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MASTERS THESIS

Department of Applied Physics and Mechanical Engineering

Division of Energy Engineering

M.Sc. in Sustainable Energy Systems

CONTINUATION COURSES

2006:54 PB ISSN: 1653 - 0187 ISRN: LTU - PB - EX - - 06/54 - - SE

2006:54 PB

Diana Carolina Cardenas Barraon

Methanol andHydrogen Production

Energy and Cost Analysis

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MASTER THESIS

METHANOL AND HYDROGEN PRODUCTION:

ENERGY AND COST ANALYSIS.

Diana Carolina Crdenas Barran

Division of Energy Engineering

Depertment of Applied Physics, Mechanical and Material EngineeringLule University of Technology

S-971 87 Lule- Sweden

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Preface

This work has been carried out as a Masters Thesis for the Master of Science Program inMechanical Engineering with focus towards Energy Engineering. The research has been

performed at the Division of Energy, Lule University of Technology, during August 2005through May 2006.

I would like to thank to my supervisors Ph.D. student Sylvain Leduc and Doc. Jan Dahl fortheir great collaboration and support during my research. I would also like to thank all myteachers and classmates for all their help, feedbacks and friendly atmosphere.

I also would like to thank my Father who has been my guide since I have memory and hadbeen my deepest inspiration all this years of studies and work. Finally I will like to thank mydear boyfriend Per for his enormous patience, encouragement and for always being there forme.

Diana Cardenas

Lule May 2006

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Abstract

Methanol and hydrogen produced from biomass are promising carbon neutral fuels. Both are

well suited for use in Fuel Cell Vehicles (FCVs) which are expected to reach highefficiencies, about a factor 2-3 better than current International Combustion Engine Vehicles(ICEVs). In addition they are quiet and clean, emitting none of the air pollutants SOx, NOx,VOS or dust. When methanol and hydrogen are derived from sustainable grown biomass, theoverall energy chain can be greenhouse gas neutral.

Technical and economic prospects of the future production of methanol and hydrogen frombiomass have been evaluated. A technology review, including promising future components,was made resulting in a set of promising conversions concepts. Flowsheeting models weremade to analyse the technical performance in ASPEN PLUS.

Results were used for economic evaluations. Overall energy efficiencies are around 55 %HHV for methanol and around 60 % for hydrogen production.

400 MWth input systems produce biofuels at 9- 12 US$/GJ, this is above the current gasolineproduction price of 4-6 US$/GJ. This cost price is largely dictated by the capital investments.The outcomes for the various systems types are rather comparable, although conceptsfocussing on optimised fuel production with a little or no electricity co-production performsomewhat better. Long term cost reductions reside in cheaper biomass, technological learning,and application of large scale up to 2000 MWth. This could bring the production costs of

biofuels in the 5-7 US$/GJ range. Biomass derived methanol and hydrogen are likely tobecome competitive fuels tomorrow.

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Table of Contents

Page

1. Introduction 5

1.1Background 5

1.1.1Biomass... 6

1.2 Rationale. 8

1.3 Objectives.. 9

1.4 Methodology 9

2. System Description..9

2.1 Production of Biofuels..9

2.1.1Pre-treatment of feedstock.92.1.2Gasification11

2.1.3Gas cleaning..15

2.2 Syngas Processing17

2.2.1 Steam Reforming..17

2.2.2 The water-gas shift reaction18

2.2.3 CO2 removal18

2.3 Methanol production.19

2.4 Hydrogen production.22

2.5 Power generation..24

2.5.1 Gas turbine.25

2.5.2 Heat Recovery Steam Generation (HRSG) .25

3. System Calculations25

3.1Modelling principles..25

3.2 Results29

4. Economics

..30

4.1Method.30

4.2Results.31

5. Discussion and Conclusions...34

6. References35

7. Annexes..40

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1. INTRODUCTION

1.1 Background

The interest risk for climate change is a growing concern for the global society. The thirdassessment report of the intergovernmental panel on climate change (IPCC) provides thestrongest evidence so far that the global warming of the last 50 years is due largely to humanactivity, especially the carbon dioxide (CO2) emissions that arise when fossil fuels are burned(IPCC, 2001a). According to what is known as the Kyoto Protocol, the Conference of theParties (COP) has agreed that by committed period 2008-2012, developed countries shall belegally committed to reduce their collective greenhouse gas (GHG) emissions by at least 5%compared to 1990 levels. Using renewable energy resources to substitute fossil fuels is one ofthe technological options to mitigating GHG emissions.

The use of Biomass as a main energy source has increased since the last decades, (example of

Sweden in Figure 1). The advantages of biomass is that it uses carbon dioxide from theatmosphere to grow, and releases as much carbon dioxide when consumed, it therefore doesnot contribute to climate change by emissions to the atmosphere of carbon dioxide or othergreenhouse gases. Biomass is then considered as a renewable energy resource if the wholecycle of biomass conversion is well managed.

Figure 1. Energy supply in Sweden, excluding net electricity imports, 19702003 (Source: Statistics Sweden,

Swedish Energy Agency processing).

Carbon dioxide from public transportation has been increasing a lot since the past decade.One way to decrease the emissions is to innovate new energy conversion technologies inwhich the fuels for the transportation are carbon dioxide neutral for the atmosphere. How toreduce the increased GHG emissions related to the transportation is a challenging issue.

Fuel cell vehicles are a promising technology for meeting future goals for zero emissions.Other zero emission energy is coming out and starts to be competitive to the fossil fuels:ethanol. In Brazil, ethanol from sugar cane is spreading very quickly. Using biofuels, theemissions of greenhouse gases from the transportation will decrease. Using on the other hand

carbon sequestration when producing these biofuels, one may even decrease the amount ofcarbon dioxide in the atmosphere.

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This report focuses on different fuels, from the woody biomass, for public and individualtransportation, methanol and hydrogen. Focus is pointed on the different technologies of

production and the cost of production of these bio fuels.

1.1.1 Biomass

Biomass is a carbonaceous material of biological origin derived from plants including wood,bark, straw, reeds, and agricultural crops, etc. Biomass energy is obtained directly fromvarious agriculture crops or from raw material from the forest, or is obtained as by-productsfrom the forest industry. Biomass is also recycled from household waste or derived fromrecycled paper and demolition wood. If properly grown and managed, biomass is a renewableenergy resource. It does not contribute to climatic change through emissions to theatmosphere of carbon dioxide or other greenhouse gases because it absorbs the sameamount of carbon in growing as it releases when consumed as fuel. The content of heavymetals in biomass is low, and if the ashes from biomass are recycled to forest and agricultureland, the use of biomass does not imply any major difference to the natural cycle of growth

and decomposition (Yan, 1998).In this report, focus is mainly stressed on woody biomass. Woody biomass or lignocellulosic(FIGURE 2) is composed of carbohydrate polymers (cellulose and hemicellulose), lignin anda remaining smaller part (extractives, acids and salts and minerals) (Hamelinck et al. 2001).

