report on biofuels for sofc applications part 1

Project no. 019739

LARGE-SOFC

Towards a Large SOFC Power Plant Instrument: Integrated Project Thematic Priority: 6.1 Sustainable Energy Systems

Report on biofuels for SOFC applications

Part 1: Fuel options (D6.1) Part2: Biogas cleaning and reforming in SOFC systems (D6.15)

Start date of project: 1.1.2007 Duration: 36 months Organisation name of lead contractor for this deliverable: VTT Technical Research Centre of

Finland

Published on 1.1.2010

Project co-funded by the European Commission within the Sixth Framework Programme (2002-2006)Dissemination Level

PU Public X PP Restricted to other programme participants (including the Commission Services) RE Restricted to a group specified by the consortium (including the Commission Services) CO Confidential, only for members of the consortium (including the Commission Services)

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Report’s title Deliverable No Biofuels for SOFC 6.1 Responsible author Address of responsible author Anja Oasmaa (VTT)

Author(s) Part 1: Anja Oasmaa (VTT) Part 2 : Michela Monteverde (UNIGE) Renzo Di Felice (UNIGE) Anja Oasmaa (VTT)

Summary

Project Project short name / number Towards a Large SOFC Power Plant - Integrated Projectwith European Commission 6th Framework Program,Sustainable Energy Systems

LARGE-SOFC Contract 019739

Project/Report identification code (if available) Work package WP 6 Key words Publication date SOFC, biofuels, gasification gas, biogas, reforming, cleaning

Restricted version M18

Dissemination level Pages Public since 1.1.2010

Project no. 019739

LARGE-SOFC


Part 1: Fuel options

Towards a Large SOFC Power Plant, LARGE-SOFC Contract 019739 Deliverable D6.1-3

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Extended summary Potential biofuels for SOFC Industrial developments in EU on biomass conversion are driven by the biofuels directive. Directive 2003/30/EC on the Promotion of the Use of Biofuels or Other Renewable Fuels for Transport set 2 % (energy bases) obligation by 2005, 5.75 % by 2010 and a recent EU decision is to increase the share to 10 % by 2020. It is quite obvious that the biofuels target cannot be met by 1st generation biofuels (Figure A).

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<1% BIOFUELS IN TRANSPORTATION IN EU

Figure A. Comparison of the availability of biofuels and fossil fuels in transport in 2005 There are large uncertainties related to bioenergy markets due to competing uses of biomass. National compulsory blending is on its way in many EU countries which will increase the value of transportation biofuels. Country specific targets vary on energy structure of the country, policy etc. Grading of transportation biofuels based on sustainability criteria is on its way which will emphasise R&D on second generation (lignocellulosic feed) biofuels in Europe. CO2-trade and feed-in-tariffs for bio-electricity will affect costs. The bottleneck is price and availability of feedstock. In order to introduce biofuels as SOFC fuels several issues has to be considered (Figure B). The availability of biofuel is the most critical factor and it is affected i.a. by availability of biomass, maturity of the biofuel production technology, existence of the infrastructure, and competition with different energy sectors. The costs of biofuel depends besides the availability, but also on efficiency, health and safety issues, legislation, fuel upgrading needs and integration issues. Optimisation between fuel cleaning demands for SOFC and development of SOFC to tolerate dirtier fuel is one alternative. H2, CO, CH4, NH3 are fuels and CO2, N2, H2O diluents for SOFC. There are limited data on impurities available. In REAL-SOFC project the limit for sulphur was set to below 1 ppm. Halogenes are corrosive agents with a deteriorative concentration limit of 1 ppm. C2-C6 organic compounds act as fuel but can also cause plugging and coking. For siloxanes there are commercial removal techniques decreasing the amount of siloxanes down to 5 ppb. The limit for acetylene (C2H2) is 0.1 vol-% and for ethene


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below 1000 ppm. The limits for toluene (benzene), and naphthalene are tested at FZJ in Large-SOFC project. The tolerancy of SOFC towards impurities depends i.e. on the FC materials and processing conditions. Lowering the operating temperature or S/C the efficiency of the stack increases but the tolerancy of SOFC towards impurities decreases. SOFC has to compete with gas engines which are market leaders and hence higher tolerance towards impurities would be beneficial. Biogas is one of the most potential biofuels for SOFC because of several reasons. Increasing amounts of bio-wastes are available and biogas production is commercial technology. The variations in gas compositions, especially with landfill gas (Table A), is a challenge because expensive tailored gas-cleaning is required. Raw biogas (Table B) from all sources contains hydrogen sulphide and organic sulphur, which has to be removed for avoiding catalyst poisoning. Also halogenated hydrocarbons have to be removed because of same reasons. Siloxanes would burn to solid silica and cause deposits. Condensed water vapour may cause instrument fouling and compressor/fan impact/erosion damage. The competition with gas engines and micro turbines will be tight and hence the development of techno-economically feasible biogas cleaning system is the key. At landfill sites the advantage of SOFCs would be operability at low CH4 concentration, where gas engines cannot function. Biogas cleaning will be discussed in the Part 2 of this report. Table A. Variation in gas composition within a few months at one landfill

Table B. Biogas composition

Biomass steam/air gasification may be feasible in small scale (down to about 1 MWe) if the gas cleaning costs can be kept low. Most challenging impurities are benzene, ethene, and naphthalene. There are large variations in gas quality and impurities and hence tailored gas-cleaning required. Several gasification-SOFC-integration (Figure B) tests have shown a lot of challenges in gas cleaning, heat integration, and net efficiency.


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Güssing, Austria

Demonstrated

Underdemonstration

Underdemonstration

Figure B. Güssing plant in Austria Biomass oxygen gasification is under demonstration. It may be feasible in large scale (above 100 MWe). Syngas cleaning is under demonstration. Sulphur and nitrogen are the most challenging impurities. The target is to achieve impurity levels: total S < 60 ppbv, halides < 10 ppbv, NH3 < 10 ppmv, HCN < 10 ppbv, particulate < 0.1 ppmw. Dry gas cleaning (Figure C) may be the most potential for SOFC.

GTI Biomass gasification pilot plant in Chigaco, USA

Biomass Gasification,Reforming, Shift

Multi -Step DryGas Cleaning

FT liquids

HP Steam

MP/LP Steam

Off-gas

Multi-Step Dry Gas Cleaning:Sorbent-based process for removal of H 2S and HCl to below 1 ppm level; sub-processesfor NH3 and HCN removal largely undeveloped as yet

GuardBeds

FTSynthesis

&Upgrading

30 bar

280 °C

Syngas production and gascleaning under demonstration

Under demonstration

Figure C. GTI biomass gasification plant in Chigaco, USA

Synthesis gas processes (Figure D) are commercial technology. Fischer-Tropsch diesel (FTD) and methanol are potential when easy transportation and storage are determining. In case of FTD and synthetic natural gas (SNG) the competition within energy sectors will be the determinining factor. Transportation fuels are usually more valuable than bioelectricity. Compared to fossil NG the price of SNG is about doupled.

FTD may be available within a few years depending on competition within energy sectors. FTD can use existing diesel infrastructure and this is one reason why the focus is on FTD in Germany and in Finland. In Germany Choren has a pilot plant in Freiberg running and


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demonstration plant starting up. In Finland two consortiums, Neste-Stora Enso and UPM-Andritz/Carbona are planning demonstration plants.

Figure D. Synthesis gas processes

SNG from syngas may be feasible in countries having existing, distributed NG infrastructure (Figure E). Fossil NG will initially be the main fuel for SOFC. Gas market directive 2003/55/EC opens the NG network for SNG. SNG can also be upgraded from fermentation biogas. In feeding of SNG from biogas to NG pipeline following aspects has to be taken care of: cleaning and upgrading processes are established but expensive, profitability is country specific, critical aspects are standards and access rights.

Figure E. Advantages for installing a SNG plant in the Netherlands

Feasibility of methanol from syngas depends on a potential infrastructure. Advantages for methanol are easy storage and transportation. Methanol may be potential fuel for intermediate temperature SOFCs, because methanol can be efficiently reformed at 300 - 600 °C. Methanol is produced presently from NG.


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NH3 as carbon-free fuel may be feasible in large-scale installations where safety issues are easier to take care of. NH3 offers energy efficiencies at least equal to methanol but on a local level is CO2 free and furthermore, offers zero emission potential. NH3 production from peat (analogous to biomass) gasification has been demonstrated (Figure F). 100% NH3 has been successfully used as a fuel in SOFC.

Figure F. Ammonia production from peat by oxygen gasification. HTW plant at Oulu, Finland in 80ies.

Alternatives for replacing fossil diesel are biodiesel (Table C) from esterification (FAME), hydrocracking (NExBTL), and by catalytic upgrading from synthesis gas via biomass gasification (FTD). Production of FAME is commercial and its specifications have been standardised in EN14214. In Finland two NExBTL plants producing 70,000 t biodiesel a year are in operation. The product is presently used in transportation sector. Table C. Properties of diesel and biodiesels

NExBTL GTL Fischer-Tropsch Diesel

FAME Diesel fuel 2005 (summergr.)

Density at +15 °C (kg/m3) 780 – 785 770 – 785 ~885 ~835

Viscosity at +40 °C (mm2/s) 3.0 – 3.5 ~3.2 – 4.5 ~4.5 ~3.5Cetane index or number 98 – 99 ~73 – 81 ~51 ~5310 % distillation (°C) ~260 – 270 ~260 ~340 ~20090 % distillation (°C) 295 – 300 325 – 330 ~355 ~350Cloud point (°C) -30 ... -5 ~0 ... +3 ~0 ... -5 ~-5Heating value (MJ/kg) ~44 ~43 ~38 ~43Heating value (MJ/l) ~34.5 ~33.8 ~34 ~36Polyaromatic content (wt-%) ~0 ~0 ~0 ~4Oxygen content (wt-%) ~0 ~0 ~11 0Sulfur content (mg/kg) <10 <10 <10 <10


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Bio-ethanol is used as fuel in transportation sector, which causes uncertainties in its availability. There are pilot plants on production of 2nd generation lignocellulosic bio-ethanol in Sweden and in Canada. Gas cleaning Fuel cells require cleaner feed gas than conventional combustion engines, for which the gas cleaning has been developed. All sulphur species are poisonous for catalytic processes employing reduced metals or metal oxides. The basic problems in biological gas upgrading are safety problems caused by using oxygen (air) and biogas at high temperature. Biogas cleaning (Figure G) involves the removal of moisture, VOCs (volatile organic compounds), particles, sulphur compounds, halogens, and siloxanes. The removal of moisture from landfill gases is very important, because they contain silicon compounds which could deposit and block gas lines and harm the stack. Oxygen damages anode of fuel cells and N2 from air dilutes the biogas. Gas cleaning is discussed in details in the Part 2 of Biofuels report.

BIOGAS

Removal of H2S

Halogenated VOC

Siloxane

Moisture

Solids

SOFC

Adsorption on Fe2O3

Adsorption on charcoal

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Cooling at -2°C/adsorption on charcoal

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High investment costLow operation cost

Particle filter

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Figure G. Biogas cleaning Costs of biofuels The production costs for biofuels are clearly higher than those of present fossil fuels. Integration with pulp mill has been evaluated to reduce the costs (Figure H). Production costs for FTD, methanol (MeOH, CH3OH), SNG and H2 similar, the end-use determines the preferred choice (Figure I). Competition within energy sectors has to be considered. Sugar cane bio-ethanol is the lowest cost 1st generation biofuel.


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Figure H. Co-production of FT liquids at a large paper mill

Figure I. Estimated production costs for FTD, methanol, SNG, and hydrogen Summary In biofuel use availability of biomass/biofuels is the key issue. Most potential gaseous biofuels for SOFC (Table D) in short-term are biogases, in medium-term (5-10 years) producer gas from biomass gasification, and cleaned syngas. However, techno-economical challenges in gas cleaning has to be solved. Of liquid biofuels syngas products FTD and methanol via biomass gasification and biodiesel via hydrocracking or esterification seem to be most potential alternatives. The risk for biodiesel use may be its availability because of


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obligations in transport sector and increased value of transportation fuels. The challenges with methanol include its ecotoxity, material resistance, and nonexisting infrastructure. In longer term potential biofuels may be glycerol as a side-product in FAME production, ammonia from biomass gasification syngas or producer gas. Because SOFC has to compete with market leaders gas engines R&D work could focus on improved tolerance of cells towards impurities. Table D. Summary of availability of biofuels Energy Source Maturity of technology Technical issues Other issuesNatural Gas Commercial Minimal fuel pretreatment necessary Existing pipeline structureS-free diesel Commercial Minimal fuel pretreatment necessary Existing diesel infrastructureBiodiesel from esterification Commercial Minimal fuel pretreatment necessary Utilize existing diesel infrastructureBiodiesel from hydrocracking Commercial Minimal fuel pretreatment necessary Sustainability of palm oil, competition with traffic sectorBiogas Commercial Wide variation in gas composition Must be located on siteSNG from biogas Under demonstration Expensive upgrading techniques Can use NG pipeline structureLandfill Gas Commercial Feasible gas cleaning key issue Must be located on siteBio-ethanol from sugar cane Commercial Sustainability issues Competition with traffic sectorBio-ethanol from grain/maize Commercial Sustainability issues Competition with traffic sectorBio-ethanol from lignocellulosics Under demonstration Not known Competition with traffic sectorSyngas from biomass gasification Under demonstration Challenging gas cleaning - SNG from syngas - Commercial Minimal fuel pretreatment necessary Can use NG pipeline structure - MeOH from syngas - Commercial Minimal fuel pretreatment necessary Easy storage and transportation - NH3 from syngas - Commercial Minimal fuel pretreatment necessary Carbon-free fuel - FT diesel from syngas - Commercial Minimal fuel pretreatment necessary Competition with traffic sectorProducer gas from biomass gasification Under demonstration Tailored gas cleaning for SOFC Gas engines market leaders, competition

Must be located on sitePyrolysis liquid Under demonstration Steam reforming to SOFC feasible Easy storage and transportation,

but challenging biodegradable fuel


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Contents 1 Definitions and abbreviations 12

1.1 Definitions 12 1.2 Abbreviations 12

2 Introduction 14

3 Fuels for SOFC 16 3.1 Natural gas 16 3.2 Biogas 16

3.2.1 Availability 16 3.2.2 Composition and properties 20 3.2.3 Biogas upgrading to synthetic natural gas (SNG) 23

3.3 Biomass gasification 24 3.3.1 Biomass gasification – producer gas 25 3.3.2 Biomass gasification – synthesis gas 31

3.4 Ethanol 41 3.5 Biodiesels 44 3.6 Other biofuels 46

4 Quality requirements of fuels for SOFC 47 4.1 Fuel properties 51

5 Production costs 53

6 Conclusions 57

7 Acknowledgements 58

8 References 59


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1 Definitions and abbreviations

1.1 Definitions

Ethylene (or IUPAC name ethene) is the chemical compound with the formula C2H4. It is the simplest alkene. Because it contains a double bond, ethylene is called an unsaturated hydrocarbon or an olefin. It is extremely important in industry and even has a role in biology as a hormone.[1] Ethylene is the most produced organic compound in the world; global production of ethylene exceeded 75 million metric tons per year in 2005.[2] Group of methane containing gases Minimum 70 % of LHV is based on methane. Other fuel gas components contribute to LHV marginal only. Inert loads: mostly CO2 and/or N2. Examples: Natural gas, biogas and sewage gas from anaerobic digestion, mine gases,landfill gases, industrial residual gases with high amount of CH4. (IEA, Jülich, 2007) Biogas is produced when organic matter decomposes in the absence of oxygen at low temperatures. This can take place in a landfill site to give landfill gas or in an anaerobic digester to give biogas. Group of Synthesis Gases (Syngas) LHV results mainly from contents of CO and/or H2. Methane can be added, but not necessarily. Inert loads mostly N2 and/or CO2. Examples: Gases from thermal gasification processes, pyrolysis. Wood gas, gas from wood derivates (paper, cartoons, packaging material, gas from plastic material, waste materials, used rubber, tires. Syngas as residual gas from industrial production processes, purge gases, gases from refineries, etc. (IEA, Jülich, 2007) Subsulphide A nonacid compound consisting of one equivalent of sulphur and more than one equivalent of some other body, as a metal.

1.2 Abbreviations

ADG Anaerobic digestion gas

APU Auxiliary power unit ATR Autothermal reforming

BG Biomass gasification gas BT/WG Technical board/working group of CEN

CEN European committee for standardization CHP Combined heat and power

DMDS Dimethyldisulphide DMS Dimethylsulphide

http://en.wikipedia.org/wiki/IUPAC

http://en.wikipedia.org/wiki/Chemical_compound

http://en.wikipedia.org/wiki/Alkene

http://en.wikipedia.org/wiki/Hormone

http://en.wikipedia.org/wiki/Ethylene#_note-Wang_2002%23_note-Wang_2002

http://en.wikipedia.org/wiki/Organic_compound

http://en.wikipedia.org/wiki/Ethylene#_note-0%23_note-0

http://www.hyperdictionary.com/dictionary/nonacid

http://www.hyperdictionary.com/dictionary/compound

http://www.hyperdictionary.com/dictionary/consisting

http://www.hyperdictionary.com/dictionary/of

http://www.hyperdictionary.com/dictionary/one

http://www.hyperdictionary.com/dictionary/equivalent


http://www.hyperdictionary.com/dictionary/sulphur

http://www.hyperdictionary.com/dictionary/and

http://www.hyperdictionary.com/dictionary/more

http://www.hyperdictionary.com/dictionary/than

http://www.hyperdictionary.com/dictionary/one

http://www.hyperdictionary.com/dictionary/equivalent


http://www.hyperdictionary.com/dictionary/some

http://www.hyperdictionary.com/dictionary/other

http://www.hyperdictionary.com/dictionary/body

http://www.hyperdictionary.com/dictionary/as

http://www.hyperdictionary.com/dictionary/a


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DOE US Department of energy

EN European norm FAEE Fatty Acid Ethyl Esters

FAME Fatty Acid Methyl Esters FC Fuel cell

FZJ Forschungscentrum Jülich (Research Centre Jülich) GHG Green house gas

GTI Gas Technology Institute IC Internal combustion

LCA Life Cycle Analysis LFG Landfill gas

MCFC Molten Carbonate Fuel Cell MeSH Mercaptan

MMT Million metric tonnes MP Melting point

MT Metric tonne. A tonne (also called metric ton) is a non-SI unit of mass, accepted for use with SI, defined as: 1 tonne = 1000 kg (= 106 g).

Mtoe Million oil equivalent tonnes NREL US National Renewable Energy Laboratory

PJ Petajoule. I PJ = 277.8 GWh RES Renewable energy source

RES-E Renewable electricity source RME Rapeseed methyl ester

RRFCS SNG Syntheric natural gas

SOFC Solid oxide fuel cell UNIGE University of Geneva

VOC Volatile organic compounds

http://en.wikipedia.org/wiki/SI

http://en.wikipedia.org/wiki/Kilogram

http://en.wikipedia.org/wiki/Gram


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2 Introduction 1. The objective of the work package WP6 is to ensure that the most relevant issues of using a SOFC power plant are clarified. SOFC is a power source with one of the main benefits being its multi-fuel potential. Therefore issues related to the use of different fuels are investigated. Special emphasis is on renewable fuels. The study include such basic issues as requirements for fuel purity and composition, how to clean the gases to the required composition, the availability of fuels of suitable composition and the required reforming technologies needed for reforming the different fuels. 2. Grid Integration of large SOFC FC: The analysis of grid connection rules and standards applicable to large SOFC FC will be performed as well as their grid support capabilities. 3. The task is to provide an understanding of the safety requirements, legal regulations and standardization context in which SOFC systems will be required to operate it. 4. Similarly it is important to understand how future environmental requirements may affect SOFC systems, and how these systems can contribute to environmental improvements in the regions and markets in which they will operate. With the growing emphasis upon reducing emissions and raising fuel efficiencies, SOFC systems can potentially provide significant benefits for society as a whole. The work package comprise four tasks which cover the main issues: WP 6 Fuel flexibility, grid connection, safety and LCA Responsible partner Task 6.1 Fuel quality and gas cleaning, fuel processing options VTT, FZJ, UNIGE Task 6.2 Grid Connection Verteco, Wärtsilä,

RRFCS Task 6.3 Safety issues Wärtsilä, RRFCS, VTT Task 6.4 LCA VTT Natural gas will be the main fuel for SOFC power plants for years to come. There is already much information and experience on the use of natural gas as a fuel for high temperature fuel cells. Therefore most of the effort in this task will deal with the other possible fuels: these are methane from anaerobic fermentation of biomass and gas from gasification of biomass. VTT will collect information on SOFC requirements for fuel quality: composition, allowed variations and impurity contents and write it as a report. Sources for this information will be both the open literature, and results from SOFCNet and Real-SOFC as well as experience of the participants. Experimental work by cell testing will be performed in order to fill the identified gaps in information. VTT will collect all information on the composition and impurity levels of the different fuels and gasification products and write a report. Open literature, and experience of the participants will provide the majority of the data required. VTT has undertaken considerable work on gasification of coal, waste and biomass. Analytical work will be performed in order to fill the identified gaps in information.


