency.Because the syngas would not be emitted, but insteadused by other processes, the results indicate that this rawmaterial is of high quality and free of those hazardouspollutants analyzed. The levels of NOx and SO2 are alsovery low thanks to the reductive atmosphere present inthe reactor that, instead of oxidizing the nitrogen andsulfur present in the fuel, it reduces them to N2 and H2S.A benefit from this is that for fuels with high sulfur con-tent, the H2S can be easily captured and transformed toelemental sulfur or can produce sulfuric acid solution.

Table 6. Characterization of the process water.

ConditionChlorides

(mg/L)Dissolved Cl2

(mg/L)PCBs(mg/L)

PCDDs/Fs(ng-TEQ/L)

Start-up 59 �0.090% PCBs 74 �0.09 �0.002 9.4 � 10�5

5% PCBs 756 �0.09 �0.002 1.5 � 10�4

10% PCBs 1850 �0.09 �0.002 8.4 � 10�3

Cleaning 2551 �0.09 �0.002

Table 7. Comparison of results of the test with rules available in Mexico.

Parameter Unitsa 0% PCBs 5% PCBs 10% PCBs Limit

Total suspended particles mg/m3 6.3 2.1 2.7 30CO mg/m3 63NOx mg/m3 1.7 1.9 2.8 300SO2 mg/m3 1.9 2.2 1.1 80HCl mg/m3 �0.03 �0.03 �0.03 15THC mg/m3 10Pb � Cr � Cu � Zn mg/m3 0.127 0.067 0.041 0.7As � Se � Co � Ni � Mn � Sn mg/m3 0.082 0.071 0.047 0.7Cd mg/m3 �0.0002 �0.0002 �0.0002 0.07Hg mg/m3 0.00004 0.00005 0.00019 0.07PCDD/Fs ng-TEQ/m3 6.5 � 10�6 8.1 � 10�6 7.1 � 10�6 0.5Destruction and removal efficiency % �99.9999 �99.9999 99.9999 (minimum)

Notes: aConcentrations are reported at 298 K, 1 atm, dry basis, and 7% O2.

Mendoza et al.


CONCLUSIONSResults from a test on the gasification of spent oil con-taminated with PCBs were presented. Tests were con-ducted using oil mixtures containing 0%, 5%, and 10%PCBs. The synthesis gas produced by the reactor was an-alyzed for gases, particles, metals, PCBs, and PCDDs/PCDFs. The water used in the scrubber was analyzed forPCBs, chlorine, chlorides, and PCDDs/PCDFs. The tech-nology efficiently destroyed PCBs contained in the feed(efficiency �99.9999%), leaving most of the chlorine inthe HCl form, which was captured in solution in the wetscrubber. The levels of the species sampled in the exitsyngas were below the emission limits stated by the ap-plicable Mexican, U.S., and European rules, includingPCDDs/PCDFs (excluding CO and THC, the first a majorproduct expected and the second a byproduct that ismostly CH4). The resulting syngas was of high quality,with high proportions of CO and H2 and free of thosehazardous pollutants that were analyzed. This productcan be further used in other synthesis processes or inenergy generation equipment.

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About the AuthorsAlberto Mendoza is an associate professor in the Depart-ment of Chemical Engineering, Instituto Tecnologico y deEstudios Superiores de Monterrey (ITESM). Porfirio Cabal-lero is an associate professor in the Center for Environmen-tal Quality at ITESM. Juan A. Villarral and Ricardo Viramon-tes are with Ternium Hylsa. Address correspondence to:Alberto Mendoza, Department of Chemical Engineering,Instituto Tecnologico y de Estudios Superiores de Monter-rey (ITESM), Ave. Eugenio Garza Sada 2501 Sur, Mon-terrey, Nuevo Leon 64849, Mexico; phone: �52-81-8328-4336; fax: �52-81-8328; e-mail: [email protected].

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