FIGURE 2. Plant Cell Wall Composition (Shlesser, 1994).

Cellulose

Cellulose has the same chemical structure in all types of biomass: a linear carbohydratepolymer with a high degree of polymerization (the average molecular weigh is 100,000).Cellulose chains aggregate into a crystalline structure that gives its mechanical strength.(Katofsky, 1993).

Hemicellulose

Hemicelluloses are mixtures of polysaccharides comprised mainly of glucose, mannose,galactose, xylose, arabinose, methylglucuronic acid and galacturonic acid, and have a lowerdegree of polymerization than cellulose (the molecular weigh is

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Lignin

Lignin is a complex, amorphous, randomly linked, high molecular weight (2,100) (Okuda etal., 2004), ringed structure that helps bind the cellulosic fibers together. Dry wood is typically45-50 % cellulose by weight, 15-25% hemicellulose, and 20-30% lignin (Sudo, et al. 1989).In addition, biomass contains 0.1-2% ash, and even smaller quantities of elements such as

chlorine and sulphur (0.01-0.1%) and alkali metals (mainly potassium and sodium) (Katofsky,1993).

Characteristics of Biomass compared with coal)

On a dry, ash free basis, biomass has a heating value that is roughly 60-70 % that of coal. Aswell, biomass has a lower mass density, higher initial moisture content (40-60% fresh woody

biomass, compared to 2-12 % for most bituminous coals), and is dispersed over a wide area.Because of this initial moisture content, the receiving heating value of biomass is only about30-40 % of the heating value of coal. Even some of the chemical properties of biomass makeit superior to coal in many ways. As seen in TABLE 1, compared to coal, biomass contains

far less inert material (ash) and significantly less sulphur. Biomass ash is usually free of toxicmetals (such as arsenic) and other potentially hazardous materials that can make the disposalof coal ash difficult and complicate syngas processing. Biomass ash can actually be used asfertilizer, to restore nutrients to the land where it was grown (Katofsky, 1993).

The most important difference between biomass and coal is the much higher volatile fractionof biomass. For this reason, biomass is considerably more reactive than coal. Cellulose, themain component of wood, pyrolyses (decomposes) more completely and at lowertemperatures than coal (FIGURE 3). Biomass char, the carbon that remains after pyrolysis, is

10-30 times more reactive than coal char (Graboski, 1981) (FIGURE 3). Biomass chars gasifymore rapidly and at lower temperatures than coal chars. Biomass is easier to gasify than coal

in the sense that lower operating temperatures are required to achieve the same gasificationrates and degree of conversion from solid to gas (Katofsky, 1993)

TABLE 1.Compositional data and heating values for selected types of biomass, coal and natural gas

(Katofsky, 1993).

Feedstocktype

HHV(MJ/kg)

Volatilematter

Fixedcarbon

Ash C H O N S Cl Ash

Douglas fir 20.37 87.3 12.6 0.1 50.64 6.18 43 0.06 0.02 0.00 0.10Maple 18.86 87.9 11.5 0.6 49.89 6.09 43.27 0.14 0.03 0.00 0.58

Ponderosapine

20.02 82.54 17.17 0.29 49.25 5.99 44.36 0.06 0.03 0.01 0.30

White oak 19.42 81.28 17.2 1.52 49.48 5.38 43.13 0.35 0.01 0.04 0.61

Poplar 19.38 82.32 16.35 1.33 48.45 5.85 43.69 0.47 0.01 0.10 1.43Eucalyptus

grandis19.35 82.55 16.93 0.52 48.33 5.89 45.13 0.15 0.01 0.08 0.41

Sugarcanebagasse

17.33 73.78. 14.95 11.27 44.8 5.35 39.55 0.38 0.01 0.12 9.79

Wyomingsubbitumou

s coal26.78 44.68 46.12 9.2 68.75 4.89 15.55 0.89 0.69 0.00 9.24

Illinois no6bituminous

coal26.67 37.5 43.4 18.18 65.34 4.2 6.59 1.02 4.55 0.00 18.3

Natural gas 52.94 71.99 23.78 0.38 3.84 0.00 0.00

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FIGURE 3.Comparison of coal and cellulose pyrolysis (the main component of biomass) (scanned from

Katofsky, 1993).

1.2 Rationale

Methanol and hydrogen can be produced from biomass via gasification. Several routesinvolving conventional, commercial, or advanced technologies, which are under development,are possible. A scheme of the main process steps to convert biomass to methanol and

hydrogen are shown in FIGURE 4.

Shift to adjust

CO/H2 ratio

Pre-treatment:

-drying

-chippingGasifier Gas cleaning

section

Reformer

for higher

hydrocarbons

Methanol

synthesis

H2separation

Methanol

Hydrogen

Gas turbine

Steam

turbine

Electricity

Auxiliaries

Purge gas

steam

Shift to adjust

CO/H2 ratio

Pre-treatment:

-drying

-chippingGasifier Gas cleaning

section

Reformer

for higher

hydrocarbons

Methanol

synthesis

H2separation

Methanol

Hydrogen

Gas turbine

Steam

turbine

Electricity

Auxiliaries

Purge gas

steam

FIGURE 4.Key components in biomass to methanol/hydrogen production concepts. (Hamelinck et al,2001)

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1.3 Objectives

The key objective of this work is to identify biomass to methanol and hydrogen conversionconcepts that may lead to higher overall energy efficiencies and lower costs on longer term.Improved performance may be obtained by:

Combined fuel and power production may lead to lower cost and possibly higheroverall thermal efficiencies because of cheaper reactor capacity and reduction ofinternal energy consumption of the total plant.

Economies of scale; various system analyses have shown that the higher conversionefficiencies and lower unit capital costs that accompany increased scale generallyoutweigh increased energy use and costs for transporting larger quantities of biomass.Furthermore, it should be noted that paper & pulp mills, sugar mills, and otherfacilities operate around the world with equivalent thermal inputs in the range of 1000-2000 MWth. Such a scale could therefore be considered for production of energy/fuelfrom (imported) biomass as well.

1.4 Methodology

The work consists of several steps. First of all a technology assessment on gasifiers, gascleaning, syngas processing and combined cycles will be made to make inventory of possibleconfigurations.Second, promising system configurations were selected for further performance modelling

with help of the flowsheeting program Aspen plus. Aspen plus is used to calculate energy andmass balances.Third and economic evaluation is performed including economies of scale of the units. Finallythe configurations are compared, conclusions drawn and recommendations are formulated.