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Alongside the work to be undertaken by VTT, UNIGE will investigate in more detail the potential behaviour of fuels in SOFC systems from a generic perspective. This work will be based on work undertaken by VTT and UNIGE’s own models. Due to sulphur sensitivity of the fuel cell anode and the reforming catalyst, sulpur removal will be an important clean-up step. Typically sulphur tolerance of the fuel cell anode is in the order of ppms. These sulphur atoms are contained in organic compounds. Light fuels contain simple organo-sulphur compounds such as thiophenes, while heavier feeds may contain large methyl-substituted dibenzothiophenes. Additionally these latter feeds may contain considerable amounts of organonitrogen compounds and particulate matter. Depending on the type of fuel several clean-up routes will be considered by UNIGE. In general, reducing the sulphur concept from several hundred ppms down to 1 ppm involves a catalytic step, whereas sulphur removal from ppm levels to ppb levels can be achieved by (reactive) absorption technology. A study in reformer options for different fuels and fuel composition will be made by UNIGE: biogas from biomass gasification, bioethanol and biodiesel will be considered as priority alternative fuels; also conventional fuels such as natural gas and diesel will be included as comparisons. Conclusions will be drawn on the requirements for fuel cleaning. This work will be based on the result of subtasks 1.1 and 1.2. A study on available fuel cleaning techniques will be made and recommendations for cleaning of fuels will be made. FZJ will perform up to 6 tests on anode substrate type single cells for up to three selected impurities in order to determine maximum allowed level of contamination. The impurities will be fed in to the hydrogen fuel stream. Tests will include recording of I-V curves and constant load operation up to 2000 hours.


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3 Fuels for SOFC

3.1 Natural gas

Natural gas (NG) will be the main fuel for SOFC power plants for years to come. There is much information and experience on the use of NG as a fuel for high temperature fuel cells. At VTT 7,000 hours run with reformed NG (CH4 > 98%) in 5 kW stack has been conducted. Its green alternative, synthetic natural gas (SNG), can be produced from synthesis gas via biomass gasification (see chapter 3.4). Biomethane can also be produced from biogas (see chapter 3.2). Gas market directive 2003/55/EC opens the NG network to both of these SNGs. A recent (2008) report prepared by the Öko-Institut and the Institut für Energetik in Leipzig concluded that within 20 years, a substantial share of Europe´s natural gas consumption could be covered by locally produced biogas/biomethane. Biomethane has many benefits, e.g. production can be decentralized, yields are high (double when compared to ethanol from crops) and large variety of feedstocks can be used. The study states that Europe’s potential for the sustainable production of biomethane is about 440 million toe per year, which is about the amount of natural gas currently consumed by the EU. This would result in a reduction of 15% of Europe´s CO2 emissions. One problem with biomethane in Germany is that the heating value of biomethane is higher than allowed for Germany´s natural gas pipeline system. Germany´s upper limit on the heating value of gas fed into the pipelines should be changed before introduction of biomethane. (AMFI 2008)

3.2 Biogas

3.2.1 Availability

Increasing amounts of bio-wastes are available. The total biogas resource in the European Union is estimated at more than 20 Mtoe with current waste production. In 2005, nearly 5 Mtoe biogas was flared into the air. Energy exploitation of biogas is not only a question of energy production but a question of waste treatment and environmental considerations. About half of European waste is landfilled. Approximately two thirds of exploited biogas is used for electricity production (Figure 3.1) and one third for heat production. Half of this electricity was obtained through CHP plants. (EU 2007)


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Figure 3.1. Historical development of electricity generation from biogas in the EU-25 Member States from 1990 to 2005. (EU 2007) Biogas results from several different types of processes. It can come as captured landfill gas formed from biodegradable waste in rubbish dumps or can be produced via a digester. Treatment depends on the kind of waste involved. Biogas can be made from household refuse or, agricultural waste, such as liquid manures and crop harvest waste. Biogas can be treated in small single farm-scale biogas units or collective and centralised units. These units, principally developed in Denmark, are capable of treating different types of waste at the same time, principally manure and liquid manure mixed with various other organic wastes. Dedicated biogas plants are an efficient way of handling wet bio-waste from agriculture and industry, and the size of these plants also allows for effective use of the energy content of the waste. There is considerable potential for growth of this technology. Annual growth rates for biogas electricity generation have been high for the last decade (Figure 3.1). (EU 2007) The feedstock has a major effect on methane production potential (Table 3.1). The variation in methane potentials of crops is shown in Figure 3.2. The methane potentials per ww (wet weight) increases with most crops as the crops matures. The highest specific methane yields of 0.268, 0.229 and 0.213 m3 CH4 kg-1 VSadded in co-digestion of cow manure with grass, sugar beet tops and straw, respectively, were obtained with 30% of crop in the feedstock. Including 30% of crop in the feedstock increased methane production per digester volume by 16-65% above that obtained from digestion of manure alone. Liquid and solid residues from digestion of grass-clover silage and sugar beet in two-stage leach bed – MF process were suitable for incorporation to soil as fertiliser and soil-improvement media, wheras in the solid residue from digestion of willow, cadmium concentration exceeded the limit value for use of digestates as fertiliser in arable land. (Lehtomäki 2006)


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Table 3.1. Methane production potential from various feedstocks Feedstock TS-% VS-% of TS C/N Biogas production potential CH4 production

m3/tVS m3/t feed m3/tVSSewage sludge fraction 40 75 10 21…25 600 100 150…200 275…400mechanically separatedSorted biowaste 35 80 20…26 500 140 300Sewage sludge, predried 15 5 70 10 6…10 450 30…70 315Cow manure 7 3 80 5 6…10 350 10…30 190Hog manure 6 1 75 10 3…7 600 20…35 360Fur animal manure 30 50 5…7 400 60 240Chicken manure 70 65 3…5 450 200 270Plant biomass 10 5 80 10 10…100 500 100 15…80 200…300Peels of potatoe 20 90 20…25 700 130 350Sludge from potatoe industry 6 90 20…25 700 30…40 350Flotation sludge from slaughterhouse 18 85 na 600 90 390Offal (Waste from slaughterhouse) 30 80 2…5 500 120 350 TS = total solids, VS = volatile solids, na = not analyzed

Figure 3.2. Methane potential from various crops. In Finland in 2006 the amount of biogas produced by the reactor installations was 28.3 million m3 and the combustion of surplus biogas 4.0 million m3. Production of thermal, electrical and mechanical energy was 131.9 GWh. There were altogether 33 landfill gas recovery plants operating at the end of 2006. The amount of the recovered biogas was 102.1 million m3. In addition to the 14 % decrease in the volume of the recovered biogas, the utilization rate also decreased notably from the previous year. The amount of recovered biogas used for the production of electrical and thermal energy was 56.8 m3, producing 242.8 GWh. Improvement in landfill gas utilization is mainly due to increase of utilization in Ämmässuo dump in Espoo. In Finland financial support can presently be obtained for utilisation of landfill gases but not for farm-scale biogas units. Finland is planning on


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introducing feed-in tariffs for biogas in the beginning of 2008. The feed-in tariffs will apply to all under 20 MW plants. This is likely to significantly increase the interest in biogas production. The details of the plan are still under discussion. (Kuittinen et a. 2006) In Germany the number of existent biogas plants in the agricultural sector only is presently approximately 1500. The potential for the next ten years in the performance range of 400 to 2000 kW gas output is 4000 plants. In case of a consequent utilization of the gas produced by these plants for CHP a contribution of 12 - 15% of consumable energy consumption can be reached. (Meyer-Pitroff, TU München) Most of agricultural residuals are recycled to the land without any treatment presently. It seems to be necessary, to build up a network of biogas plants to treat and gasify at least the big amounts of manure in order to contribute to a clean and healthy environment also in agricultural regions. There are increasing number of biological sewage treatment plants in Europe. A small number is already equipped with low efficiency piston engines to generate electricity. Replacement potential and new equipment potential are high, if fuel cell systems are reliable and cost effective. (IEA study from RR) The market environment in Germany is very favourable for biogas. Biogas is guaranteed access to the electrical grid by the Renewable Energy Law. The biogas producers will get a fixed feed-in tariff for 20 years. The amount of the tariff depends on the electrical capacity of the biogas plant. Additional bonuses are granted for the utilization of energy crops, CHP production and of innovative conversion technologies. Germany does not have direct investment subsidies for biogas plants, but the state owned KfW bank will grant low interest rate loans for the investment. Historically UK landfills are generally lined and capped and so collect gas very well. In the 1970’s there was a fatality near a UK landfill due to gas leakage beyond the landfill perimeter and this forced environmental legislation. Because the UK has historically not put a lot of efforts on recycling the landfills are perfect for producing lots of gas and the owners are very used to managing it. (Thornley 2007) To encourage renewables the UK had a non fossil fuel obligation from the late 1980’s. Landfil gas was eligible for a lucrative fixed price contract for electricity purchase and the first generating stations were put in at UK landfills. The problems with corrosion etc were addressed pretty quickly. The NFFO was replaced by the renewables obligation and landfill gas remained eligible for a premium electricity price, but now there was no need to apply for a contract it was open to all electricity suppliers. At the same time the Environment Agency were imposing the requirements of the EU landfill directive and demanding that all landfill sites actively manage their gas. The price paid for the renewable electricity makes it worthwhile. The industry has developed so that there are lots of specialist operators who will plant a few engines on a landfill site, maintain them on a remote service contract, move the engines around to another site if gas levels fall off etc. Things may change in the future as the UK is recycling more and pretreating material before landfilling so gas yields won’t be as good. Also the renewables obligation is under review and proposals are that landfill gas as a technology would get less for its electricity in future, but at present it is still very lucrative – in fact it is the largest single source of reneweable energy in the UK every year (competing with co-firing with biomass nowadays). (Thornley 2007) The United Kingdom remains the leading European country in terms of production with, according to the British Ministry of Industry and Trade, 1600 ktoe in primary energy production (+6.4% with respect to 2004). The largest part of this biogas is valorised in the form of electricity (4.7 TWh produced in 2005). This production benefits, in particular, from the Renewable Obligation Certificate System that has been in place in the United Kingdom since 2002. This system imposes that electricity suppliers annually increase the renew able


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electricity share of their electricity production. This obligation was of 3% in 2002- 2003 ; 4.3% in 2003-2004 ; 4.9% in 2004-2005 ; 5.5% in 2005-2006, and should reach 15.4% in 2026-2027. With 20 centralised plants and over 35 farmscale plants, the digestion of manure and organic waste is a well established technological practice in Denmark. However, no new centralised plants have been established since 1998 and the development of farmscale plants has slowed down. Three factors have been important for the current status of biogas plants in Denmark. First, the Danish government applied a bottom-up strategy and stimulated interaction and learning between various social groups. Second, a dedicated social network and a long-term stimulation enabled a continuous development of biogas plants without interruptions until the late 1990s. Third, specific Danish circumstances have been beneficial, including policies for decentralised CHP, the existence of district heating systems, the implementation of energy taxes in the late 1980s and the preference of Danish farmers to cooperate in small communities. The current setback in biogas plants is mainly caused by a shift in energy and environmental policies and limited availability of organic waste. (Raven & Gregersen 2005) In Italy, rubbish dumps are the principal deposit currently being exploited. According to the ENEA (Italian Agency for New Technologies, Energy and the Environment), rubbish dump origin biogas represented 334.1 ktoe out of the 376.5 ktoe produced in 2005. This figure has grown strongly considering that primary energy production from rubbish dump origin biogas was 297.7 ktoe in 2004 out of a total of 335.5 ktoe. It is thus essentially valorised in the form of electricity, with 2005 production amounting to 1 313.1 GWh, including 230.7 GWh in CHP plants. (biogas barometer 2006)

3.2.2 Composition and properties

Biogas is a mixture comprising principally methane (CH4) and carbon dioxide (CO2). The energy content of the gas is defined by the methane concentration: 50% methane yields 5 kWh/m³, 10% methane yields 1 kWh/m³ etc. Depending on the collection or recovery system oxygen can occasionally be present in the biogas in concentrations up to 5 %. The limit values for oxygen being acceptable for SOFC in terms of practical application fuelled with biogas is < 2 vol %. This is due to the reaction between the hydrogen obtained from reformed process of the biogas. The composition of biogas varies a lot depending on source (Tables 3.2 and 3.3) but also due to time and weather conditions (Figures 3.3 and 3.4). Table 3.2. Composition of biogas from various sources (Rasi et al. 2007)


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Table 3.3. Typical landfill gas chemical composition (Bove & Lunghi 2006)

Figure 3.3. Methane, carbon dioxide and nitrogen contents of landfill gases at different seasons.

Figure 3.4. TVOC (total volatile organic carbon) content of landfill gas, sewage digester gas and farm biogas. Sulphur compounds are to some extent always present in biogas. The main compound is hydrogen sulphide (H2S), but also organic sulphides (DMS, DMDS) and mercaptanes (MeSH) can occur (Cunningham et al. 2004). Chlorinated and fluorinated compounds and higher hydrocarbons are also commonly found in landfill gas (Table 3.4), municipal waste and sewage digestion gases.


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Table 3 4. Landfill gas contaminants at two sites. (Steinfeld & Sanderson 1998)

Organic silicon compounds (siloxanes, Table 3.5) are occasionally present in landfill (up to 150 mg/m3) or sewage biogas. They are produced from cosmetics, pharmaceuticals and antifoaming agents in detergents. Siloxanes in biogas from agricultural sources or food waste are usually below detection limit, whereas municipal sewage sludge digester gas can show significant concentrations. Table 3.5. Siloxanes in landfill gases. (Wheless 2004)


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3.2.3 Biogas upgrading to synthetic natural gas (SNG)

SNG or biomethane can also be produced by upgrading biogas. Technical measures to clean and upgrade biogas to a quality and state which allows it to be injected into the NG pipeline are proven and well established. However, the technology available on market is expensive and technologies that reduce capital and operational/maintenance costs need further development. The profitability of injecting processed biogas into the NG network is country specific (Figure 3.5) and depends on several factors including capital cost of equipment, operational/maintenance costs, processed biogas selling price, proximity of the farm to the NG pipeline, and interest rates. If processed biogas is to be injected into the NG pipeline, a gas quality control testing system and close communication between the biogas processing plant and the pipeline owner is essential. Standardisation of processed biogas quality and access rights for adding processed biogas to the NG grid are critical. If the development work is succesfull the demonstration of SNG production and feeding into NG network could take place in 2008 - 2012. (Saikkonen 2006)

Figure 3.5. Benefits of a biomass SNG plant.


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3.3 Biomass gasification

Gasification of biomass is a thermal process by which solid fuel is converted into combustible gases by a combination of oxidation, pyrolysis and reduction processes. Various gasifiers (Figure 3.6) have been developed for different applications yielding slightly different gas composition (Table 3.6). Downdraft is most suitable in small scale (around 250 - 500 kWth) and updraft slightly higher scale (around 1 - 10 MWth). Fluidized-bed gasifiers are best suitable to relatively large-scale (> 10 MW) and have many interesting applications in connection to lime kilns or boilers. The technical feasibility of biomass-IGCC (Integrated Gasification Combined Cycle) process based on fluidized-bed gasification was demonstrated already in 1990's. Fluidized-bed gasifiers are considered to be rather fuel flexible and are most suitable to feedstocks with high volatile matter content and high char reactivity. (Kurkela & Nieminen 2004) Entrained-bed gasifiers are only suitable for oxygen gasification of biomass producing synthesis gas. (Solantausta 2005) In oxygen gasification the oxygen production is usually based on cryogenic distillation from air. Other less expensive alternatives are studied. Presently, the focus is in membrane technologies etc. (Nieminen 2005)

Figure 3.6. Fixed-bed (Nagel 2006) and circulated fluid-bed gasification processes. The gaseous products from gasification of biomass under air are often called as ‘producer gas’ or ‘fuel gas’. Gas composition (Table 3.6) depends on oxygenation medium (air/oxygen), and mode of heat transfer (directly with oxygen or indirectly with hot solids). Producer gas contains impurities, like particulates, tar, alkali metals, and nitrogen and sulphur compounds that can be harmful in end-use applications. (Ohlström et al. 2001)


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Table 3.6. Composition of biomass gasification gases.

3.3.1 Biomass gasification – producer gas

3.3.1.1 Güssing plant, Austria The 8 MWth plant (Figure 3.7) in Güssing, Austria, is based on indirect gasification. The plant consists of one CFB-furnace and one BFB-gasifier. Heat is transferred from the CFB-furnace to the BFB-gasifier through the circulated bed material. In this way no nitrogen enters into the gas leaving the gasifier. The plant is semi-industrial and the major part of the gas is used in gas engines to produce electricity and heat. The gasifier has more than 32 700 hours (2007) of accumulated operation. The availability has increased every year since the plant was inaugurated in 2002 and is now approx. 90 %. Most of the earlier problems have been related to the biomass feeding system. Technical information of Güssing plant is described below:


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Figure 3.7 Güssing gasifier arrangement (EPRI, 2008) Table 3.7. Produced gas quality at Güssing CHP plant. (Hofbauer et al. 2005)

A minor part of the product gas (Table 3.7) is used for research, development and demonstration purposes. In cooperation with the Paul Scherer Institute from Switzerland a first successful test of the methanation process in Güssing has been made in 2003. A 10 kW methanation unit (Figure 3.8) developed by Paul Scherrer Institute, Switzerland, has been in operation in Güssing. The concept will be demonstrated in the MW-scale during 2008. (Repotec 2007)


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Figure 3.8. Biomethane production from gasification gas (Ramesohl 2007).

3.3.1.2 BIONEER Process, Finland The BIONEER gasifier is an updraft moving bed gasifier, producing tarry LCV (low calorific value) fuel gas. The gasifier consists of a refractory lined vessel with a rotating cone-shaped grate. Biomass fuel is fed from the top, wherefrom it flows downwards through drying, pyrolysis, gasification and combustion zones. The residual ash is discharged from the bottom by the rotating grate. The temperature of the combustion zone is regulated by humidifying gasification air. Air and steam are fed as the gasification media through the grate. Since updraft gasification produces a raw gas with significant amount of tar, the gas cannot be either transported long distances or directly used in IC (internal combustion) engines. In the existing BIONEER plants the gas is burnt in a close coupled boiler to generate steam and hot-water for district heating. During the mid 80’s, VTT and BIONEER conducted extensive tests with a variety of feedstocks (ex. wood chips, forest wastes, peat, straw, RDF pellets, and coal and RDF mixed with wood chips) in a 1.5 MWth pilot plant located at BIONEER’s Hämeenlinna. A typical gas composition with 41% moisture content wood chips consists of 30% CO, 11% H2, 3% CH4, 7% CO2, and 49% N2, with a HHV of 6.2 MJ/m3n. The tar content of dry product gas is estimated to be in the range of 50 to 100 g/m3n. Between 1985 and 1986, when fuel oil prices were high, eight commercial BIONEER plants, with capacities ranging from 4 to 5 MWth, were commissioned, five in Finland and three in Sweden. Four plants are operated with wood or wood and peat mixtures while the rest are operated with peat only. Most of the gasifiers are in operation at small district heating plants to provide circulating hot water. The BIONEER plants are completely automated and operated with minimal personnel costs. A. Ahlstrom corporation bought the BIONEER company originally owned by YIT Corporation. After Foster Wheeler acquired Ahlstrom, in 1996 a 6.4 MWth plant was installed at Ilomantsi, in eastern Finland. (Kurkela & Simell 2004)


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3.3.1.3 NOVEL gasifier, Finland Condens Oy and VTT have developed a new type of fixed-bed gasifier, which is based on forced fuel flow and consequently allows the use of low-bulk-density (of the order of 150 - 200 kg/m3) fibrous biomass residues. Condens Oy is offering the Novel-technology both for heat alone and combined power and heat applications. The gas cleaning train based on VTT's catalytic gas cleaning know how followed by special wet scrubbing has been demonstrated in the pilot plant and is efficient enough to allow the use of gas in turbo-charged gas engines. (Kurkela & Simell 2004) The main features of the NOVEL CHP process are: Power output 0 – 3 MWe Fuel moisture 0 – 30 % Power production 30 - 36 % of the fuel capacity depending on the initial moisture of the

fuel Wide plant control range by using several engines and different engine sizes Heat production 60 % of the fuel capacity

The first full-size NOVEL CHP plant was constructed in 2004 in Kokemäki, Finland. This plant is equipped with a complete gas cleaning train consisting of a gas reformer, filter and acid/base scrubber for residual nitrogen compounds removal. For power production three 0.6 MWe Jenbacher engines are installed and for heat recovery also a gas boiler. The main characteristics of the Kokemäki plant project are (Figure 3.9): Wood fuel Fuel capacity 7.2 MW (6.2 MW, when the boiler is not in operation) Power output 1.8 MWe District heat output 4.3 MW (3.1 MW, when the boiler is not in operation) Heat output to the fuel dryer 429 kW Start up with one JMS 316 engine (600 kW) in winter 2004/2005 Start up of the two subsequent JMS 316 engines (á 600 kW) in winter 2005/2006 Total investment cost 4.5 M€

JMS 316engines

product gasscrubber

gasfilter

gascooler

tar reformergasifier

ash bin

Figure 3.9. NOVEL gasifier (Hannula 2007) If biomass gasification gas is considered as fuel for small-scale (about 1 MWe) SOFC, the sulphur removal is the most critical task. Sulphur removal is recommended to be carried out by dry techniques, like use of sorbents. Possibly the most succesfull route would be to


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develop the scrubber technology used in NOVEL gasification concept. If SOFC technology will accept higher sulphur levels than presently (1 ppm) more gas-cleaning techniques may be available. (Simell 2005) The new NOVEL-gasification technology uses forced fuel feeding making it possible to effectively utilise such biomass residues and energy crops that cannot otherwise be used without expensive pre-treatment. Test runs with this new type of gasifier were successfully carried out with various low-bulk-density biomass fuels. Reliable operation was achieved even with sawdust and wood shavings. The technical feasibility of the monolith-based gas cleanup concept was demonstrated by performing pilot-scale test run with a process consisting of the NOVEL fixed bed gasifier, a catalytic reformer followed by a filter and a gas scrubber/cooler. Gas produced had very low tar (< 100 mg/m3n), ammonia (< 50 ppm) and particulate (< 5 mg/m3n) contents and it can be considered suitable for use in modern turbo charged engines. The long-term durability of the nickel reforming catalyst was demonstrated in a slip-stream test during a 2300 h long test run. The technical and economical feasibility of the NOVEL CHP process was studied in Finnish and Italian cases, which gave very positive results considering promotion of the process. Consequently, the first full size NOVEL CHP plant (1.8 MWe) is currently under demonstration in Kokemäki, Finland. (Simell et al. 2004, Hannula et al. 2007)