2. SYSTEM DESCRIPTION

2.1 Production of Biofuels

Syngas, a mixture of CO and H2, is needed to produce methanol or hydrogen. A train ofprocesses to convert biomass to required gas specifications precedes the methanol reactor orhydrogen separation as was shown in Figure 4.

2.1.1 Pre-treatment of feedstock

Biosyngas can be produced from biomass, but it needs a pre-treatment, which may be one ofthe following techniques:

Chipping Drying

Torrefaction Powder

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Chipping

Chipping is generally the first step in biomass preparation. The fuel size necessary forfluidised bed gasification is between 0 and 50 mm (Pierik et al., 1995). The total primaryenergy requirements for chipping woody biomass are approximately 100 kJ/kg of wet

biomass or 0.5 % of the higher heating value (Katofsky 1993).

Drying

The fuel is dried to 15 % or 10% depending on the gasifier applied in order to reduce the heatrequired for the gasification and to reduce the moisture content of the product gas. Dryingconsumes roughly 10% of the energy content of the feedstock. Although the heat ofvaporisation of water is 2,250 kJ/kg, in practice approximately 3,500 kJ is required toevaporate one kg of water (Katofsky 1993).There are two ways for drying, either with steam or with flue gas. Heat in the flue gas thatexist the heat recovery steam generator is used to dry the incoming biomass. Furthermore fluegas drying holds the risk of spontaneous combustion and corrosion (Consonni et al., 1994). It

is not clear whether flue gas or steam drying is a better option in biofuel production. Thespecificities for steam or flue gas drying are shown on TABLE 2.

TABLE 2. Requirements for steam or flue gas drying for a biomass feedstock from 50% moisture to 15-10%

(Pierik and Curvers 1995).

Unit Steam Flue gasTemperature C 200Pressure bar 12Energy use MJ/twe 2.8 2.4 / 3.0Electricity consumption kWh/twe 40 40 - 100

To improve the combustion and transportation properties of the biomass, the forest fuel can beconverted into several other forms, such as charcoal, torrefied wood, pellets, briquettes andwood powder

Torrefaction

Torrefaction is a thermal treatment at a temperature of 200 to 300 C, at near atmosphericpressure and in the absence of oxygen. This mild thermal treatment not only destructs thefibrous structure and tenacity of the biomass (wood), but is also known to increase thecalorific value and to invert the hydrophilic nature. During the process, the biomass partlydevolatilises which leads to a decrease in mass, but the initial energy content of the biomass is

mainly preserved in the solid product (fuel). The latter is of great importance to the overallenergy efficiency of the biomass-to-biosyngas conversion chain. Due to the low moisturecontent of torrefied wood the transport cost is lower and the quality as a fuel better (Bergmanet al., 2004).

Powder

Biomass can be pulverized to particles of 100 mm or less. This however consumes hugeamounts of electric energy.

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2.1.2 Gasification

After pre-treatment, is the conversion into biosyngas by gasification and subsequentlysynthesize the required products. There are different kinds of gasification, such as:

Low temperature gasification, 800 - 1000C: The biosyngas components H2 and COtypically contain only ~50% of the energy in the gas, while the remainder is containedin CH4and higher (aromatic) hydrocarbons.

High temperature gasification, >1200C: All the biomass is completely converted intobiosyngas (Boerrigter et al. 2004).

FIGURE 5 below describes these processes.

FIGURE 5. Two biomass-derived gases via gasification at different temperature levels: biosyngas and product

gas and their typical applications (Boerrigter et al. 2004).

Thermo chemical gasification is the conversion by partial oxidation at elevated temperature ofa carbonaceous feedstock such as biomass or coal into a gaseous energy carrier. In a gasifier,

biomass is converted into gases (H2, CO, CO2, H2O, CH4, light hydrocarbons) andcondensable tars at 800-1,200C. The gas also contains impurities originating from the fuel,like sulphur, nitrogen and chlorine compounds, and alkali metals. The final productdistribution in a gasification gas largely depends on gas-feedstock contact type and processconditions.

Gasification occurs in sequential steps:

Drying, to evaporate moisture. Pyrolysis, to give gas, vaporized tars or oils and a solid char residue. Gasification or partial oxidation of the solid char, pyrolysis tars and pyrolysis

gases.

The different types of gasifiers are the following: Fixed bed gasifiers Fluidised bed gasifiers

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Fixed bed gasifiers

Downdraft gasifier

FIGURE 6. Downdraft

gasifier (Ohlstrm et al.,

2001).

The downdraft gasifier features concurrent flow of gases and solidsthrough a descending packed bed which is supported across aconstriction known as a throat, where most of the gasificationreactions occur. The reaction products are intimately mixed in theturbulent high-temperature region around the throat, which aids tarcracking. Some tar cracking also occurs below the throat on aresidual charcoal bed, where the gasification process is completed.This configuration results in a high conversion of pyrolysisintermediates and hence a relatively clean gas (Bridgwater et al.1995).

Updraft gasifier

FIGURE 7. Updraft

gasifier (Ohlstrm et al.,

2001) .

In the updraft gasifier, the downward-moving biomass is first dried

by the up flowing hot product gas. After drying, the solid fuel ispyrolysed, giving char which continues to move down to begasified. Pyrolysis vapour are carried upward by the up flowing hot

product gas. An advantage, especially of updraft (counter-current)gasifiers, is the high cold gas efficiency connected with the lowsyngas exit temperature. But this advantage is obtained at theexpense of high tar content in the syngas.

Updraft or downdraft gasifiers require mechanically stable fuelpieces of one or few cm size, to guarantee an unblocked passage ofgas through the bed. Straw, hay or paper must be pelleted or

briquetted: This is an expensive procedure, but if it is performeddirectly with a harvester, it could simplify all transport and storageoperations later on. To summarise: Fixed bed gasifiers are wellsuited for stable wood pieces. Fixed bed gasifiers are well suited forstable wood pieces (Henrich et al., 2004).

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Fluidised bed gasifiers

Figure 8. Fluidised bed gasifier (Ohlstrm et al.,

2001).

Fluidised bed gasifiers are operated eitherin the bubbling or the circulating mode,usually with quartz sand as bed materialand fuel particles of few mm up to 1 or fewcm size. For biomass feedstock at least

750C is required, to achieve a reasonablyhigh gasification rate. The bed temperaturemust be kept below the ash softeningtemperature, since a sticky ash would gluetogether the bed particles and thisagglomeration causes a breakdown offluidisation (Henrich et al., 2004).

Circulating bed gasifiers

The fluidising velocity in the circulatingfluid bed is high enough to entrain large

amounts of solids with the product gas.This configuration has been extensivelydeveloped for wood waste conversion in

pulp and paper mills for firing lime andcement kilns and steam-raising forelectricity generation (Bridgwater et al.1995).

Twin fluid bed gasifiers

These are used to give a gas of higher heating value from reaction with air than is obtainedfrom a single air-blown gasifier. The gasifier is a pyrolyser, heated with hot sand from thesecond fluid bed, which is heated by burning the product char in air before recirculation to thefirst reactor. Steam is usually added to encourage the shift reaction to generate hydrogen andto encourage carbon-steam reactions (Bridgwater et al. 1995).

Entrained flow gasifiers

The entrained flow gasifier has been developed mainly for coal feedstock. The entrained flowgasifier operates at high temperature (1,300 C) which is not necessary for biomass with highreactivity. The feedstock must also be crushed to fine-sized particles which is energy and

intensive with biomass (Ohlstrm et al., 2001).Fluidised beds are attractive for biomass gasification. They are able to process a wide varietyof fuels including those of high moisture and small size. They are easily scaled to large sizessuitable for electric power production. Disadvantage of fluidized beds include relatively high

power consumption to move gas through the bed; high exit gas temperatures, whichcomplicate efficient energy recovery; and relatively high particulate burdens in the gas due tothe abrasive forces acting within the fluidized bed (Brown, 2003). Fluidised sand beds aresuited for woods, which have a high ash melting point, usually > 1000C. The ash melting

points of cereal straw however can drop to even below 700C (Henrich et al., 2004).

TABLE 3 shows the different characteristics of some gasifiers, and TABLE 4 the gascomposition form various kind of gasifiers.

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TABLE 3. Typical gasifier characteristics (Bridgewater et al. 1994)

Reaction(C)

Exitgas(C)

Tars Particulates Turn-downScale-upability

Currentcapacitymax (t/h)

MinMWe

MaxMWe

Fixed bed

Downdraft 1000 800 v.low moderate good poor 0.5 0.1 1Updraft 1000 250 v.high Moderate good good 10 1. 10Cross current 900 900 v.high high fair poor 1 0.1 2Fluid bed

Single reactor 850 800 Fair High good good 10 1 20Fast fluid bed 850 850 Low v.high good v.good 20 2 50Circulating bed 850 850 Low v.high good v.good 20 2 100Entrained bed 1000 1000 Low v.high poor good 20 5 100Twin reactor 800 700 High High fair good 10 2 50Moving bed

Multiple hearth 700 600 High low poor good 5 1 10Horizontal movingbed 700 600 High Low fair fair 5 1 10

Sloping hearth 800 700 Low Low poor fair 2 0.5 4Screw /auger kiln 800 700 High low fair fair 2 0.5 4Other

Rotary kiln 800 800 High high poor fair 10 2 30Cyclone reactor 900 900 low v.high poor fair 5 1 10

TABLE 4. Producer gas composition from various kinds of gasifiers (Brown, 2003).

Gaseous Constituents (vol.% dry) Energy content Gas quality

Gasifier Type H2 CO CO2 CH4 N2 HHV (MJ/m3) Tars Dust

Air-blownupdraft

11 24 9 3 53 5.5High

(~10g/m3)Low

Air-blowndowndraft

17 21 13 1 48 5.7 Low(~1 g/m3)

Medium

Air-blownfluidized bed

9 14 20 7 50 5.4Medium

(~10g/m3)High

Oxygen-blowndowndraft

32 48 15 2 3 10.4Low

(~1 g/m3)Low

Indirectly heatedfluidized bed

31 48 0 21 0 17.4Medium

(~10g/m3)High

Processes based on indirect gasification are of interest with regard to methanol synthesis, asthey offer a possibility to produce non-nitrogenous synthesis gas without any investment in arelatively expensive oxygen plant.

In the indirect process, the gasification reactor is heated by hot bed material. The bed materialis heated in a separate combustion unit operated in fluidised-bed principle by burning themixture of residual char and bed material separated form the product gas (Ohlstrm et al.,2001).

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2.1.3 Gas Cleaning

The syngas produced from the gasifier contains different kinds of contaminants: particles,tars, alkali, sulphuric, chloride and nitrogen compounds (Tijmensen 2000). These

contaminants can lower catalyst activity in reformer, shift or methanol reactor, and causecorrosion in gas turbine or heat exchangers. Ash particles cause wear and corrosionthroughout the plant. Particulate concentrations in raw gas from most fluidised bed gasifierscan be as high as 5000 ppmw. Severe gas cleaning is then required. The particulateconcentration needs to be below 1 ppmw at the turbine inlet, with 99% of the particles smallerthan 10 micron. This corresponds to a particulate concentration in the fuel gas before thecombustor of about 3-5 ppmw (Consonni and Larson 1994b).

Gas cleaning has to remove all components that may be harmful to the catalysts or other partsof the plant by corrosion, erosion or fouling. The gas cleaning is preferably operated at thesame temperature of the downstream gas application to minimise efficiency loss by cooling.In general two routes can be distinguished:

Wet low temperature gas cleaning, Dry high temperature gas cleaning.

Wet low temperature gas cleaning

The subsequent cleaning steps are depicted in FIGURE .

FIGURE 9. Low temperature wet gas cleaning (Hamelinck et al., 2001).

A cyclone separator removes most of the solid impurities, down to sizes ofapproximately 5 m (Katofsky 1993).

Before the bag filter the syngas is cooled to just above the water dew point. New generation bag filters made from glass and synthetic fibres have an upper

temperature limit of 260 C (Perry et al. 1987). At this temperature particulates andalkali, which condense on particulates, can successfully be removed (Consonni et al.,

1994; Tijmensen 2000). The syngas is then scrubbed down to 40 C below the water dew point, by means of

water. Residual particulates, vapour phase chemical species (unreacted tars, organicgas condensates, trace elements), reduced halogen gases and reduced nitrogencompounds are removed to a large extend. Alkali removal in a scrubber is essentiallycomplete (Consonni et al., 1994). With less than 30 ppm H2S in the syngas bulkremoval of sulphur compounds is not necessary.

A ZnO bed is sufficient to lower the sulphur concentration below 0.1 ppm. ZnO bedscan be operated between 50 and 400 C, the high-end temperature favours efficientutilisation. At low temperatures and pressures less sulphur is absorbed, thereforemultiple beds will be used in series. The ZnO serves one year and is not regenerated

(Katofsky 1993).