3.3.1.4 PuhdasEnergia Oy, Finland PuhdasEnergia Oy located in Tampere Finland is developing a small scale CHP process based on downdraft gasification. PuhdasEnergia develops and markets biomass gasifiers, and adds value to its clients by reducing energy costs and pollution by means of gasification. Standard gasifier size is 1MW in gas output. Modular design enables installations up to 5 MWs by connecting several gasifiers. The main features of the process are: new design of the gasifier internals, stable operation with pellets and other good quality fuels, and simple construction and low investment costs. (Kurkela & Simell 2004)

3.3.1.5 Lahti Kymijärvi Plant, Finland In 1997-98, the Lahden Lämpövoima Oy, has installed a 60 MWth capacity atmospheric pressure Foster Wheeler CFB biomass gasifier (Figure 3.10) at its 200 MWe fossil fuel fired power station. The gasifier is a single gasifier vessel with a cyclone and an air preheater for heating the gasification air to approximately 400°C. The LCV gas is cooled from approx. 830-850°C to 700°C before it is transported in a pipeline to the boiler. The raw gas has no adverse effect on the performance of the boiler. Emissions are reduced and the heating surfaces in the boiler stay relatively clean. The reported gas composition (in vol%) is given below (Kurkela & Simell 2004): CO2 12.9 N2 40.2 CO 4.6 H2O 33.0 H2 5.9 CxHy 3.4 The heating value of the LCV gas is approximately 2.0-2.5 MJ/m3n. The NOx emissions were reduced by 5% (permitted level is 230 mg/MJ for both NOx and SO2) and the dust emission were reduced by half because of increased conductivity of dust. However HCl emission increased by a small quantity of 5 mg/Nm3. The breakdown of fuels in the boiler is approximately: 11% LCV fuel from the gasifier, 69% Coal, 15% Natural gas to boiler, and


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5% Natural gas to gas turbine. The plant supplies 200 MWe power to the national grid (110 kV line round the town) and 250 MWth heat to the town (100,000 inhabitants) and surrounding houses (main pipe 700 mm). The district heat system was constructed in 1958. (Kurkela & Simell 2004) The biomass gasification plant was installed primarily to use locally available fuels and waste materials including plastics. The annual average total efficiency is ~80%, the fuel to power efficiency with gas turbine in operation is 35%. The gas turbine has increased the efficiency by 4 % points. (Kurkela & Simell 2004)

Figure 3.10. Lahti Kymijärvi Plant (Kurkela & Simell 2004)

3.3.1.6 Varkaus gasification plant, Finland Corenso United Oy Ltd. has built a gasification plant (Figure 3.11) for energy production and aluminium recovery at its coreboard mill in Varkaus. The plant supplied by Foster Wheeler enables the complete exploitation of used packages containing wood fibre, plastic, and aluminium. It is the first plant in the world able to recycle the aluminium in used liquid packaging to create a raw material for foil for its original purpose, while simultaneously exploiting the plastic contained in the packages to produce energy.


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Varkaus gasification plant

Additional reject2200 kg/h

Reject5000 kg/h

Fuel bunker

Gasifier

Aluminiumseparator

Oil

Boiler

Filter

Dust0.43 kg/h

Stack

Dust100 kg/h

Steam45000 kg/h

Feed water

Ash10 kg/h

Aluminiumingots

600 kg/h

Screening

Sand / Ash / Metal180 kg/h 20 kg/h 14 kg/h

Sand180 kg/h

650 kg/hPlant 40 MW Dust emissions Ash flowFuel (g/h) (kg/h)Reject 433 30Coal 4750 700Peat 5520 400Bark, wood waste 5520 200

Dust emissions and total ash volumes of different fuels

Figure 3.11. Varkaus gasification plant In Corenso’s gasification plant, the fibre material in multi-layer packages is recycled in coreboard, the aluminium being recycled as raw material for foil. The remaining plastic is gasified to create energy. The metal and packaging bands in the loads of collected raw material are sent to the metal industry for recycling. Thus, everything is recovered. The gasification plant generates about 40 MW of heat, with an estimated annual total energy production in the region of 165 GWh. An additional benefit will be the resulting improvement in air quality. The plant was taken into commercial operation in autumn 2001 and has since then operated with high availability (monthly gasifier availabilities > 90-95 %). (Kurkela & Simell 2004)

3.3.2 Biomass gasification – synthesis gas

Syngas (synthesis gas) is the name given to a gas mixture that contains varying amounts of carbon monoxide and hydrogen generated by the gasification under oxygen of a carbon containing fuel to a gaseous product with a heating value. Various products can be made from syngas (Figure 3.12). Stringent gas cleaning requirements (Table 3.8) are set for complex and variable syngas.


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Figure 3.12. Syngas to liquids processes. (Dayton 2005) Table 3.8. Syngas impurities and tolerances for fuel synthesis (Dayton 2005).

3.3.2.1 Production of synthesis gas and FT diesel - Choren, Germany FT-diesel from biomass syngas is under demonstration in Germany. DaimlerChrysler, Volkswagen, Shell, and the German government are supporting a major collaboration project with Choren (Figure 3.13) industries to develop the BtL technology. A typical BtL plant will be of large scale, between 150 MW - 2 GW with a catchment radius between 30 and 170 km. Availability of sufficient biomass and at a suitable price are the key determinants in such a project. Whilst it was recognised that different raw materials could have an impact on the efficiency front end of the BtL process (the gasification stage), the quality of output from the fuel synthesis stage is not affected. Choren has plans to establish 5 plants in Germany of about 200 ktpa. Logistics will play a key role in the viability of such a plant. A suitable site


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will have multi modal transport options. Significant satellite collection systems will have to be established to collect biomass and prepare it for transportation. Pyrolysis is recognised as a means of concentrating biomass although there is a balance between the extra processing costs and transport efficiencies.

Figure 3.13. Choren biomass gasification – synthesis gas – FTD process scheme.

3.3.2.2 Production of synthesis gas and FT products – VTT, Finland Process development work in VTT’s UCG-project aims at creating basis and developing a new synthesis gas creation process, - which would be suitable for as vast fuel range as possible - which would consist of reliable and steady state processes - with which it would be possible to produce as many alternative end products as possible:

Fischer-Tropsch-liquids (FT), methanol, synthetic natural gas (SNG), hydrogen, electricity with high temperature fuel cells.

- which would have good overall efficiency, and - the production costs of which would be significantly lower (e.g. >20% lower than in

competing concepts). Various wet scrubbing based processes and dry gas cleaning were looked at more thoroughly (Figure 3.14). The results of tests made in the USA (basically GTI and Siemens Westinghouse) formed the basis for the study concerning dry gas cleaning. In the same context, requirements of different applications for the quality of product gas were evaluated.


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Figure 3.14. General layout of processes for biosyngas production and conversion. H2S and HCN have emerged as challenging impurities. Neither can be economically removed by non-regenerative scrubbing (maximum pH 8 to avoid CO2 absorption; DI thesis, Nyberg). Guard beds can handle 1-ppm input levels but, after Base Reforming, the levels of H2S and HCN will be around 100 ppm. Advanced Reforming under development at VTT should reduce HCN to 1-ppm level. H2S and HCN can be removed effectively by commercial solvent-based regenerative absorption processes (the traditional solution for gases with higher H2S contents, e.g. coal-derived gases). HCN can be catalytically hydrolysed to easily-removable NH3. In SOFC NH3 would be a fuel. N2, present in cases where air is used as an oxidant, is an awkward component in applications aimed at fairly pure gaseous fuels (SNG, H2). In principle, H2 and N2 can be separated by PSA, but presumably this would require a more costly solution than that currently employed in H2/PSA plants. In SOFC N2 is a diluent. SOFC requirements for fuel purity are much lower than those for FT synthesis (Table 3.9). (McKeough 2005): Table 3.9. Gas cleaning requirements

Application Requirements Chemical or Liquid Fuel Synthesis

Particulate < 0.1 ppmw Total sulfur < 60 ppbv Total halides < 10 ppbv NH3 < 10 ppmv HCN < 10 ppbv

SOFC power generation Particulate < 0.1 ppmw H2S < 1 ppmv HCl < 1 ppmv


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3.3.2.3 Production of synthesis gas and FT products - Stora-Enso & Neste Neste Oil and Stora Enso are working together to develop Biomass-to-Liquids technology for the production of synthetic diesel from wood residues. The project will focus on developing new gas purification technology related to generation of clean synthesis gas from wood and on using Fischer-Tropsch processes to produce crude biodiesel from the syngas. VTT will join the two partners to implement the development phase and commercialize wood-based biofuel production. The first step in the Neste Oil/Stora Enso project will be to design and build a demonstration plant at Stora Enso’s Varkaus Mill in Finland. The plant is expected to start up in 2008 and will produce heat and electricity for use locally and crude synthetic diesel to be refined into commercial fuel at Neste Oil’s refinery in Porvoo. Following the development phase and completion of the technical solutions, the joint venture will build a full-scale commercial production plant at one of Stora Enso’s mills. Stora Enso will be responsible for supplying wood biomass and utilizing heat generated. Wood biomass will be supplied from forests according to ecological preconditions. (Green Car Congress 2008)

3.3.2.4 Production of synthesis gas and FT products - UPM Kymmene & Andritz/Carbona, Finland

UPM and Andritz, with its associated company Carbona are also developing technology for biomass gasification and synthetic gas purification. The companies will test 2007-2008 Carbona's gasification technology at the Gas Technology Institute’s pilot plant near Chicago, Ill (Figure 3.15). The pilot plant can be applied for synthetic gas production under conditions similar to commercial scale plants. The cooperation also covers the design and supply of a commercial scale biomass gasification plant. Gas-cleaning is based on dry process (Figure 3.16), which is better suited for fuel cells than wet processes.

Figure 3.15. GTI Biomass gasification pilot plant in Chigaco, USA (Felix 2007)


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Figure 3.16. Synthesis gas cleaning at GTI (USA). (Felix 2007)

The main raw material used in UPM's biodiesel production will be wood-based biomass. Locating biodiesel production plants adjacent to existing UPM pulp or paper mills would further enhance the company's ability to utilize the wood raw material efficiently. Andritz has a comprehensive product portfolio for biomass starting from wood handling equipment, dryers, and pellet machines, to fluid bed boilers and gasifiers for lime kilns. The recent addition of Carbona’s special gasification technology enables further gasification applications to complement the product family. (TAPPI 2007)

3.3.2.5 Production of synthesis gas and DME - Black liquor gasification at ChemRec, Sweden

Dimethylether (DME) can be manufactured from syngas from biomass gasification. It has potential to become a widely available fuel due to its excellent properties as a diesel or LPG substitute, gas turbine fuel or as fuel for FC‘s. The GTL fuels will be ideal FC fuels due the absence of sulfur, olefins and aromatics. DME has been successfully tested as a fuel for SOFCs. (Hansen 2004) In Sweden the focus on biomass gasification is on production of DME. Gasification technology is under development for black liquor. Black liquor is an important fuel in countries having a significant pulp and paper industry. The ChemRec black liquor gasification process (Figure 3.17) is technically the most advanced process at the moment. The atmospheric process has been demonstrated and the pressurised process development unit is under demonstration. In utilising biomass fuels or black liquor, the IGCC (Integrated Gasification Combined Cycle) process offers the possibility to significantly increase the ratio of electrical power to thermal power with combined cycle. The fuel composition is similar to that from biomass gasification and hence similar gas-cleaning may be used.


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Figure 3.17. Chemrec black liquor gasification – synthesis gas – DME production scheme.

3.3.2.6 Production of synthesis gas via pyrolysis liquid gasification – FZK, Lurgi BioLiq Process

In 2007 Lurgi and Forschungszentrum Karlsruhe officially inaugurated the first stage of the joint research plant for the generation of fuels from biomass. With the two-stage bioliq® concept developed at Forschungszentrum Karlsruhe, synthetic high-tech fuels and base products for the chemical industry can be produced. The bioliq® process (Figure 3.18) is suited for biomass, which is distributed over large areas and mostly exhibits a low energy content. In a first, decentralized step, the biomass is converted to a transportable, liquid intermediary product with a high energy density (BioSynCrude) in a so-called fast pyrolysis process and can then be efficiently transported over great distances to central facilities for conversion to synthesis gas and fuels. Subsidized by the Fachagentur Nachwachsende Rohstoffe (Agency for Renewable Resources, project executing organization of the Federal Ministry of Food, Agriculture and Consumer Protection) and in cooperation with Lurgi GmbH, a pilot plant for the complete bioliq® process chain is being built on the premises of the research center. Construction of the plant unit for the first process step to generate energy-rich BioSynCrude was completed in summer 2007. Presently, the pilot plant is being extended by the process steps for synthesis gas generation, gas cleaning and fuel synthesis through to the petrol pump to demonstrate the technical viability of the overall process, improve it and prepare its commercialization.


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Figure 3.18. Gasification of pyrolysis liquid-char slurry at FZK Germany

3.3.2.7 Synthesis gas products – SNG Fossil SNG is manufactured from light hydrocarbons, propane, buthane and naphtha. Bio-based SNG (Figure 3.19) can be produced from biogas (chapter 3.2.3), biomass gasification producer gas (chapter 3.3.1) or from synthesis gas from biomass oxygen gasification which is presently under demonstration. Methanation technology is commercial. Gas market directive 2003/55/EC opens the NG network to the SNG. (Mäkinen et al. 2005)

Figure 3.19. Process scheme for production of SNG.


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The first demonstrated integrated system line-up on SNG production is based on atmospheric gasification in combination with pressurised methanation (Figure 3.20). Biomass (beech wood) is gasified in the ECN lab-scale atmospheric bubbling fluidised bed gasifier “WOB”. Oxygen is used as gasifying medium to produce an essentially nitrogen-free product gas and steam is added to moderate the temperature in the bed of the gasifier. The gasifier is typically operated at 850°C. The raw product gas passes a high-temperature gas filter (ceramic candle) operated at 350°C to remove essentially all the solids. The product gas compositions are shown in Table 3.10.

Figure 3.20. Biomass gasification to syngas and SNG Table 3.10. Gas composition after various treatment steps. ECN


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3.3.2.8 Synthesis gas products – Ammonia Ammonia is a somewhat overlooked FC fuel probably due to concerns about toxicity and explosion risks. Ammonia is, however, handled on a major scale worldwide at relatively low cost with an excellent safety record. NH3 offers energy efficiencies at least equal to methanol but on a local level is CO2-free and furthermore, offers zero emission potential. The production technology is well established and fits well to gasification technologies with CO2 sequestration. It is the only hydrogen carrier produced on large scale, which do not emit CO2 when used locally. (Hansen 2006) The Oulu peat gasification plant (Figure 3.21) was the first commercial ammonia production plant using peat in the world. Production was started in 1988. The existing oil-based ammonia plant was modified to use peat additionally in production. Peat gasification was in production use with partial capacity for thousands of hours together with oil gasification. The problems encountered were due to the heterogeneous quality of peat. Difficulties were also caused by the high naphthalene content of gas and by blockages in the cyclone-recycle pipe of the gasification. Technical solutions for these problems were available, which proves that the production of synthesis gas and ammonia from peat on a commercial scale is technically possible. In addition, the market price for ammonia decreased significantly during demonstration.

Figure 3.21. Ammonia from peat-syngas process.


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3.3.2.9 Synthesis gas products – Methanol For intermediate temperature SOFCs operating at temperatures as low as 500 °C, methanol is considered the most likely fuel, since the operating temperatures are below those at which natural gas and higher hydrocarbons can be effectively reformed to synthesis gas, whereas methanol can be efficiently reformed at 300 - 600 °C. Nowadays the major feedstock for synthesis gas for methanol production is natural gas (and some coal and heavy petroleum fractions), but biomass may be used as well. For the production of methanol from biomass (Figure 3.22) the following major steps are required:

Gasification; to produce synthesis gas. Gas upgrading (gas clean-up, CO-shift and CO2-removal); to meet the requirements

of the methanol synthesis. Methanol synthesis and purification; to produce methanol from synthesis gas.

In the transportation sector present infrastructure does not stand for polar, corrodative methanol. The ecotoxicity of methanol is also a big issue.

Figure 3.22. Process scheme for production of methanol.

3.3.2.10 Synthesis gas products – Ethanol GM announced 2008 a partnership with Coskata Inc. to develop processes to produce ethanol from syngas. The Coskata process can combine a variety of gasification technologies with Coskata propriety microorganisms and bioreactors, which again can be used to produce ethanol from carbon-based feedstocks, such as garbage and plant waste, for less than $1 a gallon. (Green Car Congress, 2008)

3.4 Ethanol

Ethanol is presently viewed by many scientists as the perfect fuel for portable fuel cells mainly because it does not need any expensive cleaning procedure. Ethanol production from sugar and starch containing raw materials is commercial technology. (Oasmaa 2005)


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Most fuel ethanol produced in the United States is made from corn. A lot of discussion is going on on sustainability of corn and grain ethanol. Ethanol production is currently rapidly evolving (Figure 3.23, 3.24). The main advances relate to the fermentation of cellulose and hemicellulose, where formerly only free sugars and starch could be fermented. As a consequence of these developments, it will be possible to ferment wood and grass like biomass, leaving only the lignin fraction as a residue. The advantage is the much higher yield (or lower cost) of these crops.

Biofuel production in EU, 1992-2005

0

500

1 000

1 500

2 000

2 500

3 000

3 500

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

ktoe

/a

Fuel ethanolBiodiesel

Source: European Biodiesel Board, System Solaires EurObserv'ER 2005 & ht tp://europa.eu.int

Biodiesel tonne ~ 0.9 toeEthanol tonne ~ 0.64 toe

Figure 3.23. Production of fuel ethanol and biodiesel in EU 1992-2005

Ethanol production in the EU in 2005Bioethanol production in 2005

0

20

40

60

80

100

120

140

160

180

Spain Sweden Germany France Poland

ktoe

/a

source: System Solaires EurObserv'ER 2005 & http://europa.eu.int

Figure 3.24. Ethanol production in the EU in 2005


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The efficiency of ethanol production from corn is about 41 % (LHV basis), when that from wood is about 28 % (LHV basis). Due to its structure, the hydrolysis of wood is more complicated compared to the hydrolysis of starch. In Sweden, a new demonstration plant (Figure 3.25) producing 400–500 litres/d of ethanol from cellulose and wood-based raw materials was launched in spring 2004. (Mäkinen et al. 2005) In Canada, Iogen has a pilot plant based on straw.

Figure 3.25. The Swedish ethanol pilot plant fueled with woody biomass. UPM and Lassila & Tikanoja (L&T) in Finland have developed a new concept to produce ethanol and energy from commercial and industrial waste, such as paper, cardboard, wood and plastic. The companies have studied the concept under laboratory conditions in cooperation with the Technical Research Centre of Finland (VTT) and will now begin estensive testing at VTT´s Rajamäki pilot unit. The objective is to be ready by the end of the year to decide on building a commercial scale plant. (UPM Press release 2008 in AMFI Newsletter Jan 2008) Oxford Catalysts Group PLC has signed a Strategic Alliance Agreement with Novus Energy, LLC, to develop technology for the conversion of biogas derived from organic wastes to ethanol and higher-chain alcohols. Oxford Catalysts offers a novel class of catalysts made from metal carbides which can match or exceed the benefits of traditional precious metal catalysts for applications such as Fischer-Tropsch processing or hydro-desulfurization (HDS) at a lower cost. (Green Car Congress 2008 in AMFI Newsletter Jan 2008)


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3.5 Biodiesels

Biodiesel (Figure 3.26, Table 3.8) is commercially produced via esterification of vegetable oils or by catalytic hydrocracking of oils and fats.

Biodiesel production in the EU in 2005

Biodiesel production in 2005

0

200

400

600

800

1000

1200

1400

1600

1800

German

y

France Ita

ly

Czech

Reb

.

Austria

Slovak

iaSpa

in

Denmark UK

Lithu

ania

Sweden

ktoe

/a

Source: European Biodiesel Board Figure 3.26. Biodiesel production in the EU in 2005 Neste Oil has built a biodiesel plant at its Porvoo oil refinery. The plant has an annual capacity of roughly 170,000 tons of biodiesel. Production of biodiesel will be based on a NExBTL process (Figure 3.27) developed by Neste Oil that produces high-quality diesel fuel (Table 3.11) from vegetable oils and animal fats. The company has announced that it will follow up this first plant with a similar unit at Porvoo, also rated at 170,000 t/a, to begin production in 2009. Sustainability issues concerning use of palm oil as a feed are presently under discussion.

NExBTL-ProcessConversion

of fatty acidsto

parafins and isoparafins

Stabilation

Feed tank

PretreatmentImpuritiesremoval

Fuel gas

Sour water

SludgeAcidCausticWater

Hydrogen

Bio Oil

Biodieseltank

Dieseltank

Diesel +BiodieselBlends

NExBTL component sales

Mineral oil diesel

Figure 3.27. NExBTL process of Neste Oil. (Mäkinen et al. 2005)


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Neste Oil plans to build up the world´s largest biofuel facility in Singapore. The plant, which is based on NExBTL technology, will have a design capacity of 800 000 t/a. The Singapore plant is expected to be completed by the end of 2010. Palm oil will be the main feedstock for the Singapore plant. Neste Oil has committed to use RSPO certified palm oil as soon as sufficient quantities are available. Singapore is the world´s third-largest center of oil refining, and occupies a central location in terms of product and feedstock flows and logistics. (Neste Oil 2007) Table 3.11. Properties of diesels

NExBTL GTL Fischer-Tropsch Diesel

FAME Diesel fuel 2005 (summergr.)

Density at +15 °C (kg/m3) 780 – 785 770 – 785 ~885 ~835

Viscosity at +40 °C (mm2/s) 3.0 – 3.5 ~3.2 – 4.5 ~4.5 ~3.5Cetane index or number 98 – 99 ~73 – 81 ~51 ~5310 % distillation (°C) ~260 – 270 ~260 ~340 ~20090 % distillation (°C) 295 – 300 325 – 330 ~355 ~350Cloud point (°C) -30 ... -5 ~0 ... +3 ~0 ... -5 ~-5Heating value (MJ/kg) ~44 ~43 ~38 ~43Heating value (MJ/l) ~34.5 ~33.8 ~34 ~36Polyaromatic content (wt-%) ~0 ~0 ~0 ~4Oxygen content (wt-%) ~0 ~0 ~11 0Sulfur content (mg/kg) <10 <10 <10 <10 Sulphur of NExBTL is typically below 1 ppm. The specifications set the limit to below 10 ppm.

Algae may be a future feedstock for biodiesel. Shell and HR Biopetroleum have formed a company, Cellane, to develop a pilot facility in Hawaii, to grow marine algae and produce vegetable oil for conversion into biofuel. (Shell Press release, 2007) Green Star Products (GSPI) will build a 100-acre commercial algae in the Midwest. The Algae Facility will be constructed adjacent to an existing biodiesel plant and will use the CO2 emitted from this plant to feed a portion of the algae facility needs. (Green Star Products 2007) Solazyme of San Francisco, a developer of algae-based biodiesel, announced the first road test of the fuel. A blend of the algae biodiesel fuel, called soladiesel (tm), was tested in a Mercedes-Benz diesel car under typical driving conditions. The biodiesel blending level of 5% blend was used. The company is producing thousands of gallons of algal oil, and recently signed a biodiesel feedstock development and testing agreement with Chevron. Chevron and NREL, will collaborate to define suitable algae strains for production of biofuels. PetroSun BioFuels has entered into a joint venture to build up a biodiesel refinery in Arizona. The feedstock will be algal oil produced by PetroSun BioFuels at company owned and operated algae farms. The refinery will have an annual production capacity of 30 million gallons. PetroSun BioFuels will process the residual algae biomass into ethanol. The biorefinery and algae farm complex generate all of its own electrical and heat requirements, utilize non-potable or saltwater, consume no fossil fuels and will be carbon neutral. The joint venture anticipates that all permits will be approved and construction on the biorefinery should commence during the third quarter of 2008. UOP is also developing technology fro the production of renewable Jet Propellant-8 fuel from vegetable and algal oils funded from the Defense Advanced Research Projects Agency (DARPA). (AMFI 2007)


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3.6 Other biofuels

Other optional biofuels for R&D could be waste or side-products from biofuel processing, like glycerol from esterification of FAME or levulinic acid from paper mill sludge, municipal solid waste, unrecyclable waste paper, waste wood, and agricultural residues. Also bio-buthanol has been claimed to be cheaper alternative to ethanol. In addition, liquids from biomass fast pyrolysis have been studied as alternative feeds for gasification or steam reforming in producing hydrogen gas. (Oasmaa 2005)


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4 Quality requirements of fuels for SOFC SOFC can utilise a wide range of fuels (Figure 4.1). Due to internal reforming hydrogen, carbon monoxide and methane can be reformed directly on the anode. Other fuels need to be processed to be suitable for SOFC.

Oxygenates

Coal-based fuels

Hydrogen

H2 + CO

Natural gas

Bottled gas(propane, butane)

GasolineDiesel

Aviation fuel

Ammonia

Acetic acid

Formic acidButanol

Methanol

Butyric acid

Hydrocarbons

Oxygenates

Coal-based fuels

Hydrogen

H2 + CO

Natural gas


GasolineDiesel

Aviation fuel

Ammonia

Acetic acid

Formic acidButanol

Methanol

Butyric acid

Hydrocarbons

Coal-based fuels

Hydrogen

H2 + CO

Natural gas


GasolineDiesel

Aviation fuel

Ammonia

Acetic acid

Formic acidButanol

Methanol

Butyric acid

Hydrocarbons

Hydrogen

H2 + CO

Natural gas


GasolineDiesel

Aviation fuel

Ammonia

Acetic acid

Formic acidButanol

Methanol

Butyric acid

Hydrocarbons

H2 + CO

Natural gas


GasolineDiesel

Aviation fuel

Ammonia

Acetic acid

Formic acidButanol

Methanol

Butyric acid

HydrocarbonsSNG frombiomass syngasor biogas

Bio-Methanol frombiomass syngas

Biogas, Landfill gas

Vegetable oils,Biodiesel, NExBTLFT-diesel

NH3 from biomass syngas

Biomass gasificationgases

Pyrolysis liquid

Levulinic acid

Bioethanol

Glycerolfrom biodiesel production

DME

SNG frombiomass syngasor biogas

Bio-Methanol frombiomass syngas

Biogas, Landfill gas

Vegetable oils,Biodiesel, NExBTLFT-diesel

NH3 from biomass syngas

Biomass gasificationgases

Pyrolysis liquid

Levulinic acid

Bioethanol

Glycerolfrom biodiesel production

DME

Figure 4.1. Range of potential fuels for SOFCs. SOFCs are relatively tolerant of fuel impurities. There are discrepancies in the tolerance for harmful species specified by fuel cell developers, even for similar type fuel cells. These discrepancies are for example due to electrode design and microstructure differences. In some cases, the presence of certain harmful species causes immediate performance deterioration. More often, the degradation occurs over a long period of time, depending on the developer’s permissible exposure to the specific harmful species. Table 4.1 presents the effects of various reactants on SOFC. SOFCs have been found to tolerate small levels of air- and fuel-side impurities without any significant long-term performance problems. While operating with air containing seawater mist, some voltage losses occur but these can be entirely attributed to water vapour; most of the salt passes through the cell with only minimal deposition on the inside of the air electron tube. The addition of 1 ppm HCl did not have any detectable effect. Silicon (Si) is believed to accumulate on the fuel cell electrode in the form of silica (SiO2). However, when the H2O content of the fuel is less than 13%, significant Si transport is not expected. (Oasmaa 2005)


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Table 4.1. Effects of various reactants on SOFC.

Specimen Limits for SOFC Effect H2 Fuel

CO Fuel

CH4 Fuel

NH3

Fuel NOx formation at anode, anode poisoning Fuel is diluted by product water

CO2, N2 Diluents

H2O Diluent Decreases cell efficiency

O2 < 2 vol-% Reacts with H2

C2-C6

Sat HC – 12 vol% (CH4 included) Olefins (ethene) – 0.2 vol% Aromatics (benzene,) - 0.5 vol% Cyclics – 0.5 vol%

Plugging & coking Fuel w/reformer

Gasification tars (naphthalene) < 8 g/m2 3 Coke formation,

plugging

S as (H2S; COS, DMS, DMDS, MeSH) < 1 ppm

Degradation of electrodes, Degradation in electrochemical performance Catalyst poison

organo-nitrogen compounds

Halogens (HCl) < 1 ppm Corrosion, poison

Heavy metals < 1 ppm Deposition, coking

Alkali metals < 1 ppm Deposition

See water mist

Minimal deposition of alkalis Cathode poisoning in direct supply

Particles < 1 µm, 1 ppmw 2 Plugging

SiO24 Not specified Deposition

Siloxanes For gas engines < 0.03 ... < 28 mg/m3 Deposition 2 Hofman et al. 2007 3 Tar content of 8 g/m2 did not poison anode in 30 hours run (Nagel et al. 2007) 4 Si may accumulate on the fuel cell electrode in the form of SiO2. When the H2O content of the fuel is less than 13%, significant Si transport is not expected.

There is more experience on tolerancy of gas engines towards impurities (Table 4.2). Because SOFC has to compete with gas engines in biogas utilisation it would be beneficial if the tolerancy of SOFC would be at least as good as for gas engines. Presently, SOFC tolerates better only ammonia. In addition, SOFC can operate at lower methane concentrations than gas engines.


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Table 4.2. Gas specifications from selected manufacturers of landfill gas engines. Environment Agency, UK, August 2004.

Sulphur is the most relevant impurity and it can be present up to 1% level in marine diesel fuel. Natural gas often has “odorant” sulphur compounds added to make leaks more easily


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detectable. Sulphur is poisonous for catalytic sites in fuel cell anode and the effect is aggravated when there are nickel or iron-containing components including catalyst. In the Real-SOFC project (Noponen et al. 2007) sulphur poisoning of the SOFC anode has been studied with hydrogen sulphide (H2S). It has been shown that nickel will be reacted into nickel sulphides, i.e. mostly into nickel subsulphide (Ni3N2) and into nickel sulphide (NiS), but also nickel sulphate (NiSO4) has been found from the cells exposed to H2S rich feed gas. The production of the nickel sulphides effect the electrochemical activity of the hydrogen oxidation reaction and even more on the internal reforming activity, i.e. steam reforming of methane. Pre-reformate seeks to the equilibrium content when no hydrogen sulphide is present in reformate. Even 1 ppm H2S reduced the methane conversion to 45 % as without sulphur the conversion was 99%. These results indicate that nickel sulphides have fairly good electrochemical activity but pure reforming performance. Nickel sulphate is an electronic insulator and its production will cause cell failures. In addition, production of SO3 will lead to production of sulphur acid that will cause corrosion of the balance of plant components. The production of the nickel sulphides and nickel sulphate is reversible reaction seen clearly from the cell voltage and reforming activity. Irreversible deactivation of the cell performance is caused by morphological changes in the anode microstructure resulting from transportation of bulk nickel into the nickel sulphite and nickel sulphate phases. Tungsten oxide impregnated cells may give a positive influence to the electrochemical performance by at least decelerating the production of nickel sulphides. However the results are contradictory and still WO3 cells show similar kind of fluctuation in the voltage as the H2S content is varying in the gas feed as the pure nickel anodes. (Noponen et al. 2007) Many groups have determined with microscopic analysis that nickel sulphides are produced when nickel anodes are exposed to H2S rich gas when the H2S level exceeds 100 ppm. From the equilibrium calculations, production of nickel sulphides is predicted also at 1 ppm level but its saturation level is two decades lower which may explain why sulphides are not seen with the microscopic methods. It has also been seen that sulphides are saturated at the triple phase boundary indicating that the anodic over potential enhances the sulphides production. There have also been indications that both at the anode surface facing the gas channel and at triple phase boundary nickel sulphide production results in nickel transportation from the bulk phase. This re-arrangement of nickel will cause irreversible damage at least by decreasing the ionic and electronic conductivities resulting from reduced number of conduction paths. (Noponen et al. 2007) Solid oxide fuel cells having nickel anode can be operated with H2S rich gas for thousands of hours as shown by Hexis if the H2S concentration is low enough. If no internal reforming activity is needed, the allowed H2S level can be ppm-level. If internal reforming activity is desired, the H2S content has to be reduced notably under ppm-levels. In addition, if the sulphur content in the feed gas is varying, the cell voltage will be fluctuating even at ppm-level. The fluctuation will cause decreased predictably to the system performance and thus will aggravate the controllability of the solid oxide fuel cell system. (Noponen et al. 2007) If truly H2S resistant anodes are wanted, these cannot be based on nickel anodes. Nickel will always react with H2S to form nickel sulphides and even nickel sulphates that will decrease the electrochemical performance and the internal reforming activity. Eventually the production of nickel sulphides and nickel sulphate may destroy the microstructure of the anode leading to irreversible damages. (Noponen et al. 2007)


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For HCl and CH3Cl it was observed that at 850 °C 40 ppm HCl+CH3Cl degraded the SOFC performance steadily, but at 750 °C there was no significant effect. (SECA 2007) Ethylene has been analyzed to be the most significant impurity in diesel reformate. In the work by Aarva (2007) an anode supported unit cell was used to examine the behaviour and performance of a SOFC when ethylene was added to hydrogen feed. The effect of ethylene was first examined by increasing amount of ethylene in the feed stepwise from 0 ppm to 1000 ppm at 800 °C. After that the test was continued at lower 750 °C and 700 °C. Changes in the cell performance were monitored by impedance spectroscopy and polarization measurements. It has been demonstrated that ethylene (1000 ppm) does not accelerate degradation at 800 °C and 750°C within 580–680 h at least when carbon deposition is not thermodynamically viable i.e. water supply (S/C 15) is sufficient. When temperature was decreased to 700 °C severe carbon formation was detected even when S/C = 15 at the cell inlet was used. Carbon formation was deduced to consist of three stages which might be: initial stage where carbon nanotubes start forming, second stage where tubes gain length and termination stage where nanotubes lay down on catalyst surface and cell performance is collapsed. Thus ethylene is suitable fuel component in hydrogen rich fuel feed if the temperature is 750 °C or higher, otherwise catalyst should be regenerated within certain time interval with steam rich feed without carbon source. (Aarva 2007)

4.1 Fuel properties

Summaries of properties of gaseous and liquid fuels are presented in Tables 4.3 and 4.4. Table 4.3. Properties of gaseous fuels (various references) Natural gas BiogasSource Finland Farm biogas Sewage digester LandfillCH4 > 98% 55-80 % 50-90 vol-% 30-60 vol-%COAmmonia NH3 0-50 mg/m³ 0-10 mg/m³CO2 20-45 % 10-50 vol-% 25-50 vol-%N2* < 1% < 2 % < 9 % 0-30 vol-% *O2* < 1 % < 1 % 0-5 vol-% *H2O 1 % 4-7 vol-% 1-7 vol-%C2 hydrocarbons < 1 % ethaneEtheneC3-C5 hydrocarbons < 0,5 % < 1300 ppmvC6+ hydrocarbons < 400 ppmvVOC < 250 mg/m³ < 300 mg/m3 < 250 mg/m³Halogens < 100 mg/m³ < 300 mg/m³Siloxanes < 50 mg/m³ < 150 mg/m³Aromatic compounds/tars < 2 mg/m3 < 12 mg/m3 < 300 mg/m3Nitrogen compounds (NH3, HCN)Sulphur < 1 mg/m3n 100-2000 mg/m³ 100-1000 mg/m³Sulphur compounds (H2S, COS) 15 mg/m3 C4H8S 50-300 ppm H2SChlorine compounds (HCl) < 100 mg/m3


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Table 4.4 Properties of liquid fuels (various references) Alcohols & ethers (Bio)diesels

Methanol Ethanol DME NExBTL FT-diesel RME FAME S-free DieselChemical formula CH3OH C2H5OH CH3OCH3Molecular weight (kg/kmol) 32 46 46 296Water (wt-%) < 0,01Methanol (wt-%) < 0,05Methyl ethyl ether, MEE (wt-%) < 0,20Higher alcohols (wt-%) < 0,05Higher ethers (wt-%) < 0,05Ketones (wt-%) < 0,05Odorant (e.g. ethylmercaptane) (ppm) 20Lubricant (e.g. Lubrizol or Hitech) (ppm) 500-2000Aromatics (wt-%) 2 24Polyaromatic content (wt-%) ~0 ~0 ~0 < 0.1Oxygen content (wt-%) 50 35 35 ~0 ~0 9,22 ~11 0Nitrogen content (mg/kg) 6 1Sulfur content (mg/kg) < 1 < 1 120 <10 < 1Reid vapour pressure (kPa) at +15 °C 31,7 16,5Auto-ignition temperature (°C) 450 390-420 235 315Boiling temperature (°C) 65 78 347 14010 % distillation (°C) ~260 – 270 ~260 ~340 ~20090 % distillation (°C) 295 – 300 325 – 330 ~355 ~350Density at +15 °C (kg/m3) 790 800 670 (20°C) 780 – 785 770 – 785 880 ~885 867Viscosity at +40 °C (mm2/s) 3.0 – 3.5 ~3.2 – 4.5 5,65 ~4.5 ~3.5Cloud point (°C) -30 ... -5 ~0 ... +3 0 ~0 ... -5 ~-5Octane number (RON) 110 109Octane number (MON) 92 92Cetane index or number 5 11 55-60 98 – 99 ~73 – 81 61,8 ~51 ~53Lower heating value (MJ/kg) 19,8 26,4 28,4 ~44 ~43 38 ~38 ~43Lower heating value (MJ/l) 15,6 21,2 18,8 ~34.5 ~33.8 32,8 at 20C ~34 ~36


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5 Production costs NG will be the main fuel for SOFC for long. The consumer prices for NG are seen in Table 5.1. Table 5.1. Consumer prices for NG, €/MWh (tax not included)1

T1: Pienehkö, pääasiassa lämmityskäyttöön maakaasua tarvitseva asiakas, maakaasun kokonaiskulutus 50 GWh/a (5 milj.m3/a). T3: Keskikokoinen, pääasiassa lämmityskäyttöön maakaasua tarvitseva asiakas, maakaasun kokonaiskulutus 150 GWh/a (15 milj.m3/a). T4: Keskikokoinen teollisuusasiakas, kaasun tarve melko tasaista ympäri vuoden, maakaasun kokonaiskulutus 150 GWh/a (15 milj.m3/a). T8: suuri teollisuusyritys tai voimalaitos, kaasun tarve melko tasaista ympäri vuoden, maakaasun kokonaiskulutus 1000 GWh/a (100 milj.m3/a). Kuvassa esitetty kokonaishinta sisältää maakaasun siirtohinnan ja energian myyntihinnan. Siirtohinnan osuus kokonaishinnasta vaihtelee eri käyttäjien kesken ja on keskimäärin 15-25 %. Biogas and producer gas utilisation may be most beneficial in decentralized systems (small scale, local use). Biogas production and upgrading technologies are commercial. However, because of large variations in biogas composition and impurity content R&D should be focused on optimising an economical gas-cleaning system. Biomass gasification is under demonstration. As with biogas the economical gas-cleaning system would be the key issue. Gas-cleaning to meet the demands of SOFC may not be economical in small-scale (about 1 MWe) in Finland. In countries, where the electricity price is much higher, like Germany and Austria, the economics may be different.

The production costs of ethanol and biodiesel are same in the Europe. However these biofuels cannot compete in costs with sugar cane ethanol (about 100 €/MWh, 0.6 €/l) from Brazil. Sustainability issues have to be taken care of with all 1st generation biofuels. The increase in raw oil price improves the competitiviness of biodiesel. (Table 5.2).


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Table 5.2. Fuel consumer prices (taxes included)1 (Tilastokeskus www-sivut)

1) Moottoribensiini, dieselöljy ja kevyt polttoöljy: kuuden paikkakunnan (Helsinki, Mikkeli, Oulu, Rovaniemi, Seinäjoki ja Turku) 15. päivän hintojen painotettu keskiarvo. Synthesis gas products, i.e. FTD, MeOH, DME, H2, and NH3 will be produced in large centralised plants. When integrating BTL production with pulp mill (Figure 5.1) benefits are gained i.e. utilising the steam formed during BTL. In the recent (McKeough and Kurkela 2007) detailed process calculations it was concluded that the production cost estimates display a relatively small dependency on the end-product (Figure 5.2). The differences are smaller than would be expected on the basis of feedstock-conversion efficiences (Figure 5.3) and are largely explained by compensating differences in the overall thermal efficiences. The application makes the largest difference. (McKeough & Kurkela 2007) In Figure 5.4 it is seen that FTD and SNG have similar price if used for power or CHP use. The production costs for SNG includes pressurisation up to 50 bars. The price for NG is about half of the SNG.