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If CO2 removal is demanded as well, a solvent absorption process will be used likeRectisol or Sulfinol, this unit can also be placed downstream (Tijmensen 2000). H2Sand COS are reduced to less than 0.1 ppm and all or part of the CO 2is separated. Thesulphur in the acid gas output is concentrated to sulphuric acid or reclaimed aselemental sulphur in a Claus unit.

This method will have some energy penalty and requires additional waste water treatment, buton the short term it is more effective than hot dry gas cleaning.

High temperature dry gas cleaning

The subsequent cleaning steps are depicted in FIGURE .

FIGURE 10. High temperature dry gas cleaning (Hamelinck et al., 2001).

As with wet gas cleaning the tar cracker is optional. Possibly present tars and oils are notremoved during the downstream hot gas cleaning units since they do not condense at hightemperatures. It is not clear to what extent tars are removed (Tijmensen 2000).

For particle removal at temperatures above 400 C sliding granular bed filters are usedinstead of cyclones.

Final dust cleaning is done using ceramic candle filters (Hamelinck et al., 2001) orsintered-metal barriers operating at temperatures up to 720 C; collection efficienciesgreater that 99.8 % for 2 7 m particles have been reported (Katofsky 1993). Still

better ceramic filters for simultaneous SOx, NOx and particulate removal are underdevelopment (White et al. 1992). Processes for alkali removal in the 750 900 C range are under development and

expected to be commercialised within few years. Lead and zinc are not removed at thistemperature. High temperature alkali removal by passing the gas stream through afixed bed of sorbent or getter material that preferentially adsorbs alkali via physicaladsorption or chemisorption was discussed by Turn et al. (1998). Below 600 C alkalimetals condense onto particulates and can more easily be removed with filters(Katofsky 1993). Nickel based catalysts have proved to be very efficiency indecomposing tar, ammonia and methane in biomass gasification gas mixtures at about900 C. However sulphur can poison these catalysts (Tijmensen 2000). It is unclear if

the nitrogenous component HCN is removed. It will probably form NOx in a gasturbine (Verschoor et al., 1991).

Halogens are removed by Na and Ca based powdered absorbents. These are injected inthe gas stream and removed in the dedusting stage (Verschoor et al., 1991).

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2.2 Syngas Processing

The syngas produced by the gasification of biomass, consists mainly of H2, CO, CO2 andCH4. Syngas processing consists of three steps, which are all optional.

2.2.1Steam reforming

In the presence of a suitable catalyst (usually nickel based), methane, tars and other lighthydrocarbons are reformed into CO and H2at high temperatures (Katofsky 1993).

Steam reforming is the most common method of producing a synthesis gas from natural gas orgasifier gas. The highly endothermic process takes place over a nickel-based catalyst.Reactions are:

CH4+ H2OCO + 3H2 h=206 MJ/kmol (R1)C2H4+ 2H2O2CO + 4H2 h=210 MJ/kmol (R2)

C2H6+ 2H2O2CO + 5H2 h=347 MJ/kmol (R3)

The water gas shift reaction (Reaction R4) takes place as well, and brings the reformerproduct to chemical equilibrium (Katofsky 1993). Reforming is favoured at lower pressures,but elevated pressures benefit economically (smaller equipment). Reformers typically operateat 1 3.5 MPa.

Steam methane reformer (SMR) uses steam as the conversion reactant and to prevent carbonformation during operation. Tube damage or even rupture can occur when the steam to carbon

ratio is allowed to drop below acceptable limits. The specific type of reforming catalyst used,and the operating temperature and pressure are factors that determine the proper steam tocarbon ratio for a safe, reliable operation.

Typical steam to hydrocarbon-carbon ratios range from 2:1 for natural gas feeds with CO2recycle, to 3:1 for natural gas feeds without CO2recycle, propane, naphtha and butane feeds(King et al., 2000).

Usually full conversion of higher hydrocarbons in the feedstock takes place in an adiabaticpre-reformer. This makes it possible to operate the tubular reformer at a steam to carbon ratioof 2.5. When higher hydrocarbons are still present, the steam to carbon ratio should be higher:3.5. In older plants, where there is only one steam reformer, the steam to carbon ratio wastypically 5.5. A higher steam: carbon ratio favours a higher H2:CO ratio and thus highermethanol production. However more steam must be raised and heated to the reactiontemperature; this decreases the process efficiency. Neither is additional steam necessary to

prevent coking (Katofsky 1993).

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2.2.2 The water-gas shift reaction

In a shift reactor the ratio CO:H2is changed via the water-gas shift reaction:

CO + H2OCO2+ H2 (R4)

This reaction is exothermic and proceeds nearly to completion at low temperatures. Moderncatalysts are active as low as 200 C (Katofsky 1993) or 400 C (Maiya et al. 2000). Due tohigh catalyst selectivity all gases except those involved in the water-gas shift reaction areinert. The reaction is independent of pressure. Conventionally the shift is realised in asuccessive high temperature (360 C) and low temperature (190 C) reactor. Nowadays, theshift section is often simplified by installing only one CO-shift converter operating at mediumtemperature (210 C). To shift as much as possible CO to H2, and profit from the kinetics ofhigh temperatures, the dual shift reactor is applied in the hydrogen production concepts in the

present study. For methanol synthesis, the gas can be shifted partially to a suitable H2:COratio, therefore less than one reactor is applied. The temperature may be higher because thereaction needs not to be complete and this way less process heat is lost. Theoretically thesteam: carbon monoxide ratio could be 2:1. On lab scale good results are achieved with thisratio (Maiya et al. 2000). In practice extra steam is added to prevent coking (Tijmensen 2000);the ratio is set 3:1.

2.2.3 CO

2

removal

To get the ratio (H2-CO2)/(CO +CO2) to the value desired for methanol synthesis, part of the

carbon oxides could be removed. This can be done by partially scrubbing out carbon oxides,most effectively carbon dioxides. For this purpose different physical and chemical processesare available. The various technologies for CO2 removal from gas streams have beendescribed by many authors. A technology overview was made in a previous STS report(Hamelinck et al. 2000 Annex A). Generally a division can be made into:

Chemical absorption Physical absorption Membranes Distillation

The two absorption options are widely applied, and at present the most suitable for applicationto a broad range of CO2containing streams.

Chemical absorption using amines is the most conventional and commercially best-proven option.

Physical absorption, using Selexol, has been developed since the seventies and is aneconomically more attractive technology for gas streams containing higherconcentrations of CO2.