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Figure 5.1. Energy flows in co-production of FT liquids at a large paper mill. (McKeough & Kurkela 2007)

Figure 5.2. Estimated feedstock-conversion efficiencies in co-production of FT liquids at a large paper mill. (McKeough & Kurkela 2007)


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Figure 5.3. Estimated production costs in co-production of FT liquids at a large paper mill. (McKeough & Kurkela 2007)

CHP

Includes pressurisationto 50 bars

Figure 5.4. Estimated biomass-to-pump costs in co-production of FT liquids at a large paper mill. (McKeough & Kurkela 2007)


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6 Conclusions A summary of issues on using various fuels for SOFC is shown below: Energy Source Maturity of technology Technical issues Other issuesNatural Gas Commercial Minimal fuel pretreatment necessary Existing pipeline structureS-free diesel Commercial Minimal fuel pretreatment necessary Existing diesel infrastructureBiodiesel from esterification Commercial Minimal fuel pretreatment necessary Utilize existing diesel infrastructureBiodiesel from hydrocracking Commercial Minimal fuel pretreatment necessary Sustainability of palm oil, competition with traffic sectorBiogas Commercial Wide variation in gas composition Must be located on siteSNG from biogas Under demonstration Expensive upgrading techniques Can use NG pipeline structureLandfill Gas Commercial Feasible gas cleaning key issue Must be located on siteBio-ethanol from sugar cane Commercial Sustainability issues Competition with traffic sectorBio-ethanol from grain/maize Commercial Sustainability issues Competition with traffic sectorBio-ethanol from lignocellulosics Under demonstration Not known Competition with traffic sectorSyngas from biomass gasification Under demonstration Challenging gas cleaning - SNG from syngas - Commercial Minimal fuel pretreatment necessary Can use NG pipeline structure - MeOH from syngas - Commercial Minimal fuel pretreatment necessary Easy storage and transportation - NH3 from syngas - Commercial Minimal fuel pretreatment necessary Carbon-free fuel - FT diesel from syngas - Commercial Minimal fuel pretreatment necessary Competition with traffic sectorProducer gas from biomass gasification Under demonstration Tailored gas cleaning for SOFC Gas engines market leaders, competition

Must be located on sitePyrolysis liquid Under demonstration Steam reforming to SOFC feasible Easy storage and transportation,

but challenging biodegradable fuel Compared to other fuel cells SOFC suits well for integration with biofuels due to its relative high tolerance towards contaminants and its ability to internally reform biofuel gases, leading to lower operational costs. The development of new fuel cell materials, which will better withstand biofuel contaminants, may help in promoting biofuel fed fuel cells, by removing the need for an additional gas-clean up process. However, it seems that it is more feasible to remove the contaminants from fuel than develop fuel cell to tolerate dirty gas. In short-term biogas is a potential biofuel for SOFC. Increasing amounts of bio-wastes are available. Biogas production is commercial technology and assumed to be feasible in small scale in decentralised energy production. SOFC must be located on-site. Large variations in gas compositions cause challenges for upgrading and use. Commercial gas cleaning equipment are available but their costs are high. The competition with gas engines and micro turbines will be tight and hence the development of techno-economically feasible biogas cleaning system is the key. Several demonstration projects are running on biogas and landfill gas in MCFCs. The demonstration of fermentation biogas+SOFC system (Sulzer-Hexis, CH) was operated for 5,000 hours with electrical efficiency of 35%. Use of landfill gas is more challenging due to various complex impurities and large variation of gas composition between various landfills and within one place depending on time and weather conditions. Siloxanes are perhaps the most harmfull impurities in landfill gas and they have to removed completely. In medium-term (within 5-10 years) syngas products methanol, FT-diesel, and SNG seem all promissing. Recent detailed process calculations for integrated BTL process show that the production costs for methanol, FT-diesel, and SNG are quite similar and the end-use makes the difference in cost. Compared to fossil NG their price is about doupled. FT-diesel and methanol are potential when easy transportation and storage are determining. In case of FT-diesel and SNG the competition within energy sectors will be the determinining factor. Transportation fuels are in many cases more valuable than bioelectricity. For methanol no infrastructure exists. Respectively, SNG is feasible in countries having existing distributed NG infrastructure, like in Netherlands. Biomass gasification-syngas products concepts are under demonstration in EU (Germany, Finland) and in USA. If electricity can be used at the syngas plant SOFC may also be coupled after the gas cleaning stage.


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Also ammonia (NH3) can be manufactured from syngas via biomass gasification. NH3 is carbon-free and could be a promising biofuel for SOFC in in large-scale installations where safety issues are easier to take care of. Recently 100% NH3 has been successfully reformed in SOFC. SNG can also be upgraded from fermentation biogas. Gas market directive 2003/55/EC opens the NG network to both SNG from syngas and biogas. However, cleaning and upgrading processes are established for biogas are still expensive. Standardisation of processed biogas quality and access rights for adding processed biogas to the NG grid are critical. The profitability of SNG from biogas is country specific. Bioethanol is commercially produced from corn (USA), sugar beat, wheat (EU), or sugar cane (Brazil). Sugar cane ethanol is cheapest bio-ethanol in the market. However, debats on its sustainability issues continue. There are also demonstration of 2nd generation lignocellulosics-ethanol in EU (Sweden), USA, and Canada. Bioethanol is valuable transportation fuel and hence its cost may be too high for electricity generation. Biomass air/steam gasification has been demonstrated. Gas-cleaning systems are under demonstration. The gas-cleaning system should be developed for SOFC demands. Short-term SOFC tests with real gasification gas are claimed as promising, but long-term demonstration needs to be done. The most harmfull impurities besides sulphur compounds are ethene, benzene, and naphthalene. In designing a feasible biofuel+SOFC combinate optimisation between various items is done. The efficiency of the combinate improves when decreasing the operating temperature and S/C ratio. Also economics are improving because of lower material costs. However, simultaneously the tolerancy of SOFC against impurities decreases. For further more detailed studies following biofuels are suggested: - biogas from anaerobic digestion (sludge from farms and waste water treatment) and

landfill gas - syngas or syngas products methanol, FT diesel, and ammonia - biomass gasification producer gas

7 Acknowledgements At VTT the help of colleagues Matti Noponen, Matias Halinen, Anja Aarva, Tuula Mäkinen, Päivi Aakko, Pauliina Uusi-Penttilä, Pirkko Vesterinen, Pekka Simell, Matti Reinikainen, Ilkka Hannula, Paterson McKeough, and Yrjö Solantausta are acknowledged. At HUT thanks are due to Andrea Gutierrez and Reetta Kaila.


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Project no. 019739

LARGE-SOFC


Part 2: Biogas cleaning and reforming in

SOFC systems

Towards a Large SOFC Power Plant, LARGE-SOFC Contract 019739

Deliverable D6.15

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Contents

1 Introduction 4

2 Properties of Biogas (ADG / LFG) 4

3 Biogas for SOFC 9

3.1 Cannock (UK) Landfill Gas (LFG)[2] 10 3.2 Review on LFG clean up 13

3.2.1 Sulphur and Chlorine clean up from Anoka’s (US)[5] LFG 13

3.2.2 Methods to Clean the Landfill Gas 15

3.2.3 Removal of Siloxanes and VOCs from LFG 18

3.2.4 Impurities removal from LFG by Activated Carbons 20

3.2.5 Operation of Fuel Cells with LFG feed – Results from simulation 24

3.2.6 Summary 30 3.3 ADG Clean up: Biochemical method 32

3.3.1 Biogas Composition: Profactor, Austria [10] 32

3.3.2 Upgrading of Biogas 33 3.4 ADG Clean up: Cologne-Rodenkirchen, Germany[18] 41

3.4.1 Purification of Sewage Sludge 41

3.4.2 Biogas Composition 43

3.4.3 Digester gas Cleaning 44

3.4.4 Composition of Cleaned Biogas 46 3.5 Review summary 48 3.6 LFG and ADG clean up 50 3.7 Conclusions 55 3.8 LFG/ADG References 56

4 Biomass Gasification: Producer / Syn Gas (SNG) 58

4.1 Types of Gasifier 60 4.2 Gas composition and clean up 61

4.2.1 OLGA clean-up system 65

4.2.2 NOVEL gasifier, Finland 66 4.3 Producer Gas: Fuel processing 67

4.3.1 Producer gas: thermodynamic modelling 68

4.3.2 Optimal gasification process 71

4.3.3 Optimal methanation reactor 71

4.3.4 Producer gas clean up 73 4.4 Conclusions 74 4.5 Producer/Syn gas References 75


Deliverable D6.15

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1 Introduction

This work provides a detailed overview about the fuel clean up challenges that should be

addressed when using biogas for power generation by means of a SOFC. Typical biogas

composition and relevant clean up technologies are discussed and presented in the form of:

comparative tables, from fuel quality to impurity removal efficiency, data collection and a

review of the state of the art technology for biogas clean up, including examples from existing

power plants operating with SOFC technology. Particular emphasis has been given to three

type of biogases, namely: Landfill, Anaerobic Digester and Producer Gas. Design of the

optimal clean up process for these biogases is also advised.

Results from this report aim to provide the criteria to industry for selection of the optimal

clean up technology and further processing of biogas for an internal reforming SOFC (250

kW).

2 Properties of Biogas (ADG / LFG)

Biogas occurs widely in nature. Biogas forms wherever organic material accrues under

exclusion of oxygen (called anaerobic digestion), e.g. in bogs, on the bottom of lakes or in

ruminants’ stomachs.

The organic matter is almost entirely converted into biogas in these conditions. The actual

process by which biogas forms involves the complex interaction of various micro-organisms

and, basically, takes place in four separate phases, as shown in Fig. 2.1.

The first stage of decomposition in methane producing fermentation is the liquefaction phase,

which splits long chain organic compounds (e.g. fats, carbohydrates) into simpler organic

compounds (e.g. amino acids, fatty acids, sugars) through bacterial action.

The products of hydrolysis are subsequently metabolised in the acidification phase

(acidogenesis) by acidogenic bacteria and broken down into short chain fatty acids (e.g.

acetic, propionic and butyric acid). Acetate, hydrogen and carbon dioxide are also created and

act as initial products for methane formation.


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In the acetic acid phase (acetogenesis), the organic acids and alcohols are broken down into

acetic acid, hydrogen and carbon dioxide. These products act as a substrate for methanogenic

micro-organisms.

In the fourth and finale phase, during which methane is formed (methanogenesis), the

products from the previous phases are converted into methane by methanogenic micro-

organisms (archaea).

The end product of fermentation is the combustible biogas that is averagely composed as

illustrated in Table 2.1.

Figure 2.1: Simplified diagram of how organic matter is broken down during biogas production


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Biogas production can therefore take place in a Landfill site, to give Landfill Gas (LFG), or in

an anaerobic digester (ADG). The gas is a mixture comprising principally methane and

carbon dioxide.

The energy content of the biogas is directly dependent on the methane content. The higher the

content of substances such as fats and starch that are easy to break down in the fermented

mass, the greater the gas yield.

One cubic metre (m3) of methane has an energy content of about ten kilowatt hours

(9.97kWh). E.g., if the biogas contains 60 % methane, then the energy value of one cubic

metre of biogas is about six kilowatt hours. In this case, the heating value of one cubic metre

of biogas is roughly 0.6 litres of heating oil.

Component Anaerobic Digester Landfill Gas

CH4 55-80 % 30-55 %

CO2 20-45 % 35-45 %

N2 - 0-20 % *

O2 - 0-5 % *

H2O 1 % 1 %

Ammonia NH3 0-50 mg/m3 0-10 mg/m3

Sulphur 100-2000 mg/m3 100-1000 mg/m3

VOC 0-200 mg/m3 0-200 mg/m3

Halogens 0-100 mg/m3 0-100 mg/m3

Siloxanes 0-50 mg/m3 0-50 mg/m3

* the concentration depends on the gas recovery system

Table 2.1: Typical composition of Digester Biogas (ADG) and Landfill Gas (LFG) [1]


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As the proportion of carbon dioxide increases and methane decreases, the fuel becomes more

difficult to ignite. At ratio 3:1 of CO2 ignition can no longer be maintained. The amount of

power produced within the SOFC from Biogas is reasonable at methane contents as low as

15% whereas the methane content requirement for conventional heat engines is around 45 %.

In principle High Temperature Fuel Cells offer the possibility of using Biogas that is depleted

in methane, utilising gas that is difficult to ignite and therefore useless in traditional energy

production systems. Gases with low methane content can be used in Fuel Cells after

upgrading by using CO2 instead of water as source of oxygen for producing H2/CO by

reforming.

One of the main limitations of Biogas in many applications concern its variable composition

according to both geographical location and time. For instance, the methane content from a

single digester can vary by +/- 10%. As a result, the Fuel Cell is typically operated at less than

full output in order to avoid shut-downs associated with decreases in methane content.

Normally, Biogas produced by the digestion of organic materials in waste disposal sites and

sewage treatment plants has to be collected and combusted. Since it contains about 50–65%

by volume methane this process yields energy. The major non-methane constituent of biogas

is carbon dioxide with a typical concentration of 30%. Landfill gas may further contain

nitrogen and oxygen, which are indicative of air incursion into the gas collection system.

Oxygen concentrations are monitored continuously and held low for safety reasons.

Apart from the main components above mentioned, landfill gas and sewage gas contain a

variety of trace compounds. More than 140 substances have been identified so far and they

may reach a total concentration of up to 2000 mg/m3 (0.15 vol.%).

When biogas is used as a fuel for electricity generation by SOFC, such trace compounds may

damage or hamper the normal operation of the power unit.

Specific contaminants to biogas utilization are hydrogen sulphide, halides and silicon

containing compounds, as indicated in Table 2.1.

However, it's very difficult to establish a standard method for biogas clean-up due to the

substantial differences on type of contaminants and their concentrations within the gas stream.

Hereafter, an indicative summary of the principal contaminant classes is shown:


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1. Organic compounds, saturated and unsaturated, having a molecular weight greater

than methane and essentially insoluble in water (VOC).

2. Organic alcohols and acid hydrocarbons, mostly soluble in water.

3. Aromatic hydrocarbons.

4. Halogenated hydrocarbons (primarily chlorinated hydrocarbons).

5. Sulphur compounds, such as hydrogen sulphide (H2S), carbonyl sulphide (COS),

carbon disulphide (CS2) and Mercaptans (R-SH).

6. Inorganic compounds (as siloxanes), inerts, and other compounds not falling into any

of the above categories.

The next chapter of this report will highlight the effect of contaminants on high temperature

fuel cells when LFG or ADG are employed as fuel for power generation. Furthermore, typical

biogas clean-up methods are being illustrated as a result of an extensive survey on biogas

treatment plants.


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3 Biogas for SOFC

Biogas can be used for all applications designed for natural gas, assuming sufficient purification.

On-site, stationary biogas applications generally have fewer gas processing requirements. A

summary of potential biogas utilization technologies and their gas processing requirements are

given in Table 3.1 .

Table 3.1: Biogas utilization technologies and gas processing requirements

Technologies such as boilers and Stirling engines have the least stringent gas processing

requirements because of their external combustion configurations. Internal combustion engines

and microturbines are the next most tolerant to contaminants. Fuel cells are generally less tolerant

to contaminants due to the potential for catalytic poisoning. Upgrading to natural-gas quality

usually requires expensive and complex processing and must be done when injection into a

natural-gas pipeline or production of vehicle fuel is desired.


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Due to the different amount and typology of contaminants which can be present within a

biogas stream, the detrimental effects of a specific impurity on fuel cell efficiency are often

unclear if not unknown. However, it is common practice to investigate the cell behaviour by

feeding the system with a “model” gas as close in composition as the “real” one; with this

view, the poisoning effect of a specific impurity is being studied by establishing some

empirical relationships between its concentration and the fuel cell’s power loss over time.

Hereafter, two different research studies are reported on the modelling and investigation of a

biogas-fed SOFC system for power generation.

3.1 Cannock (UK) Landfill Gas (LFG)[2]

Experimental tests have been carried out in order to study the effect of one of the major

contaminants in LFG, namely Hydrogen Sulfide, H2S. The experimental system is sketched in

Figure 3.1.

Figure 3.1: Experimental System for Testing a Small Tubular SOFC on Cannock Landfill Gas

Analysis by chromatography showed that the Cannock Landfill Gas is mainly a mixture of

CH4, CO2, and N2 (Table 3.2).


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Component Level

Nitrogen 18%

Methane 56%

Carbon Dioxide 26%

Hydrogen sulphide < 1%

Table 3.2: Composition of Cannock Landfill Gas

With no pre-treatment the power output of the cell declined due to poisoning by the small

quantity of hydrogen sulphide within the gas. The effect is shown in Figure 3.2.

Figure 3.2: Power Output against time of Cannock Landfill Gas

To demonstrate that the hydrogen sulphide is the cause of the decline, some tests have been

carried out with Sulphur-free Landfill Gas. The desulphurisation process consisted on

bubbling the gas through a 5% solution of sodium carbonate. The effects are reported in

Figure 3.3.


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Figure 3.3: The Effect of Desulphurisation on Cannock Landfill Gas

These test have confirmed the evidence that desulphurisation greatly reduced the cell power

loss. So this step is very important when treating Biogas for Fuel Cells use.

Moreover, an air reforming was used to increase the power. The effect is shown in Figure 3.4.

Figure 3.4: Desulphurisation and Air Reforming of Cannock landfill Gas


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3.2 Review on LFG clean up

The National Renewable Energy Laboratory (NREL), as part of the U.S. Department of

Energy, is the United States’ primary laboratory for renewable energy and energy efficiency

research and development. NREL took an interest in Landfill Gas because it is a significant

fuel resource both in the United States and world wide. The emissions of Landfill Gas from

existing landfills have become an environmental liability contributing to global warming and

causing odours problems. The Landfill Gas has been used to fuel reciprocating engineers and

gas turbines and may also be used to fuel cells.

3.2.1 Sulphur and Chlorine clean up from Anoka’s (US)[5] LFG

The Landfill Gas consists primarily of methane and carbon dioxide. It contains also water

vapour, traces of organic compounds, which result from solvents, propellants and materials

deposited in the landfill, nitrogen and small amounts of oxygen. In the Table 3.3 is shown a

typical composition of Landfill Gas and the composition of Anoka Landfill Gas. The specific

contaminants are showed in Table 3.4 .

Table 3.3: Typical LFG and Anoka’s LFG compositions


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Table 3.4: Landfill Gas Contaminants at two sites :Penrose (L.A., California) and Anoka (Minnesota)

As shown in the Table 3.3, the amount of contaminants varies. A typical Landfill Gas consists

of 49% methane, 39.5% carbon dioxide, 1.5% water vapour, 9% nitrogen, 0.9% oxygen and

some trace compounds such as sulphur compounds and chlorinated hydrocarbons. The

contaminants must be removed; otherwise they could cause unacceptable products of


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combustion, pollution of the environment and corrosion of gas treating process equipment.

Besides, if the Landfill Gas is used in the Fuel Cells, the sulphur compounds and the

chlorinated hydrocarbons have a detrimental effect on catalysts used in the fuel cell power

plant.

3.2.2 Methods to Clean the Landfill Gas

The chemical methods, used by NREL, to remove organic compounds are:

- Adsorption using carbon beds, PSA/TSA;

- Absorption using solvents such as methanol, Selexol, liquid CO2;

- Carbon (COS is not removed);

- Refrigeration to condense organic compounds.

The chemical methods, used by NREL, to remove sulphur compounds are:

- Iron oxide such as SulfaTreat;

- Acid gas removal (such as MEA and DEA among others).

MCFC Contaminant Tolerances

If the Landfill Gas is used as a fuel for MCFC, the maximum allowed concentrations for H2S

and HCl are < 100 ppbv for both. The problem of these components is that when they react

the fuel cell’s performance is reduced. In general, the sulphur reacts with nickel catalyst:

xH2S + Ni → NiSx + xH2 (Reac. 3.1)

While the chlorides, more than reacts with nickel catalyst, can react with potassium carbonate

electrolyte:

2HCl + K2CO3 → 2KCl(v) + H2O + CO2 (Reac. 3.2)

Sometimes also the oxygen can oxidize nickel catalyst, so its tolerance level is approximate

0.2% vol. Table 3.5 shows the amount of these contaminants in the raw Landfill Gas of

Anoka.


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Table 3.5: Contaminants Concentration in raw Anoka Landfill Gas

If the concentrations of H2S and HCl must be < 100 ppbv, the sulphur is in excess of 99.83%

and the chlorine is in excess of 99.39%. To remove the excess of sulphur there are 3 possible

methods:

- Reaction with a sulphur sorbent;

- conversion of organic sulphur to hydrogen sulphide;

- Reaction with zinc oxide. The reaction is:

ZnO + H2S ↔ ZnS + H2O (Reac. 3.3)

This reaction lowers the concentration of H2S to below 50 ppb as shown in Figure 3.5.

Figure 3.5: Hydrogen Sulphide Equilibrium over Zinc Oxide (1°F = 9/5°C+32)


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To remove the excess of chlorine the low-cost methods are:

• Removal by adsorption onto activated carbon;

• Conversion of organic chlorine to hydrogen chloride by reaction with hydrogen gas;

• Removal of hydrogen chloride by reaction with potassium carbonate.

The entire process of the cleanup is reported in Figure 3.6.

Figure 3.6: Prototype Landfill Gas Cleanup

The raw gas is compressed to 3 atmospheres (absolute) to reduce the vessel size and the costs.

Iron oxide is used to remove the bulk of the hydrogen sulphide and the activated carbon

adsorption is used to remove the bulk high molecular weight chlorinated hydrocarbons. At

elevated temperature, the sulphur compounds and the chloride compounds react with

hydrogen gas. Hydrogen chloride is removed by reaction with potassium carbonate. The

hydrogen sulphide is removed by reaction with zinc oxide.


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3.2.3 Removal of Siloxanes and VOCs from LFG

Siloxanes are a family of man-made organic compounds that contain oxygen and methyl

groups. Siloxanes are used in the manufacture of personal hygene, health care and industrial

products. As a consequence of their widespread use, siloxanes are found in wastewater and in

solid waste deposited in landfills.

At wastewater treatment plants and landfills, low molecular weight siloxanes volatilize into

digester gas and landfill gas. When this gas is combusted to generate power (such as in gas

turbines, boilers or internal combustion engines), siloxanes are converted to silicon dioxide

(SiO2), which can deposit in the combustion and/or exhaust stages of the equipment. In high

temperatures fuel cell applications there is some uncertainty regarding the concentration limit

of siloxanes, which should be kept below 100 ppbv according to one fuel cell manufacturer

[6].

In a recent experimental study, Haga et al. [7] have investigated the poisoning of SOFC

anodes by various fuel impurities, including sulphur, chlorine and siloxanes. Particularly, the

authors observed cell voltage loss upon feeding the anode with a gas (mainly H2 with 3% of

water) stream containing just 10 ppm of Decamethylcyclopentasiloxane (D5) , as shown in

Figure 3.7.

Figure 3.7 : Cell voltage poisoned by 10 ppm siloxane (D5)


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The authors concluded their study by stating that cell voltages decrease gradually with time,

and at each operational temperature, poisoning by siloxane resulted in a fatal degradation of

cell performance. Such degradation is associated with the formation of SiO2 in porous cermet

anodes. Moreover, a larger amount of SiO2 was precipitated near the top surface of the porous

anode, while a small amount of SiO2 was also located within the porous anode layer.

Many removal technologies have been developed in order to remove siloxanes from gas

streams; these include refrigeration, liquid absorption, silica gel and activated carbons to

name a few.

Activated Carbon (AC) has been widely used for the removal of a variety of substances from

air and gas for decades, which makes clean up by adsorption on this material quite a

consolidated technology. Common activated carbon (including coconut shell and graphite)

could adsorb approximately 1 to 1.5 percent siloxanes by weight or 10,000 to 15,000 mg

siloxanes per kilogram of carbon (here the adsorption capacity is defined as the point where

siloxane breakthrough can be detected). On the other hand, the effective capacity of carbon

(and silica gels) can be affected by the presence of moisture in the gas stream. More

generally, activated carbon’s uptake of siloxane is affected by several factors including:

• Siloxane speciation (the relative concentration of the various forms of siloxane that are

present); the lighter, straight molecular forms, particularly L2, breakthrough sooner

than the heavier, cyclic molecular forms. A gas with no or little L2 would have a

greater chance to be cleaned by AC than a gas having more L2.

• The presence of other compounds in the gas that may compete with siloxane for

activated carbon “pore space”; LFG and ADG contain a number of compounds, other

than siloxanes, that activated carbon will remove, including H2S and a group of

compounds known as volatile organic compounds. Generally, VOC in LFG have

greater concentration than in ADG, while the opposite is true for H2S.

• Gas physical condition (moisture content, temperature and relative humidity); AC

perform better on a dry, cool/warm gas than on a wet, hot gas. Biogas processing

schemes that incorporate a refrigeration-based moisture removal process prior to

adsorption on AC should be expected to experience longer carbon life.


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• Activated Carbon type; for instance, impregnated activated carbon can remove ten

times as much hydrogen sulphide (H2S) than un-impregnated activated carbon. Alkali

impregnated carbon can be used as first contact layer in a vessel where biogas is

polished from hydrogen sulphide;

As can be inferred by the above discussion, the siloxanes adsorption capacity has the potential

to vary greatly from site to site. Based on available information on landfill gas composition,

adsorption capacity of activated carbon can vary substantially and different routes can be

followed for optimal clean-up technology. Further discussion is presented in the next section.

3.2.4 Impurities removal from LFG by Activated Carbons

Desirable attributes for a gas purification system include low capital and operating costs, ease of

operation and media disposal, and minimal material and energy inputs. H2S and other impurities

removal processes will be divided into dry-based, liquid-based, physical-solvent, membrane,

alternative, and biological processes for this summary. Media disposal costs are not discussed

here but very well may be the most significant costs for a project.

Adsorbents rely on physical adsorption of a gas-phase particle onto a solid surface, rather than

chemical transformation. High porosity and large surface areas are desirable characteristics,

enabling more physical area for adsorption to occur. Media eventually becomes saturated and

must be replaced or regenerated. If regeneration of the media is economical or desirable, it can be

achieved by using one of the processes described in Table 3.6 below. During regeneration, H2S

rich gas is released and must be exhausted appropriately or subjected to another process for sulfur

recovery.


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Table 3.6: Processes for adsorbent regeneration

The most employed adsorbents employed in industry for purification processes are Molecular

Sieves (Zeolites) and Activated Carbons.

Zeolites are naturally occurring or synthetic silicates with extremely uniform pore sizes and

dimensions and are especially useful for dehydration or purification of gas streams. Polar

compounds, such as water, H2S, SO

2, NH

3, carbonyl sulfide, and mercaptans, are very strongly

adsorbed and can be removed from such non-polar systems as methane. About 40 different zeolite

structures have been discovered and properties of the four most common ones are described in the

Table 3.7 .

Table 3.7: Basic types of commercial molecular sieves


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Adsorption preference, from high to low, is: H2O, mercaptans, H

2S, and CO

2. Not all

mercaptans are adsorbable on type 4A or 5A molecular sieves because of pore size

limitations. Consequently, 13X is preferred for complete sulfur removal from natural-gas

streams. Because contaminants are essentially competing for the same active adsorption spots,

a graphical representation of multiple adsorption zones in a molecular sieve bed might occur

as in Figure 3.8 .

Figure 3.8: Adsorption zones in a MS bed, adsorbing both water vapour and mercaptans from natural gas

However, due to their selectivity and cost, Molecular Sieves are the less advised materials

when adsorbents for removing a high number of impurities from a gas stream are searched.

Alternatively, Granular activated carbon (GAC) is a preferred method for removal of volatile

organic compounds (VOC) from industrial gas streams. Heating carbon-containing materials

to drive off volatile components forms GAC’s, which have a highly porous adsorptive

surface. AC have high selectivity for VOC in the presence of moisture. Typical VOC that can

be removed from a gas stream by AC include ether, methyl, ethyl, isopropyl, buthyl and other

alchols; chlorinated hydrocarbons such as carbon tetrachloride, ethylene dichloride and


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propylene dichloride; esters, acetone and other ketones; aromatic hydrocarbons such as

benzene, toluene and xylene; carbon disulfide and carbonyl sulfide.

Utilization of GAC’s for removal of H2S has been limited to removing small amounts, and

primarily from drinking water. If H2S is the selected contaminant to be removed, GAC’s

impregnated with alkaline or oxide coatings are utilized. In fact, coating GAC’s with alkaline

or oxide solids enhance the physical adsorptive characteristics of the carbon with chemical

reaction. Sodium hydroxide, sodium carbonate, potassium hydroxide (KOH), potassium

iodide, and metal oxides are the most common coatings employed.

Distributors of impregnated activated carbon include Calgon Carbon Corporation (Type

FCA®

carbon), Molecular Products, Ltd. (Sofnocarb KC®

), US Filter-Westates, and Bay

Products, Inc. Typically, 20-25% loading by weight of H2S can be achieved, which is up from

10% as seen with regular GAC.

An example of particular interest was the use of a non-regenerable KOH-activated-carbon bed

(Westates) for removal of H2S from anaerobic-digester and landfill gas for use in a fuel cell.

Oxygen (0.3-0.5% by volume) was added to facilitate conversion of H2S to elemental sulfur.

Two beds, 0.6 m in diameter by 1.5 m high, were piped in series and run with space velocities

of 5300/hr. Inlet H2S concentration ranged from 0.7-50 ppm, averaging 24.1 ppm, and 98+%

removal was demonstrated. A loading capacity of 0.51 g S/g carbon was reported, which is

substantially greater than the normally reported range of 0.15 - 0.35 g S/g carbon for KOH-

carbon. Media costs were estimated at $5/kg for the adsorbent [8].

A further proof of the high scavenging potential of Activated Carbons, is provided by the

siloxanes purification system employed at a landfill site in Italy.

Biogas produced at the landfill site in Corteolona (IT) is obtained by anaerobic digestion of

two different materials: the landfilled solid wastes and a mixture of sludge and straw. Since

the biogas stream is used as fuel for an IC electricity generator, it is of fundamental

importance to provide both siloxanes and sulphur-free feed to the power generator. The clean

up process is based on passive adsorption of biogas impurities by employing two columns

(each column volume is 22 m3) in series and packed with Activated Carbons (see Table 3.8

for specs.).


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Table 3.8 : Specifications of AC used at Corteolona (IT) landfill site

The first of the two columns allows for the removal of most of impurities in the gas stream:

here, competition between species (i.e. H2S and siloxanes) as well as their relative

concentration make the bed life shorter than the second; however, while sulphur and cyclic

siloxanes (type D) are succesfully trapped in the first AC bed, linear siloxanes (type L) sweep

away from the first column to be completely adsorbed in the second. In fact, tests on the

effective capacity of retention for siloxanes species have confirmed the higher saturation

values for cyclic siloxane species (Dsat = 160 kggas / kgAC) in respect to linear siloxanes (Lsat =

135 kggas / kgAC) [9].

3.2.5 Operation of Fuel Cells with LFG feed – Results from simulation

Fuel cell testing was conducted using simulated Landfill Gas composition typical of the

Anoka site. Major gas components without contaminants were used in this test. It was used a

32kW Carbonate Fuel Cell Stack, composed of 68 cells and 9 reforming units. The

compositions of fuel and oxidant used in this test are reported in Table 3.9.


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Table 3.9: Simulated LFG Composition

And the simulated fuel cell performance is shown in Figure 3.9.


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Figure 3.9: Fuel Cell Performance using Anoka LFG

The performance of the cell was good. The stack operated at the endurance conditions for 525

hours. Polarisation curves of LFG and Natural Gas are shown in Figure 3.9. The performance

with Landfill Gas is worse than the performance with Natural Gas.


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Figure 3.9: 32 kW Stack Test on Landfill Gas compared to Natural Gas

After these tests, NREL executed some experiments to understand if it is possible to increase

the tolerance of chlorides and sulphides. For example, if the tolerance of chlorides is 300 ppb,

the beginning of life (BOL) electrolyte reduces of 2%, as shown in Figure 3.10.

Figure 3.10: Carbonate Electrolyte Loss caused by Chloride in the Feed Streams


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To assess this increase in tolerance level for sulphur and chloride contaminants in Landfill

Gas, two bench scale single cells (250 cm2) were operated with simulated landfill gas which

has been contaminated with these compounds. One cell was contaminated with

dichlorobenzene to provide an equivalent 300 ppb Cl in the fuel gas. A second cell was

contaminated with dichlorobenzene and hydrogen sulphide. Both cells were tested on

standard gases to benchmark performance and were found to have normal initial performance

and resistance. Simulated landfill gas and contaminants were introduced to the cells after

operating the cells for several hundred hours to stabilize performance.

The first Landfill Gas contaminant test with 300 ppb Chlorides as dichlorobenzene operated

approximately 1600 hours. Originally planned to operate for 2000 hours, this test was

terminated early due to carbon formation. The performance is shown in Figure 3.11.

Figure 3.11: Single Cell Test on simulated Landfill Gas with 300 ppb Chloride Contaminant

The performance began to decline in the last 200 hours.

The second Landfill Gas contaminant test with 300 ppb dichlorobenzene and 300 ppb H2S

operated for 3000 hours. The performance is shown in Figure 3.12.


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Figure 3.12: Single Cell Test on simulated Landfill Gas with 300 ppb Cl and 300 ppb H2S

The performance began to decline after about 1500 hours.

Comparing the performance of these cells to other cells tested without contaminants, indicates

that the performance obtained with the 300 ppb Cl and H2S contaminants falls within the

scatter of standard cell performance tests conducted in the past. It is difficult to conclude that

the 300 ppb level of contaminants tested will lead to excessive performance decay without

further testing to establish a statistical data base. The anode and the cathode current collectors

were analyzed by metallographic to determinate the effect of contaminants on corrosion. In

addition, the internal reforming catalyst was analysed. The electrolyte was washed first using

ultra-pure water and analyzed. The solid residue was completely digested for similar analysis.

The results of metallographic analysis of the anode and the cathode current collectors are

show in Figure 3.13.


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Figure 3.13: Post Test of Anode and Cathode

There is not an accelerated corrosion of the current collectors for both cells tested.

While these results are encouraging in terms of allowing higher tolerance levels for future

operation of carbonate fuel cells on Landfill Gas with Cl and H2S contaminants at 300 ppb,

additional long term tests are required to confirm these results and to establish a broader

statistical data base.

The effect of sulphur on the internal reforming catalyst will likely be mitigated by the fact that

a pre-reformer is normally part of the power plant system, and this will provide a guard bed to

the fuel cell. This reactor may need more frequent replacement as it gradually picks up

sulphur.

3.2.6 Summary

The methods used to remove the sulphur in the Landfill Gas were:

- Removal of hydrogen sulphide using a specific iron oxide (SulfaTreat);

- Reaction with sulphur sorbent;

- Conversion of organic sulphur to hydrogen sulphide;

- Reaction with zinc oxide.


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The concentration of sulphur was reduced to < 100 ppbv (60,000 ppbv in the Raw Landfill

Gas).

The methods to remove the chlorine in the Landfill Gas were:

- Removal by adsorption onto activated carbon;

- Conversion of organic chlorine to hydrogen chloride by reaction with hydrogen gas;

- Removal of hydrogen chloride by reaction with potassium carbonate.

The concentration of chloride was reduced to < 100 ppbv (9,000 ppbv in the Raw Landfill

Gas).

Other characteristics of the Landfill Gas to be used in the Fuel Cells:

- In the MCFC the tolerance level of oxygen is approximate 0.2% vol because it can

oxidize nickel catalyst;

- Besides, when the oxygen is present in the Raw Gas, there is a big amount of sulphur

dioxide, and the cleaning is not adequate to reduce the presence of sulphur to 100

ppbv;

- The Raw Gas is compressed to 3 atmospheres (absolute) to reduce the vessel size and

the costs.

NREL did a simulation of the using of Landfill Gas in the MCFC. The performance of the

MCFC with Landfill Gas is lower that the performance with Natural Gas.

The tests to increase the tolerance of chlorides and sulphides were encouraging in terms of

allowing higher tolerance levels for future operation of MCFC with contaminated Landfill

Gas.


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3.3 ADG Clean up: Biochemical method

The Innovative Energy Systems department contributes to the establishment of the usage of

RES in combination with advanced energy conversion technologies on a European level.

The department, has been involved in European RTD-projects, like coordinating EFFECTIVE

and AMONCO, and as RTD performer, in three CRAFT-projects (3A-BIOGAS, ENERDEC

and POLAR), in the field of Biomass anaerobic fermentation, Biogas upgrading and

trigeneration.

3.3.1 Biogas Composition: Profactor, Austria [10]

The typical composition of Biogas from anaerobic digestion is reported in Table 3.10.

Main Components (%) CH4 40 – 70%

CO2 30 – 50%

N2 0 – 20%

O2 0 – 5%

Main Contaminations (ppm) H2S 0 – 2000 ppm

Mercaptanes 0 – 100 ppm

Traces Contamination (mg/m3) Siloxanes 0 – 100 mg/m3

Halogenated HC 0 – 100 mg/m3

Table 3.10: Biogas Composition and Contaminants [11]

The aim of PROFACTOR is to use the Biogas in Fuel Cells. The fuel requirements are

reported in Table 3.11.


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Low Temperature FC High Temperature FC

PEFC AFC PAFC MCFC SOFC

Temperature [°C] 80 100 200 650 800-1000

Gas Components

H2 Fuel Fuel Fuel Fuel Fuel

CH4, CnHm Inert Gas Poison Inert Gas Fuel Fuel

CO2, H2O Diluent Poison Diluent Recycled Diluent

CO Poison

(< 50 ppm) Poison

Poison

(< 500 ppm) Fuel Fuel

H2S, COS Poison Poison Poison

(< 50 ppm)

Poison

(< 0.5 ppm)

Poison

(< 1.0 ppm H2S)

NH3 Poison Fuel Poison Fuel Fuel

Halogens Poison Poison Poison

(< 4 ppm)

Poison

(< 0.1-1.0 ppm)

Poison

(< 1.0 ppm)

Table 3.11: Fuel Cells Feeding Requirements

Biogas must be cleaned to reduce above all the sulphur and siloxane components.

3.3.2 Upgrading of Biogas

The general overview of Biogas upgrading is reported in Figure 3.14.


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Figure 3.14: General Overview of Biogas Upgrading[7]

The components, which could cause problems in the Fuel Cells, have to be removed. For

example the CO2 reduces the energy content; the H2S causes the corrosion is toxic in some

concentrations and produces SO2/SO3 in combustion; the H2O causes the condensation in gas

line and produces acid solutions; the HC-X cause corrosion. Also the moisture, particles,

halogen compounds and siloxanes have to be removed. To remove the moisture following

methods can be used:

- To reduce the gas flow velocity and to allow liquid droplets to condensate in

the vessel walls;

- Filters with high surface area allow further condensation. It also allows

particles removal. In combination with moisture separators removes 99.9% of

the liquids;

- To decrease the dew point of the gas;

- Absorption of liquids with high water affinity (glycols). Regeneration is

required;

- Using some absorbent materials, like silica gel, alumina or molecular sieves.

Regeneration is required.

For H2S removal following methods can be used:

- The biological desulphurisation. In this method the autotrophic organism

consuming CO2 and producing S and SO42-. Besides it is required the addition

of some amount of O2 (2-6%) to reduce H2S level below 50 ppm. In Figures


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3.15, 3.16 and 3.17 are reported the scheme of biological methods and the

equipments for biological cleaning.

Figure 3.15: Design of the Biological H2S Removal Method

Figure 3.16: Biological Biogas Cleaning


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Figure 3.17: Biological Biogas Cleaning – Laboratory test

- This is the combination of water scrubbing and biological desulphurisation. This method has a

high efficiency, lower investment costs, avoids a catalysts and the formation of secondary

contaminants, see Figure 3.18.

Figure 3.18: Biotrickling Filter Concept [11]


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To degrade H2S is used a common bacteria, bacteria genus thiobacillus [10]. Besides, the

energy is obtained by the oxidation of inorganic sulphur substrate:

H2S + 0.5 O2 → S + H2O (Eq. 3.1)

H2S + 2 O2 + 2 OH- → SO4= + 2 H2O (Eq. 3.2)

The results of this cleaning method are reported in Figure 3.19 and Table 3.12. It is clear that

this is a good method to remove the H2S.

Figure 3.19: Results of Biotrickling Filter Concept [11]

Table 3.12: Gas Quality at Inlet and Outlet of the Biotrickling Filter including the specific H2S load at the Biogas

Plant in Kolinany (Slovakia) [12]


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The Biotrickling used in the EFFECTIVE Project is shown in Figure 3.20.

Figure 3.20: The EFFECTIVE way of Biotrickling Filter Concept [11]

By using these methods, the concentration of sulphur reduces (Figure 3.21).

Figure 3.21: The Sulphur Removal[13]


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Also the organic silicon compounds are occasionally present in Biogas and may affect

adversary to Fuel Cells performance. Removal methods for siloxanes with biotrickling filters

are shown in Figures 3.22 and 3.23.

Figure 3.22: Scheme of Biotrickling to remove siloxanes [15]

Figure 3.23: Biotrickling Filter to remove the siloxane [11]


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The adsorption separation of carbon dioxide happens by PSA (Pressure Swing Adsorption).

The PSA system is shown in Figure 3.24, where the activated carbon is in the tube. The

regeneration happens by desorption at 200°C.

Figure 3.24: PSA Systems

The equipment is reported in Figure 3.25.

Figure 3.25: The Adsorption Separation (CarboTech) [14]


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3.4 ADG Clean up: Cologne-Rodenkirchen, Germany[18]

The city of Cologne has four sewage plants which treat sewage of approximately one million

inhabitants as well as local industrial and commercial waste. The Cologne-Rodenkirchen

sewage plant (Figure 3.26) started the operation in 1956 with the sewage system and was

expanded in 1972-1995 to include a biological purification phase.

Figure 3.26: Aerial Photo of Cologne-Rodenkirchen Sewage Plant

3.4.1 Purification of Sewage Sludge

In the purification phase, the mechanical preliminary settling and the sewage from households

and industrial companies is pre-purified with the help of a sieve grill. Accumulated coarse

substances are collected in containers and disposed. The sewage ends up in a follow on

ventilated sandpit for the separation of mineral substances. In the next phase, the sewage is

spread out in a clarification basin. Light floating substances with little density are separated

here.

In addition to dissolved and non-dissolved biologically decomposing substances, sewage

consists of a multitude of micro-organisms which ensure the decomposition of organic freight

in a natural way. Maximum substance turnover is reached in the activating basin (2nd cleaning

phase) by adjusting ideal living conditions (extra oxygen, intermixed) from the bacteria


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derived from the decomposing procedure. By zoning the basin in the ventilated (aerobic) and

non-ventilated (anaerobic) areas, the decomposition of dissolved nitrogen-, carbon- and

combinations can be continued, using metal salt phosphate combinations. In a 3rd cleaning

phase, an almost complete separation of existing phosphate is carried out.

In the post-clarification basin, bio-sludge is separated from water. After being partly

dehydrated, part of the bio-sludge is put back into the fermentation power as bio-mass which

is constantly growing due to the steady cell increase of the micro-organisms. Further

decomposition of organic substances takes place with the help of methanogenic bacteria, in a

period of 26 days non-ventilated (anaerobic) and at a constant temperature of 39°C

(mesophyll). One of the main products of rotting is digester gas which is a combination of

mainly methane (CH4) and carbon dioxide (CO2) at a ratio of 63 : 37.

In order to obtain complete energetic use of digester gas from the rotting process, a gas motor

decentralized combined power plant is typically used. A phosphoric acid fuel cell has been

used for the first time in Europe instead of conventional internal combustion engines. The

plant of the project is reported in Figure 3.27.

Figure 3.27: Schematic Overview of the Fuel Cell Plant with Digester Gas

As showed, there are 5 modules:

• Digester Gas Tank. The scope is to supply the fuel cell with methylated gas;

• Digester Gas Cleaning. The scope is to purify the digester gas;

• Reformer/Converter. The scope is to produce a hydrogen rich gas;


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• Fuel Cell. The scope is to generate heat and electricity;

• DC/AC Converter. The scope is to change the voltage.

3.4.2 Biogas Composition

The filthy gas accumulated in the fermentation power of the sewage plant is called Raw Gas

(Table 3.13). It is completely unsuitable to be used by the fuel cell before cleaning.

Table 3.13: Composition of Digester Gas (Raw Gas)

Figure 3.28 shows the emission levels of Raw Biogas before the gas cleaning phase.


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Figure 3.28: Concentration of Raw Biogas (4readings)

3.4.3 Digester gas Cleaning

The digester gas produced is brought to the next step in the cleaning process. Even the

slightest amounts of undesirable organic combinations, like silicon compound, sulphur and

halogen, can considerably hinder the efficiency of the fuel cell catalyst and cause its

destruction. They are removed in this step: the cleaning device consists of a 2-step basic

cleaning unit and a follow-on adsorption level with a particle filter. The Figure 3.29 shows the

journey of raw gas through the cleaning device.