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2.3 Methanol Production

Conventionally, methanol is produced in two-phase systems: the reactants and productsforming the gas phase and the catalyst being the solid phase. Synthetic methanol productionfirst began in 1923 at BASFs Leuna, Germany plant. The process required a high pressure

(250 350 atm) and catalyst selectivity was poor. Processes under development at presentfocus on shifting the equilibrium to the product side to achieve higher conversion per pass.Examples are the gas/solid/solid trickle flow reactor, with a fine adsorbent powder flowingdown a catalyst bed and picking up the produced methanol; and liquid phase methanol

processes where reactants, product, and catalyst are suspended in a liquid. (Hamelinck et al.2001).

Synthesis Gas Conditioning

For optimal production of methanol, three parameters are of particular importance:

a) The ratio of CO2to CO should be optimised for methanol production, similar to the ratio insteam reformed natural gas.

b) The H2:CO ratio of the synthesis gas. The synthesis of methanol is most efficient when thefeed gas contains the correct ratio of components. The ideal gas composition is given by:

22

22 =+

=

COCO

COHR Equation 2-1

c) The concentration of inert materials (e.g. N2, CH4) should be minimised. The CO2/CO ratio

and the stoichiometry number can be adjusted by the water-gas-shift reaction and then CO2removal. If the raw gas from the gasifier contains significant quantities of CH4, steamreforming may also be used, as follows:

CH4+ H2O3H2+ CO (R5)

The water-gas-shift reaction is a catalytic process operating at 200-475 C to convert CO andsteam to H2and CO2, via the reaction:

CO + H2OH2+ CO2 (R6)

For the production of methanol from biomass only partial conversion is required. Excess CO2may then be removed by one of several commercially available processes.

Methanol SynthesisOnce the economic optimum synthesis gas is available the methanol synthesis takes place.This typically uses a copper-zinc catalyst at temperatures of 200-300 C and pressures of 50-100 bar. Only a portion of the CO in the feed gas is converted to methanol in one pass throughthe reactor, due to the low temperature at which the catalyst operates. The unreacted gas is

recycled at a ratio typically between 2.3 and 6 (Hamelinck et al., 2001).

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Methanol is produced from syngas via the following two reactions:

CO+2H2CH3OH h= -90.7 MJ/kmol (R7)CO2+3H2CH3OH+H2O h= -49.5 MJ/kmol (R8)

Methanol synthesis is exothermic, and gives a net decrease in molar volume. A crudemethanol production is condensed out by cooling the product gas of the methanol synthesisreactor, and is then sent to a distillation column (Hamelinck et al, 2001, Ohlstrm et al.,2001).(R7) is the primary methanol synthesis reaction. Since (R8) results in the loss of some of thehydrogen as water, under ideal circumstances there would be no CO2in the feed. However, itis well established that a small amount of CO2in the feed (1-2%) acts as a promoter of the

primary methanol synthesis reaction and helps maintain catalyst activity (Hamelinck et al,2001).Some side reactions are also possible:

2CH3OHCH3OCH3+H2O (dimethyl-ether) (R9)CO + H2CH2O (formaldehyde) (R10)2nH2+nCOCnH2n+1OH + (n-1) H2O (higher alcohols) (R11)

Methanol Purification

The crude methanol from the synthesis loop contains water produced during synthesis as wellas other minor by-products. Purification is achieved in multistage distillation, with thecomplexity of distillation dictated by the final methanol purity required (Schuck, 2002). Thefollowing figure presents a combined production of methanol.

FIGURE 4. Process flow diagram of methanol production.

Optional are a gas turbine or boiler to employ the unconverted gas, and a steam turbine;resulting in electricity co-production.

Pre-

treatment

Gasifier

Gas cleaning

section

Reformer for

higher hydrocarbons

Shift to adjust

CO/H2 ratio

Dried

Wood

Raw

Gas

Clean

Gas

CO, H2

Methanol

production

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Wood based methanol process integrated to CHP

production

The evaluated methanol process is based on oxygen-driven gasification. After the gasificationthe gas is reformed with a catalyst to achieve a maximum conversion of hydrocarbons intogases (CO, H2). Water scrubbing of the gas is needed for removing the remaining condensabletars, solids, and ammonia. In addition, the composition of the gas must be converted by COconversion (shift) units to adjust the stoichiometric ratio in the range required by methanolsynthesis. Sulphur compounds and CO2must be removed with special scrubbing processes. In

principal, all process units presented are commercial technology, although no wood-basedmethanol plants are under operation (Ohlstrm et al., 2001).

FIGURE 5. Methanol production combined to CHP production at a pulp and paper mill. Steam production

and utilisation is combined to a steam cycle of the pulp mill (Ohlstrm et al., 2001).

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2.4 Hydrogen Production

Hydrogen can be combusted or combined with oxygen inside a fuel cell to produce energy.However, hydrogen gas does not occur naturally in large quantities on earth; it must beseparated from other compounds such as water or fuels that contain carbon such as fossil fuels

or biomass. Hydrogen can be produced by two processes from biomass: gasification andpyrolysis.

Hydrogen from gasification

During gasification, the following reaction occurs:

CaHb + a/2O2b/2H2 + aCO (R12)

A variety of secondary reactions such as hydro cracking, steam gasification, hydrocarbon

reforming, and water-gas shift reactions also take place. The feedstock react with oxygenunder severity operating conditions (1,150C -1,425C at 400-1,200 psig). In hydrogenproduction plant, there is an air separation unit (ASU) upstream of the gasifier. Using oxygenrather than air avoids downstream nitrogen removal steps.

In some designs, the gasifiers are injected with steam to moderate operating temperatures andto suppress carbon formation (Simbeck et al. 2002). The hot syngas could be cooled directlywith a water quench at the bottom of the gasifier or indirectly in a waste heat exchanger (oftenreferred to as a syngas cooler) or a combination of the two.

The characteristics of the biomass gasification process are also similar to those of coal

gasification systems, but the biomass gasifier operates at lower temperatures and has differentclean-up requirements (Ogden, 1999).

Steam methane reforming

The gasification step is followed by a similar steam reforming process; a reforming stepwhich converts methane and the higher hydrocarbons in the syngas to hydrogen. Steammethane reforming (SMR) is an endothermic reaction conducted under 30 atm andtemperatures exceeding 870C. Conventional SMR is a fired heater filled with multiple tubesto ensure uniform heat transfer.

CH4 + H2O3H2 + CO (R13)

Commercially, the steam to carbon ratio is between 2 and 3. Higher stoichiometric amounts ofsteam promote higher conversion rates and minimize thermal cracking and coke formation.Because of the high operating temperatures, a considerable amount of heat is available forrecovery from both the reformer exit gas and from the furnace flue gas. A portion of this heatis used to preheat the feed to the reformer and to generate the steam for the reformer.Additional heat is available to produce steam for export or to preheat the combustion air.Methane reforming produces a synthesis gas (syngas) with a 3:1 H2/CO ratio. The H2/COratio decreases to 2:1 for less hydrogen-rich feedstock such as light naphtha. The addition of aCO shift reactor could further increase hydrogen yield from SMR according to Reaction

(R14). CO + H2OH2 + CO2 (R14)

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Shift conversion

The shift conversion may be conducted in either one or two stages operating at threetemperature levels. High temperature (350C) shift utilizes an iron-based catalyst, whereasmedium and low (205C) temperature shifts use a copper based catalyst. Assuming 76% SMRefficiency coupled with CO shift, the hydrogen yield from methane on a volume is 2.4:1.

Hydrogen purification

There are two options for purifying crude hydrogen. Most of the modern plants use multi-bedpressure swing adsorption (PSA) to remove water, methane, CO2, N2, and CO from the shiftreactor to produce a high purity product (99.99%). Alternatively, CO2 could be removed bychemical absorption followed by methanation to convert residual CO2 in the syngas.FIGURE6below shows a block diagram for the production of hydrogen:

FIGURE 6. Block diagram of the process configurations for the production of hydrogen from biomass. PSA=

Pressure Swing Absorption (Katofsky et al, 1993, Komiyama et al., 2001).

Pressure swing absorption (PSA)

Pressure swing absorption (PSA) systems have reached a level of performance such that theycan produce hydrogen with extremely high purity (99.999%) at recovery rates of 90 % orhigher.

In Pressure Swing Adsorption (PSA), molecules are physically bound to a surface at highpressure, and released at low pressure (Katofsky 1993). This technology can be applied forvarious purification purposes, like in hydrogen or oxygen production. Hydrogen purification

Pre-

treatment

Gasifier

Steam methane

reforming

CO Shift

reaction

PSA H2 separation

CO2 removal

Dried

Wood

Raw

Gas

Syngas

Hydrogen

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by adsorption was first performed commercially by Union Carbide Corp. in 1966. Since thenover 400 H2 PSA plans have been installed around the world. Most H2 PSA plants useactivated carbon or zeolite adsorbents or both, sometimes in layers with alumina or otheradsorbents for impurity removal (LaCava et al. 1998).

The adsorption surfaces have to be large and can be selective to particular molecules. Twobasic categories are carbonaceous and zeolitic adsorbents, as extensively described byKatofsky (1993). Zeolites are both naturally occurring and manmade, and are also calledmolecular sieves. Broadly defined, they are silicates of aluminium with alkali metals. Theability of a substance to adsorb a particular gas depends on several factors including pore size,

pore size distribution, void fraction and surface activity. Some zeolites contain metal cations,which can attract certain gas molecules. There are literally hundreds of different types ofzeolites, with pore sizes ranging from 3 to 10 . The size of the gas molecule to be adsorbedis therefore important when selecting which zeolite to use. Macroscopic properties are alsoimportant. Sufficient macroporosity is required to permit rapid diffusion of gases from thesurface of the adsorbent into the microscopic structure. Greater macroporosity also reduces

pressure losses and allows for rapid desorption during bed regeneration.

For hydrogen purification from synthesis gas, two sets of PSA beds are placed in series (FIGURE14). The gas is cooled down to a temperature of about 40C before entering the PSAunit. PSA-A removes all the CO2and H2O, PSA-B removes all residual gasses but 84 % ofthe hydrogen. By recycling 80 % of the liberated gas from PSA-B to PSA-A, the overallhydrogen recovery is above 90 %. The produced hydrogen is extremely pure (99.999%) and isliberated almost at feed pressure. Besides pure hydrogen, also a highly pure CO2stream and acombustible purge gas stream, undiluted by inert compounds, are produced (Katofsky 1993).

FIGURE 14. PSA set up for hydrogen purification (Katofsky 1993)

2.5 Power Generation

The off gas after the methanol or hydrogen production section can still contain a significant

amount of chemical energy. This gas stream may be combusted in a gas turbine, to generateelectricity.

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2.5.1Gas turbine

The gas turbine consists of two distinct parts. First the off gas, at high pressure, is put througha combustor. Adding pressurised air generates a large hot stream, which is expanded soelectricity is generated. Part of the work is used to drive the air compressor. In some cases the

syngas has a caloric value too low for the ensure stable combustion in the combustor. Themass flow will become too large if the standard combustion temperature is to be maintained.

Therefore, a lower combustion temperature is necessary when syngas with a low caloric valueis put through a gas turbine, also adjustments to the gas turbine have to be made (Ree,Oudhuis et al. 1995). This reduction of the gas turbine combustion temperature is called de-rating. Another form of de-rating is raising the pressure of the air put through the turbine.Heavy de-rating has strong impacts on overall performance and economics foe combinedcycles.

Roughly spoken, a syngas with LHV higher than 6 MJ/Nm3can be burned without de-rating,at 1200C and 14 bar. The burner may need modifications if the syngas is lower than 10MJ/Nm3(Walter et al. 1998). Syngas with a caloric value below 5 MJ/Nm3will probably not

be suited for the gas turbine, but this depends on the gas turbine used (LHVs of 2.5 havebeen used in gas turbines).

When a gas turbine is used the exhaust gas carries a large amount of heat. Steam from coolingthe exhaust gas is fed to the Heat Recovery Steam Generation (HRSG). The exhaust gas of thegas turbine cannot be cooled below 170C due to environmental restrains (Faaij 1997). A gasturbine using HRSG is called combined cycle.

2.5.2 Heat recovery steam generation hrsg)

At different places in the whole process cooling down is necessary, e.g. the exhaust gas fromthe gas turbine, the cooling down of the syngas after gasification, etc. Water is pressurised inadvance of the heat exchanger, so high pressure steam is generated. The superheated steam isexpanded in a partly condensing gas turbine to produce electricity. Also, steam required in the

process (drying, gasification, shifting and reforming) can be taken from the HRSG at differentpressures.

3. SYSTEM CALCULATIONS

3.1 Modelling principles

Modelling of the concepts has been performed with the flowsheet program Aspen Plus, onbasis of the flowsheet presented in FIGURE 15 for methanol and FIGURE 16 for hydrogen.