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Figure 3.29: Process Plan of Gas Cleaning device with Heat Exchange

Cooling System

The refrigeration technical device consists of a 2-step basic cleaning unit. The processed gas

is chilled at a temperature of -30°C. Condensation and ice formation occur due to the moisture

contained in the device. Ice absorbs organic silicon. Siloxanes are organic silicon compounds

which crystallize from the formation of SiO2 (quartz) in the fuel area of gas engines and can

cause destruction. As a precaution, gaseous organic silicon was removed as there was not

sufficient experience in dealing with it within the electrochemical processes at the time of

constructing the device.

Periodic thawing phases are necessary to filter out harmful substances and the water load of

ice. The system has two parallel refrigeration sections which can be thawed reciprocally. The

resulting amount of condensation depends on the saturation temperature, outdoor temperature

and the location of the device.

The resulting warm gas is pre-cooled when returned with cold refined gas via a recuperator.


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The necessary temperature level for cold refined gas can be raised at the same time using a

special gas guide. The advantage of this technology is based on a reduction in the energy

requirement for the whole cleaning plant by almost 45%.

A refined gas returning device is installed to prevent ice formation in the area of energy

recycling. This can be controlled as required with a built-in compressor. Taking these

measures into account, a continuous cleaning operation of the refrigeration device is carried

out. Thermal energy, removed from the digester gas during the refrigeration process, can be

drawn off to the surrounding area via a used water cooler. The cleaning devices energy

requirement is particularly low with an efficiency level of 3.5 kW.

Due to economic reasons, the manufacturer has resorted to a standardized device which

corresponds with the general regulations of technology.

Activated carbon phase (adsorption phase) has two parallel filter sections where halogen and

sulphur compositions can be substantially removed using activated carbon. To ensure the

most effective use of activated carbon, each filter section has two filter units with a series of

switches. Maximum loading capacity is achieved in each filter using the switching.

Continuous operation is guaranteed even when the activated carbon has to be exchanged. It is

not possible to perform with full cleaning efficiency shortly after the filter has been changed.

Filtering at the end of the process, there is an additional particle filter which removes all of

the particles larger than 0.5 micrometers from the gas.

3.4.4 Composition of Cleaned Biogas

In order to check that the Biogas cleaning plant was operating faultlessly, readings were taken

of Raw Gas before (Table 3.14) and after (Table 3.15).


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Table 3.14: Composition of Raw Biogas

Table 3.15: Composition of Refined Biogas

Four gas samples were taken before and after cleaning. Maximum level of siloxanes in Raw

Biogas was 3.7 mg/m³. Increasing levels of siloxanes are due to the high usage of detergents

(anti-foam agents) and growing demand for cosmetics (carrier materials). Siloxanes develop

silicon dioxide (SiO2) when burned in the gas room with the help of oxygen. Resulting

crystals are continuously added to the burning room which causes a decrease in efficiency or

can lead to the destruction of the plant. Siloxanes were successfully removed from Raw Gas

except for the sample on 11.14.00. Organic silicon, with a maximum level of 1.4 mg/m³ in

raw gas, was completely removed after the cleaning process.

There is a considerable removal of hydrogen sulphide and sulphur emissions in the digester

gas cleaning plant. Although there were maximum 40 mg/m³ of sulphur and 43 mg/m³ of


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hydrogen sulphide in Raw Gas, these substances were undetectable in Refined Gas. Quality of

Refined Gas confirmed the excellent cleaning capacity of the plant. No emission levels were

recorded in refined gas at the end of the cleaning phase apart from the slightest levels of

organic silicon. Plant construction guarantees that the process engineering pollution limits

necessary will be adhered to. Positive operational results show that, with sufficient gas

cleaning, it is possible to use biogenetic gases in the fuel cell.

3.5 Review summary

This first part of review was focussed on the different methods to treat the Biogas (LFG and

ADG) before its use in high temperature Fuel Cells.

First of all, five Biogas Compositions are analysed. In the Table 3.16 the characteristics of

these Biogas are showed up.

Biogas Farm CH4 CO2 H2S

Cannock (U.K.) 56 % 26 % < 1 %

Lully (Switzerland) 63 % 35 % 1-2 ppm

Anoka (U.S.A.)* 52.2 % 38.1 % 60 ppm

Profactor (Austria) 40-70 % 30.50 % 0-2000 ppm

Cologne-Rodenkirchen (Germany) 55 % < 45 % < 6 mg/m3

Table 3.16 Biogas Composition [* it contains also 8.36 ppm of Chlorine]

Generally the Hydrogen Sulphide reacts with some components and reduces the Fuel Cell’s

performance, so it must be removed. In industry different methods, to reduce its

concentration, exist. In the Table 3.17 the methods to reduce H2S and their efficiency are

testified.


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Biogas Farm H2S Before Methods to Remove H2S H2S After

Cannock (U.K.) < 1 % To bubble the gas through a 5%

solution of Sodium Carbonate

Lully (Switzerland) 1-2 ppm The concentration is low

Anoka (U.S.A.)

60 ppm

Using a specific Iron Oxide

To react with Sulphur Sorbent

To react with Zinc Oxide

< 100 ppbv

Profactor (Austria) 0-2000 ppm Biological desulphurisation

Biotrickling filter

1 ppm

Cologne-Rodenkirchen

(Germany)

< 6 mg/m3 Activated Carbon < 1 mg/m3

Table 3.17 Methods to Remove H2S

The Anoka Landfill Gas had to be also treated to remove the Chlorine. There were used

different methods like removal by adsorption onto activated carbon, conversion of organic

chlorine to hydrogen chloride by reaction with hydrogen gas or removal of hydrogen chloride

by reaction with potassium carbonate. After these treatments, Biogas was used in the Fuel

Cells. In the Table 3.18 is reported in what type of Fuel Cells these Biogas or Landfill Gas are

used.

Biogas Farm SOFC MCFC Other

Cannock (U.K.) X

Lully (Switzerland) X

Anoka (U.S.A.)* X

Profactor (Austria) X X

Cologne-Rodenkirchen (Germany) X

Table 3.18 Where the Biogas/Landfill Gas is used


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The tests prove that the performance of Biogas, after the appropriate cleaning, is good.

3.6 LFG and ADG clean up

In this section, details for biogas treatment and clean up are provided according to an

estimated average gas composition, as shown in Tables 3.19 and 3.20:

LANDFILL Gas Composition CH4 50% CO2 38% N2+O2 9% H2O 3% H2 - MW, kg/kmol 27.8 Density, kg/m3 1.11 Flowrate (250kW SOFC), kmol/s 0.00125 Flowrate (250kW SOFC), Nm3/h 114 Yearly Requirement (250kw SOFC), kg 1098504

Table 3.19 : LFG average composition and consumption for a 250 kW SOFC

ADG Gas Composition CH4 63% CO2 35% N2+O2 0.50% H2O - H2 1.50% MW, kg/kmol 25.7 Density, kg/m3 1 Flowrate (250kw SOFC), kmol/s 0.00098 Flowrate (250kw SOFC), Nm3/h 91 Yearly Requirement (250kw SOFC),kg 797160

Table 3.20 : ADG average composition and consumption for a 250 kW SOFC


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In the above tables, the total amount of biogas required for a 250 kW SOFC operation is

indicated: the yearly flowrate has been calculated accordingly to biogas composition by a

conservative estimation of the fuel cell efficiency.

Since for both Landfill and Anaerobic Digestion the biogas properties and composition may

vary substantially, as well as their impurities content, the main aim of this work is to provide

the best removal technology according to average values, which have been extrapolated by

carrying out an extensive literature survey and data collection. The following tables, Table

3.21 and 3.22, summarize four categories of impurities that are present in both LFG and

ADG:

LFG Impurities mg/m3 kg/year

Sulphur (H2S) 150 150 VOC 1000 1000 Halogenated HC 10 9.98 Siloxanes (50% type D+ 50% type L) 30 15

Table 3.21 : Average LFG impurities content

ADG Impurities mg/m3 kg/year

Sulphur (H2S) 1500 1195 VOC 10 8 Halogenated HC 0 - Siloxanes (50% type D+ 50% typeL) 10 8

Table 3.22 : Average ADG impurities content

It is worth to stress again that the approach here proposed as optimal clean up process should

hold for those cases where LFG and ADG impurity content is likely to fall within the

categories shown in the above tables. In fact, specific case studies may exist, such as the

Anolka Landfill, where LFG clean up involved high energy and resources consumption in

order to remove a particularly high concentration of sulphur and chlorinated compounds; on

the other hand, biogas produced by Lully’s farm in Switzerland shows only a limited amount

of sulphur, thus not requiring any sort of polishing process.

Therefore, we found that dry adsorption by specific adsorbents will provide the best

scavenging option for those gases with multiple poisoning species to be removed.

Particularly, Activated Carbons are flexible and cheap; moreover, because of the relatively


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small amount of impurities in both types of biogas, the disposal option for spent carbons is a

such a cost effective operation that should be preferred to the classic two-columns set up with

regeneration cycle (TSA).

Figure 3.30 : Two adsorption columns are required to selectively adsorb biogas impurities

Since competition during adsorption process is likely to occur among gas impurities, a

polishing set up involving two columns in series is sought as the optimal option for a

complete scavenging process, Figure 3.30.

Table 3.23 summarize the design calculations for both columns for LFG clean up:

LFG Impurities kg/year AC capacity AC Column I [kg/yr] AC Column II [kg/yr]

Sulphur (H2S) 150 10 g/kg 15000 -

VOC 1000 15 g/kg - 67000

Halogenated HC 9.98 0.2% wt AC - 134 (0.2%wt)

Siloxanes 15 D = 1.5% wt AC 225 (1.5%wt) - 15 L = 1.22% wt AC - 817 (1.22%wt) Table 3.23 : Yearly AC requirement for a two column set up employed in the purification of Landfill Gas (LFG)

In Column I, only H2S and D-Siloxanes are not in competition for adsorption on AC sites.

The yearly requirement of AC to remove about 150 kg of hydrogen sulphide has been

LFG

to SOFC

I II

AC AC


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calculated on a conservative estimate; once H2S saturation occurs, 1.5% by weight of the AC

bed is still available for D-siloxanes adsorption. That is Activated Carbons are still capable to

adsorb the yearly amount (15 kg) of D-siloxanes before H2S breakthrough.

The second adsorption column, Column II, has been designed in order to offer the maximum

uptake capacity for the larger impurity level in the LFG stream, that is VOC. Saturation of the

adsorption bed is reached yearly by consuming 67t of AC, while 0.2% and 1.22% of its

weight offers enough capacity to remove both the yearly amount of Halogenated HC and L-

siloxanes, that is 9.98 and 15 kg respectively.

Should the LFG stream be water saturated, then the removal efficiency of both the adsorption

columns would drop substantially; in such case, a common technique would employ a gas

refrigeration step prior to feeding the gas to the first column, thus removing the excess water

content down to a few percent as well as any condensable siloxane compounds. The

refrigeration step do not affect the design of both columns, as the calculations have been

based on H2S and VOC concentration in the gas.

Purification of Anaerobic Digestion Gas requires the introduction of a bulk desulphurisation

step because of the relatively high concentration, see Table 3.23, of H2S. Dry adsorption by

means of adsorption columns is still the preferred removal technique, however the choice of

selective adsorbents is mandatory in order to deliver process feasibility. Table 3.24 shows the

typical H2S adsorption capacities for three commercial adsorbents.

Bulk Sulphur Removal S uptake[g/kg] Notes KOH or NaOH-Activated Carbons 150-350 Dry gas Media G2 (Iron Oxide) 560 Non Hazardous waste; Regeneration;

Demonstrated only at pilot scale Sulfatreat (Iron Oxide) 550-720 Water saturation, Disposal costs;

Non Regenerable Table 3.24 : Candidate adsorbents for Bulk Sulphur Removal step in ADG purification

Although the maximum Sulphur uptake exhibited by KOH based AC is almost 50% less than

the Iron oxide based counterpart, the impregnated activated carbons have the advantage to be

relatively cheap and capable to provide an environmentally safe operation; in fact, once

saturated, KOH-AC can be disposed as hazardous waste without further treatment.


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Whilst Media G2 sulphur removal and regeneration capability and operation cost has been

only demonstrated both at pilot and lab scale level, Sulfatreat is reportedly easier to handle

than iron sponge (iron oxide mineral), thus reducing operation costs, labour for change out

and pressure drops in the bed. Also, Sulfatreat claims to be non-pyrophoric when exposed to

air and thus does not pose a safety hazard during change out.

Drawbacks associated with this product are similar to iron sponge: the process is non-

regenerable, chemically intensive, and spent product can be problematic or expensive to

dispose properly.

A two column in series process, likewise the LFG set up, is required for complete removal of

ADG impurities, Figure 3.31, which may compete to fill the active sites of the adsorbent

material.

Figure 3.31 : ADG purification by means of two adsorption columns

Bulk desulphurisation is operated by means of Column I, that is filled with KOH impregnated

active carbons; the same column is also responsible for D type Siloxanes removal. Column II

is an Activated Carbons adsorption column, that is responsible for purifying the gas stream

from the remaining impurities, namely VOC and L type Siloxanes. Yearly requirement of

both adsorbents are summarised in Table 3.25 .

I II

KOH AC

AC

ADG

to SOFC


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ADG Impurities kg/year KOH Capacity AC Capacity KOH-AC Column I AC Column II

[kg/year] [kg/year]

Sulphur (H2S) 1195 100 g/kg - 11950 -

VOC 8 - 15 g/kg - 533

-

Siloxanes

4 (D) D=1.5% wt 179 (1.5% wt) 6.50 (1.22 % wt)

4 (L) L=1.22% wt

Table 3.25 : Yearly KOH-AC and AC requirement for ADG purification process

3.7 Conclusions

Results achieved on LFG and ADG clean up can be summarized as follows:

• Data collection and literature review work was carried out in order to highlight the

main contaminants composition in two different type of gases, namely: Landfill,

Anaerobic Digester. These can be summarized into four categories: Sulphur

compounds, VOCs, Halogens and Inorganic compounds such as Siloxanes. Optimal

polishing methods for each biogas type have been discussed and comparative tables

were produced.

• Adsorption of one or more contaminants over a fixed bed of specific adsorbents was

selected as the best clean up technology, which requires coupling with other unit

operations when the level of impurities is particularly high. In order to support this

choice, a number of examples of existing biogas plants were reported as well as the

relevant purification methods.

• Activated Carbons are the optimal choice for adsorption of a number of impurities also

because they are a cost effective and flexible technology. Regeneration or safe

disposal do not affect negatively on the overall energy and cost balance of the plant.

According to each biogas composition, the yearly biogas requirement for a 250 kW SOFC

was calculated. Moreover, for a low/moderate level of impurities, a two adsorption columns

set up was designed and the yearly change over of adsorbent material was calculated.


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3.8 LFG/ADG References

[1] Bio-Fuel for SOFC – 25.11.2005 Final – Anja Oasmaa

[2] J.Staniforth, K. Kendall – “Cannock landfill gas powering a small tubular solid oxide fuel

cell – a case study” – Journal of Power Sources 86 (2000) 401 – 403

[3] J.Van herle, Y. Membrez, O. Bucheli – “Biogas as a fuel source for SOFC co-generators” –

Journal of Power Sources 127 (2004) 300 – 312

[4] J.Van herle, F. Maréchal, S. Leuenberger, Y. Membrez, O. Bucheli, D. Favrat – “Process

flow model of solid oxide fuel cell system supplied with sewage biogas” – Journal of Power

Sources 131 (2004) 127 – 141

[5] G. Steinfeld and R. Sanderson – “Landfill Gas Cleanup for Carbonate Fuel Cell Power

Generazion, Final Report” – Energy Research Corporation – Danbury, Connecticut –

February 1998 – NREL/SR-570-26037

[6] E. Wheless and J. Pierce– “Siloxanes in Landfill and Digester Gas” – SWANA Landfill gas

Symposium, March 2002

[7] K. Haga, S. Adachi, Y. Shiratori, K. Itoh, K. Sasaki – “Poisoning of SOFC anodes by

various fuel impurities” – Solid State Ionics 179 (2008) , 1427-1431

[8] S. Zicari – “Removal of Hydrogen Sulfide from Biogas Using Cow Manure Compost” –

MS Thesis, Cornell University, 2003

[9] I. Bozzano – “Purificazione di Gas da Discarica Tramite Adsorbimento su Carboni Attivi”-

Thesis, UNIGE, 2009

[10] AMONCO: REPORT OF THE FIRST BUSINESS INTEREST GROUP (BIG)

MEETING – Dipl.-Ing. Dr. Günter R. Simader – Vienna, April 2004


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[11] Hydrogen sulphide and siloxane removal from biogad for its usage in fuel cells – W.

Ahrer, F.Accettola, S. Trogisch, E. Herrero – 1st European FC Tech. and Appl. Conference,

Rome 2005

[12] Operation of molten carbonate fuel cells with different biogas sources: A challenging

approach for field trials - S. Trogisch, J. Hoffmann, L. Daza Bertrand - 25 April 2005

[13] The usage of biogas in fuel cell systems – Dr. Paloma Ferreira – CIEMAT-CSIC –

Madrid, Spain

[14] Operation of a pilot plant for the biogas injection in Austria – W- Ahrer, J. Bergmair, N.

Weran - Austria

[15] Siloxane removal from biogas by biofiltration: biodegradation studies – F. Accettola,

G.M. Guebitz and R. Schoeftner - 3 February 2007

[16] Potential applications and synergies of biogas fuel cells as an efficient alternative energy

conversion technology – Steven Trogisch – Vienna, Austria 2004

[17] BIOSOFC-Technologiy Development for Integrated SOFC, Biomass Gasification and

High Temperature Gas Cleaning – Achievements – J. E. Hustad, Ø. Skreiberg, T. Slungaard,

D. Stanghelle, A. Norheim, O. K. Sønjo, H. Hofbauer, R. Rauch, A. Grausam, A. Vik, I.

Wærnhus, J. Byrknes.

[18] Digester Gas – Fuel Cell – Project, Final Report for the U.S. Department of Energy – Dr.

Eng. Dirk Adolph, Dipl. Eng. Thomas Saure - March 2002


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4 Biomass Gasification: Producer / Syn Gas (SNG)

Gasification is a thermal conversion process – as is combustion – in which both heat and a

combustible product gas are produced. One method of gasification, referred to as “partial

oxidation,” is very similar to combustion except that it occurs with insufficient oxygen supply

for complete combustion to occur. In a second method, the biomass is indirectly heated in the

absence of oxygen or air, with steam as the oxidizing agent.

The product gas is either a medium-energy content gas referred to as “synthetic gas” or

“syngas” or a low-energy content gas often referred to as “producer gas”, as shown in Table

4.1. Syngas consists primarily of carbon monoxide and hydrogen. Higher quality syngas can

be produced by indirect heating or by using pure oxygen as the oxidizing agent (“oxygen-

blowing”). Producer gas results if air is used as the oxidizing agent (“air-blowing”), which

dilutes the combustible components of the gas with nitrogen. Generally, producer gas is

adequate for power generation and avoids the energy use associated with oxygen production.

Syngas is required for chemical production.

Table 4.1 : Typical energy content of Producer Gas, SNG and NG [1].

The product gas can be burned in conventional boilers, furnaces, engines and turbines, or co-

fired with natural gas, with minor modifications to conventional equipment. Since both

producer gas and syngas have lower heating values than propane or natural gas, enlarging

orifices and adjusting control settings may be required. The product gas can also be used in

solid-fuel boilers as a reburn fuel that is injected into the boiler.

The product gas is primarily composed of carbon monoxide and hydrogen, and if air is used

as the oxidizing agent, nitrogen. The product gas will also have smaller quantities of carbon

dioxide, methane, water and other contaminants, such as tars, char, and ash. The percentages

of each of these components depends on a number of parameters, including the temperature

and pressure of gasification, feedstock characteristics and moisture content, and whether air or

oxygen with or without steam is used for the process. Significant methane is only produced at

high temperatures. More char is produced at lower temperatures, below about 700°C

(1300°F), with a corresponding decrease in energy content of the product gas.


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An important advantage of gasification compared to combustion is its potential to achieve

higher efficiencies and lower emissions. Generating a gaseous fuel makes the use of

reciprocating engines, gas turbines and fuel cells possible in the generation of electricity. Gas

turbines, fuel cells and engines are more efficient electrical generation technologies than the

steam cycle to which solid biomass is limited. The efficiency of a biomass-fired steam turbine

system is between 20% and 25%. In comparison, syngas-fueled engines and turbines can

achieve system efficiencies in the range of 30% to 40%, with higher efficiencies possible in

integrated combined cycles.

In considering overall efficiency, it is important to examine losses in the gasification process

itself in converting biomass to the product gas in addition to improved electrical efficiency. If

the chars and tars that result in gasification are reburned and the heat of gasification is

recovered, high conversion efficiencies can be achieved.

Combustion, gasification and pyrolysis are three thermal conversion processes by which

energy is obtained from biomass. Distinctions between these three processes are summarized

in Tables 4.2 and 4.3. In short, combustion occurs with sufficient oxygen to completely

oxidize the fuel, i.e. convert all carbon to carbon dioxide, all hydrogen to water, and all the

sulfur to sulfur dioxide. Gasification occurs with insufficient oxygen or with steam such that

complete oxidation does not occur. Pyrolysis occurs in the absence of an oxidizing agent (air,

oxygen, or steam). As an intermediate process between combustion and pyrolysis, gasification

is sometimes referred to as “partial oxidization” and sometimes as “partial pyrolysis.”

Gasification, combustion and pyrolysis each have advantages and disadvantages. In any

particular project, it is important to evaluate the goal of the project, the biomass resources

available, and particular needs of the facility in choosing a thermal conversion process [1].


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Table 4.2 : Comparison of combustion, gasification and pyrolysis. *In stoichiometric combustion, air supply is the theoretical quantity necessary to completely oxidize the fuel. For cellulosic biomass, the stoichiometric air supply is 2.5 to 3 kg of air per kg of biomass [1].

Table 4.3 : Predominant components of products from Fast Pyrolysis and Gasification. 1Updraft gasifiers produce 10 to 20% tar, while tar content from downdraft gasifiers is low. 2Downdraft gasifiers produce 20% or more char, while char content from updraft gasifiers is low [1].

4.1 Types of Gasifier

Types of gasifier currently used in biomass gasification include fixed-bed, fluidized-bed and

indirectly heated steam gasifiers. Characteristics of these types of gasifiers are summarized in

Table 4.4. Other types of gasifiers, include entrained bed, plasma arc, and super-critical water

gasifiers. Within these general classifications, there are many different designs that have been

developed. For examples of a number of fluidized bed gasifiers refer to “Combustion and

Gasification in Fluidized Beds” [2].


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Table 4.4 : Summary of selected biomass gasifier types [1].

4.2 Gas composition and clean up

Gas composition and energy content , Table 4.5 and Figure 4.2 respectively, depend on

oxygenation medium (air/oxygen), and also mode of heat transfer (directly with oxygen or

indirectly with hot solids). Figure 4.1 shows different gasifier types for biomass gasification

using air.

Figure 4.1 : Fixed bed, updraft and downdraft respectively, and circulated fluid-bed gasification process


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Figure 4.2 : Energy content of producer gas in fixed bed gasification

Table 4.5 : Composition of coal and biomass derived gases obtained by fluid- bed gasification

Coal and biomass have very different properties and each presents different challenges and

advantages. There is much more experience gasifying coal than gasifying biomass and

conventional designs for coal have often been troublesome when used with 100% biomass.

Compared to coal, biomass fuels have varying chemical content, so each type of biomass

must be considered separately. But several generalizations can be made. Sulfur and ash is

typically lower in biomass, but alkali metal content and silica content, which lead to slagging,

is often greater in biomass. Volatile matter is generally much greater in biomass. At the low

end, volatile matter comprises only about 5% of anthracite coal, while wood contains more

than 75%. Therefore, wood is more easily converted to gas and produces less char but more

tar. Efficient use of char within the gasifier is more important in coal gasification.

Table 4.6 compares typical characteristics of biomass to those of coal.


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Table 4.6 : Biomass characteristics as compared to coal

Thorough gas cleaning and perfect adaptation of the gas from biomass gasification to the

specific requirements of the gas utilisation systems are the prerequisites for gas use in gas

fired engines, gas turbines and fuel cells. Tar compounds can be removed effectively by

increasing the gas temperature or by catalytic tar cracking with dolomite or nickel. However,

even for wood gasifiers there is still no economically viable solution of the tar problem. None

of the gasifier types currently on the market have been successfully tested in connection to gas

fired engines in long term operation under practical conditions in CHP power stations.

Many issues and potential difficulties exist in the integration of a biomass gasifier with a fuel

cell. The most notable of these difficulties is the quality of the fuel gas provided to the fuel

cell. Fuel gas may contain many different contaminants that may poison fuel cell catalysts.

Known contaminants include chlorine, sulphur, arsenic, selenium, zinc, lead and tars. High

concentrations of chlorine may be evident in biomass fuels, particularly fast growing biomass

(such as switchgrass). The chlorine is typically tied up as salts in the biomass but may be

found in the producer gas as potassium chloride, sodium chloride or hydrogen chloride. In any

case, chlorine compounds will need to be removed to <0.1 ppm for long term operation

without detrimental effects to the fuel cell catalyst. Biomass typically has very little sulphur.

However, sulphur concentrations >0.5 ppm wiil be detrimental to fuel cell operation. Sulphur

in the producer gas will most likely be in the form of hydrogen sulphide. It is not likely that

there will be arsenic, selenium, zinc or lead in the vapour phase due to their low volatility at

gasifier temperatures. On the other hand, tars may be problematic as they form a soot layer on

fuel cell catalyst. It has been experimentally measured that concentrations <1% by volume of

light hydrocarbons may be acceptable. However, fluidized bed gasifiers typically generate 4-

8% condensable tars.


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As summarized in Table 4.4, gas produced from downdraft biomass gasifiers typically does

not have high tar content. In fact, downdraft gasifiers were developed specifically to minimize

tar. In contrast, gas obtained from gasification by updraft gasifiers can contain about 100

times more tar than that of downdraft gasifiers. Fluidized bed gasifiers can produce low tar

content product gas, largely depending on the bed material, as discussed below. Typical tar

contents of gas produced by gasifier type are shown in Table 4.7.

Table 4.7 : Typical tar and particulate contents of gasifier types

In addition to gasifier type, feedstock strongly influences tar content of the product gas.

Woody biomass in particular results in high tar content gas. Agricultural and food wastes tend

to have lower tar contents.

The requirement for tar removal depends on the end use of the producer/syn gas. Burners

have higher tolerance for tar than engines, which in turn have higher tolerance than turbines,

as shown in Table 4.8.

Table 4.8 : Tolerance of end-use devices for tar*

In general, tar is removed from the product gas by either chemical or physical methods.

Chemical methods are catalytic cracking, thermal cracking, plasma reactors and use of

catalytic beds. Physical methods are: cyclones, filters, electrostatic precipitators and

scrubbers.


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Using physical methods, sticky particles such as tars are usually collected in a liquid, as in a

scrubber or in a cyclone, bag filter or electrostatic filter whose collecting surfaces are

continually coated with a film of flowing liquid.

In fluidized bed gasifiers, the bed materials can serve as a catalyst for tar reduction. Clay-

derived materials, including activated clay, acidified bentonite, and clay housebrick, have

worked well for this purpose. Ordinary clay housebrick captures more than twice that by sand.

On the other hand, some bed materials – notably dolomite and limestone, but not magnesite –

will recarbonate during cool down, which results in fouling and deposits will occur in

different locations in the gasifier system and in downstream systems.

4.2.1 OLGA clean-up system

Several manufacturers are in the process of developing or have developed proprietary tar

removal systems. For example the OLGA system developed by ECN and marketed by

Dahlman, which uses organic solvents to remove tars [3]. In the design of the OLGA the

liquid tar collection and the gaseous tar absorption are performed in two separate scrubbing

columns. Although, both processes could be performed in a single scrubber unit, separation in

two sections is preferred because of process operation considerations. The liquid tars are

separated from the scrubbing liquid and returned to the gasifier, also a small amount of the

scrubbing liquid is bleed and recycled to the gasifier. For the absorption step, scrubbing

columns were selected that are interacting with each other in a classical absorption-

regeneration mode.

Compared to alternative conventional tar removal systems, the specific investment costs for

relatively small OLGA unit are relatively high, as shown in Figure 4.3 . However, the scale-

up factor of OLGA is relatively low, as this system is based on easily scalable technology and

does not become more complex upon scaling-up.

Figure 4.3 : OLGA - Specific investment costs determined by the gas flowrate [3]


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4.2.2 NOVEL gasifier, Finland

Condens Oy and VTT have developed a new type of fixed bed gasifier, which is based on

forced fuel flow and consequently allows the use of low bulk density (of the order of 150/200

kg/m3) fibrous biomass residues. Condens Oy is offering the Novel technology both for heat

alone and combined power and heat applications. The gas cleaning train based on VTT's

catalytic gas cleaning know how followed by special wet scrubbing, see Figure 4.4, has been

demonstrated in the pilot plant and is efficient enough to allow the use of gas in turbocharged

gas engines.

Figure 4.4 : NOVEL gasification and clean up scheme

Gas cleaning to meet the demands of SOFC may not be economical in small scale (about 1

MWe) in Finland. In countries, where the electricity price is much higher, like Germany and

Austria, the economics may be different. If biomass gasification gas is considered as fuel for

small scale (about 1 MWe) SOFC, the sulphur removal is the most critical task. Sulphur

removal is recommended to be carried out by dry techniques, like use of sorbents. Possibly

the most successful route would be to develop the scrubber technology used in NOVEL

gasification concept. If SOFC technology will accept higher sulphur levels than presently (1

ppm) more gas cleaning techniques may be available. The new NOVEL gasification

technology uses forced fuel feeding making it possible to effectively utilise such biomass

residues and energy crops that cannot otherwise be used without expensive pre-treatment.

Test runs with this new type of gasifier were successfully carried out with various low bulk

density biomass fuels. Reliable operation was achieved even with sawdust and wood

shavings.


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4.3 Producer Gas: Fuel processing

In the next sections, optimal fuel from biomass gasification will be selected as well as the

process conditions required to employ producer gas for a 250 kW SOFC power unit.

Atmospheric pressure operation was chosen over a pressurised system for several reasons.

First, the complexity of pressurised systems is much greater than atmospheric systems,

especially in the feeding of fuel to the gasifier. Furthermore, high temperature pressurised

gasifiers are more dangerous than their counterparts. Finally, pressurised systems are more

costly to construct because of their complexity and the need for additional safety precautions

in their design.

Fuel processing consists of a set of treatments aimed at converting a producer gas stream from

biomass gasification into a gas fit to be used as feed in a fuel cell system. In this work, Rolls-

Royce SOFC (solid oxide fuel cell) with internal reforming made up the generating system.

Therefore, the chosen fuel composition, as obtained from fluid-bed gasification for our

specific case in hand, has to be transformed in a gaseous stream rich in methane that will be

fed and reformed inside the cell. Moreover, the fuel has to be cleaned-up in order to reduce

contaminants concentration to the tolerance limits of the fuel cell and the catalysts used in the

internal reforming; this task will be discussed in Section 5.4 of this report.

Processes known for chemical conversion of the generic hydrocarbon fuel are:

(1) Steam Reforming (SR)

(a) CnHm + nH2O → nCO + (n + m/2)H2

(b) CO + H2O → CO2 + H2 Water Gas Shift (WGS)

The fuel reacts with steam producing hydrogen and carbon monoxide, reaction (a). Steam

reforming is followed by the water gas shift reaction (b), that produces a further mole of

hydrogen. Generally steam reforming is an endothermic process, whereas WGS is an

exothermic reaction.

(2) Partial Oxidation (PO)

CnHm + (n/2)O2 → nCO + (m/2)H2


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The fuel reacts with air producing hydrogen and carbon monoxide. This is an exothermic

reaction.

(3) Autothermal Reforming

2CnHm + (n+m/4)O2 + nH2O → nCO + (n+m/2)H2 + nCO2 + (m/2) H2O

The fuel reacts with a mixture of steam and air. This reaction may be endothermic or

exothermic, depending on quantity of air provided. A convenient offsetting of steam and air

quantities may make the overall process isothermal.

Carbon formation, an undesired side reaction, reduces the conversion of hydrocarbons in the

reforming reactor. Hydrocarbons, when exposed to temperatures superior to 300°C, tend to

dehydrogenate and to produce solid species. The char produced deposits in the active sites of

the catalyst deactivating it; together with an obvious reduction in the overall efficiency. The

possible reactions are the followings:

CnHm ↔ nC + m/2H2

2CO ↔ C + CO2

Carbon deposition may be minimized by working at low temperatures, about 500°C. Steam is

an efficient inhibitor of the coking effect, because, thank to the catalyst, the hydrocarbons

rapidly react with steam producing methane and hydrogen. By operating with a high steam-to-

carbon ratio, char deposition on the catalyst is minimized.

4.3.1 Producer gas: thermodynamic modelling

In this section, a thermodynamic study has been carried out on the different fuel processing

options, with the aim to study the influence of the main process parameters, such as

temperature and gas composition. Particularly, this study will search for optimal equilibrium

conditions by maximizing the methane content in the output stream of a fuel processor.

The basic assumption of the study requires all the reaction to reach thermodynamic

equilibrium; to this aim, a Gibbs reactor has been employed as fuel processing unit in the

simulation, Figure 4.5 . The equilibrium model is based on the following assumptions:

uniform temperature and pressure (atmospheric) are assumed; no information about actual


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reaction pathways/formation of intermediates; no tar, no carbon deposition is modelled; no

information about the rate of reaction.

Producer gas compositions shown in Table 4.5 have been used as model fuel fed to the

reactor; in this regard, fluid-bed gasification has been selected as optimal gasification

technology because of its scalability and low tar productivity.

The target of this simulation is to evaluate the theoretical methane content at equilibrium

between 250 and 500 °C.

Figure 4.5: Sketch of a simulated Gibbs reactor; S3=Input Stream , R1=Gibbs Reactor, S4=Output Stream

• U-Gas

With reference to Table 4.5, the inlet U-Gas composition, S3, is the following:

Table 4.6 : U-Gas composition

Typical results from simulation, Table 4.7 and Figure 4.6, show the molar fraction of reaction

products (i.e. stream S4 in Figure 5.4) at temperatures ranging between 250 and 500 °C.


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Table 4.7 : Molar composition at different temperatures for U-Gas methanation

Figure 4.6 : Graphical trend of molar compositions at different temperatures for U-gas methanation

Note that methane concentration raises up to about 20% because of methanation reaction (4)

at T=250°C; similarly, CO2 concentration increases due to water gas shift reaction (1b).

Furthermore, the low (almost zero) Hydrogen molar fraction could be explained by the

relevant maximization of Methane production.


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4.3.2 Optimal gasification process

In order to establish a comparison chart, the reference equilibrium composition is shown for

different gasification processes in Table 4.8: note that the operative temperature is set at 250

°C as it represents the optimal equilibrium temperature for methane maximization.

Table 4.8 : Comparison table for different gasification technologies after methanation reaction. The Residue

content (not shown in this table) is calculated by overall balance for each type of gas.

Because of the higher methane content produced through methanation reaction, Battelle gas

has been selected as optimal fuel for a SOFC-Power Unit. Therefore, Battelle gas will be

employed in this work as model fuel.

4.3.3 Optimal methanation reactor

Since the equilibrium calculations represent the ideal maximum methane yield (or CO

conversion), the aim of this section is to elucidate which type of methanation reactor will

provide a gas composition that is closer to the equilibrium system.

Methanation, reaction (4), is a well known reaction and most of the thermodynamic data are

readily available in literature. This reaction is usually associated with a Shift reaction, (5),

which make the simplified methanation reaction set as follows:

(4) CO + 3H2 = CH4 + H2O

(5) CO + H2O = CO2 + H2

The equilibrium constants for both reactions being at their maximum at temperatures ranging

between 200 and 250 °C, then decreasing of one order of magnitude by a temperature

increasing step of about 50 °C.

The high exothermicity of methanation is an important factor in considering techniques and

plant for operating process, because if the reaction temperature becomes too high not only is

the equilibrium state of the reaction adversely affected but the catalyst (i.e., Nickel/Alumina)


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life is shortened by sintering of the metal-based particles. On the other hand, operation at high

pressures will substantially enhance the conversion of methane, but care should be taken as

the adiabatic temperature of reaction will also rise with pressure and could pose a significant

risk for catalyst life.

The process can be operated in two basically different ways, however a third option has been

also discussed in this work as a possible process solution:

1. Adiabatic Reactor : the process is operated adiabatically without temperature control,

the maximum temperature depending on the conversion limit; in fact, in the adiabatic

process and due to the exothermic reaction, temperature in the reactor will

substantially increase and thermodynamic equilibrium is readily reached but with only

limited conversion.

2. Isothermal Adiabatic Reactor : in order to achieve high conversions the reaction

temperature must be kept low, i.e. reaction heat must be removed, by process

technique, which includes: product gas recycle (Lurgi), addition of steam, internally

cooled (HaldØr-Topsoe) or tube-wall reactor design, use of a liquid phase heat removal

medium and fluidization. Ideally the reactor should operate at nearly isothermal

conditions and in the temperature range of 200-400 °C.

3. Multi-stage Adiabatic Methanation : a simple system which comprises a series of

adiabatic methanation reactors with intermediate heat exchangers. The application of

such a system is limited to processes at lower pressures, as at higher pressures the

adiabatic temperature of the reactor will rise to a point where catalyst damage might

occur. This option has been here considered and evaluated as biomass gasification is

generally operated at ambient/low pressure condition and so is the fuel cell stack.

Adiabatic, isothermal and multi-stage adiabatic methanation processes have been modelled by

calculating the equilibrium gas composition, temperature and flowrates by means of equations

(4) and (5).


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4.3.4 Producer gas clean up

Producer gas clean up techniques include two main polishing stages: the first stage or pre-

cleaning stage, Figure 4.7, requires the removal of tars, particulates and halides; the amount of

such impurities being strictly related to the type of biomass employed for gasification, gasifier

type and gasification process. The pre-cleaning stage comprises producer gas cooling to an

acceptable temperature (about 140 °C), which is required for particle removal by means of a

Venturi scrubber; after filtering out particulates from the gas stream, the gas is further cooled

down (about 30°C) through wet scrubbing in a packed column: at this stage condensable tars,

ammonia and halides, including HCl (down to a maximum concentration of 100 ppmv), will

be removed.

Producer gas exiting from the pre-cleaning stage will contain mainly sulphur (H2S up to 50

ppmv) and chloride (HCl up to 100 ppmv) impurities. Gas clean up process involves the

selection of the optimal removal technique to scavenge H2S and HCl before the methanation

reactor: particularly, methanation catalysts, which are Nickel based materials, are very

sensitive to sulphur poisoning.

Table 4.8 : Uptake capacities and operative conditions of commercially available sorbents

Producer gas polishing method by physical adsorption has been here selected as optimal

removal technique for H2S and HCl: according to Table 4.8, an adsorption bed of activated

carbons (AC) will remove trace sulphur compounds, that are present in concentrations up to

50 ppmv. Since HCl is poorly adsorbed by activated carbons, a second adsorption column

filled with activated alumina will be employed in series just after the activated carbons

treatment. Activated alumina can remove effectively HCl by passive adsorption, provided that

the HCl concentration does not exceed 100 ppmv. Given the low amount of impurities, spent

sorbents disposal has been preferred to regeneration.

Adsorbent Type T [°C] P [atm] H2S

Capacity HCl

Capacity Notes AC 25 1 1-4 % low H2S uptake: high with P, low with T Alumina, Al2O3 25 1 low 4-7 % HCl uptake: high with T and P Trona, Na based 300-500 1 low 5% Requires high T , direct injection Katalco 59-3 350-500 1 low 4-5% Requires high T ZnO/CaO 350-500 high 22-24% 25% Requires High T, High P, H2 for HDS


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• Producer gas clean up, H2S=50 ppmv and HCl=100 ppmv

In this section, design parameters, have been calculated in order to remove sulphur and

chloride impurities through two adsorption columns in series, as sketched in Figure 4.8.

.

Figure 4.8 : Sketch of sulphur (H2S=50 ppmv) and chloride (HCl=100 ppmv) impurities removal from a Battelle

gas stream. Column I: Activated Carbons; Column II: Activated Alumina

For Battelle gas, composition shown in Table 4.8, containing 50 ppmv of H2S and 100 ppmv

of HCl at ambient temperature and atmospheric pressure, results of a preliminary estimation

for the required amount of adsorbents are reported in Table 4.9.

Battelle Gas Mass Flow 1419120 kg/year

H2S Concentration 50 ppmv HCl Conc. 100 ppmv

H2S Mass Flow 108 kg/year HCl Mass Flow 230 kg/year

AC consumed 10800 kg/year Alumina consumed 32860 kg/year

Column I Volume 22 m^3

Column II Volume 43 m^3

Table 4.9 : Amount of adsorbents required yearly for Battelle gas purification

4.4 Conclusions

Choice of the optimal reactor for Producer gas methanation was investigated, as both landfill

and anaerobic digester biogas are rich in methane. Equilibrium calculations have been carried

out in order to ascertain which gasification technology would provide the best Producer gas

AC Sulphur clean up

<0.1 ppmv

Battelle Gas

Al 2O3

HCl clean up <1 ppmv

I II II Methanation

Pre

-Cle

anin

g

I II


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composition for further methanation. According to such calculations, the Producer gas from

fluid-bed gasification was selected.

Exit gas compositions for an adiabatic, isothermal and multi-stage methanation reactor have

been calculated in order to select the optimal technology that would provide a suitable biogas

for an 250 kW internal reforming SOFC.

Producer/Syn gas clean up was also discussed by distinguishing tar removal technologies

from sulphur and halogen compounds polishing. Hot tar removal is either being demonstrated

only at pilot scale or proved to be a serious issue in the overall plant balance. Cold tar removal

by means of scrubbers and ceramic/sand filters was advised as best option, which should be

followed by adsorption on two columns in series, in order to achieve the removal of trace

sulphur and halogens compounds.

Yearly requirements of adsorbent materials have been calculated for a 250 kW SOFC.

4.5 Producer/Syn gas References

[1] C.J. Roos – “Clean heat and power using biomass gasification for industrial and

agricultural projects.”- WSU Extension Energy Program. Updated July 2009.

[2] P. Basu – ”Combustion and Gasificaton in Fluidized Beds.” CRC Press, Boca Raton, FL,

2006.

[3] H. Boerrigter, S. Van Paasen, P. Bergman, J. Konemann, R. Emmen – “Tar Removal from

Biomass Product Gas; Development and Optimisation of the Olga Tar Removal Technology”-

14th European Biomass Conference & Exhibition, 2005.

report on biofuels for sofc applications part 1

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