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FIGURE 15. Aspen flowsheet used for the calculation of the mass and energy balances for the metha

Reforming

Section

Shift

Section

Gasification and

cleaning section

CO2

Removal

Gas Tu

Steam

Turbine

Gasifier

Reformer

Shift reactor

Scrubber

MeOH

Reactor

Separator

Compresor

Heat Recovery

Power

Power

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FIGURE 16. Aspen flowsheet used for the calculation of the mass and energy balances for hydroge

Reforming

Section

Shift

Section

Gasification and

cleaning section

CO

2

Removal

H2

Production

Steam

Turbine

Gasifier

Reformer

ScrubberHeat Recovery

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The selected systems are modelled in Aspen Plus, a widely used process simulation program.In this flowsheeting program, chemical reactors, pumps, turbines, heat exchanging apparatus,etc are virtually connected by pipes. Every component can be specified in detail: reactionstaking place, efficiencies, dimensions of heating surfaces and so on. For given inputs, productstreams can be calculated, or one can evaluate the influence of apparatus adjustments on

electrical output. The plant efficiency can be optimised by integrating the heat supply anddemand. The resulting dimensions of streams and units and the energy balances cansubsequently be used for economic analyses.

The pre-treatment section is not modelled, their energy use and conversion efficiencies areincluded in the energy balances, though. The models start with the gasification section with acomposition of biomass given in TABLE 5. Only the base scale of 80 dry tonne/hour (430MWth) biomass is modelled.

TABLE 5. Biomass composition (Consonni, Larson 1994).

The heat supply and demand within the plant is carefully matched, aimed at maximising the

production of superheated steam for the steam turbine. A summation of all heat inputs andoutputs in a heat bin is too simple, since it does not take the quality of heat into account.

Heat integration of heat demand and supply within the considered plants here is done by hand.The intention is to keep the integration simple by placing few heat exchangers pergas/water/steam stream. First, an inventory of heat supply and demand is made. Streamsmatching in temperature range and heat demand/supply are combined: e.g. heating before thereformer by using the cooling after the reformer. When the heat demand is met, steam can beraised for power generation.

Depending on the amount and ratio of high and low heat, process steam is raised in heat

exchangers, or drawn from the steam turbine. Steam for gasification and drying is almost

Feed wood Equivalent fuel

Moisture content 50

LHV, MJ/Kg 8.11

HHV, MJ/Kg 10 CH4 6.950

CO 10.780

Dried wood CO2 19.720

Moisture content 15 C2H2 0.016

LHV, MJ/Kg 15.5 C2H4 3.157

HHV, MJ/Kg 17 C2H6 2.229

C3H8 0.042

Bone dry wood H2 0.344

C 49.98 N2 0.016

H 6.12 O2 0.721

O 42.49 C 5.250

N 0.55 H2O 50.000

S 0.06 NH3 0.317

Ash 0.8 SO2 0.048

LHV, MJ/Kg 18.66 H2S 0.006

HHV, MJ/Kg 20

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always drawn from the steam cycle, unless a perfect match is possible with a heat-supplyingstream. The steam entering the steam turbine is set at 86 bar and 501 C.

3.2 Results

TABLE 6 summarises the outcomes of the flowsheet models.

TABLE 6. Results of the Aspen performance calculations, for 430MWth input HHV systems of the methanol

and hydrogen production concepts considered.

Methanol Production

HHV Fuel Output (MW) HHV Efficiency ( ) Material

(MJ/Kmol) Net electricity

1)

Fuel

2)

(ton/hr)

IGT Gasifier, Scrubber,Steam Reforming, 187 43 54 28.2

Shift Reactor, Gas Phase

Methanol Reactor,

Combine Cycle.

Hydrogen Production

HHV Fuel Output (MW) HHV Efficiency ( ) Material

(MJ/Kmol) Net electricity

1)

Fuel

2)

(ton/hr)

IGT Gasifier, Scrubber,

Steam Reforming, 225 26 60 5.7

Shift Reactor, Pressure

Swing Adsorption,

Combine Cycle.

1)Net electrical output is gross output minus internal use. Gross electricity is produced by gas turbine and/or steam

turbine. The internal electricity use stems from pumps, compressors, oxygen separator, etc.

2) The electricity part is assumed to be produced from biomass at e = 45 % HHV efficiency (Faaij et al. 1998). The Fuelonly efficiency is calculated by = Fuel/(MWth,in Electricity/e).

Based on experiences with low calorific combustion elsewhere (van Ree et al. 1995;Consonni and Larson 1994a) the streams in this study, which were projected to be combustedin a gas turbine, will give stable combustion.

The overall plant efficiency for the methanol concept lie in a close range: methanol 54% andhydrogen 60%.

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4. ECONOMICS

4.1 Method

The methanol and hydrogen production costs are calculated by dividing the total annual costsof a system by the produced amount of fuel. The total annual costs consist of:

Annual investments Operating and Maintenance Biomass feedstock Electricity supply / demand (fixed power price)

The total annual investment is calculated by a factored estimation (Peters and Timmerhaus1980), based on knowledge of major items of equipment as found in literature. Theuncertainty range of such estimates is up to 30 %. The installed investment costs for the

separate units are added up. The unit investments depend on the size of the components(which follow from the Aspen+ modelling), by scaling from known scales in literature (seeTABLE 21 in Annex H), using Equation 4-1:

Costa/ Costb= (Sizea/ Sizeb) R Equation 4-1

with R = scaling factor

Various system components have a maximum size, above which multiple units will be placedin parallel. Hence the influence of economies of scale on the total system costs decreases.This aspect is dealt with by assuming that the base investment costs of multiple units are

proportional to the cost of the maximum size: the base investment cost per size becomesconstant.

The total investment costs include auxiliary equipment and installation labour, engineeringand contingencies. If only equipment costs, excluding installation, are available, those costsare increased by applying an overall installation factor of 1.86. This value is based on 33%added investment to hardware costs (instrumentation and control 5%, buildings 1.5% gridconnections 5%, site preparation 0.5%, civil works 10%, electronics 7%, and piping 4%) and40 % added installation costs to investment (engineering 5%, building interest 10%, projectcontingency 10%, fees/overheads/profits 10%, start-up costs 5%) (Faaij et al. 1998).

The annual investment cost follows from Equation 4-2 which takes the technical andeconomic lifetime of the installation into account. The interest rate is 10 %.

( )( )

+

+

=t

et

tt

t

annualt

tt

IRI

IR

IRI

e

e

1

11

1

11

Equation 4-2

with Iannual = Annual investment costsIR = Interest rate = 10%It = Total investment (sum of the unit investments)te = Economical lifetime= 15 yearstt = Technical lifetime = 25 years

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Operational costs (maintenance, labour, consumables, residual streams disposal) are taken asa single overall percentage (4 %) of the total installed investment (Faaij et al. 1998; Larson etal. 1998).It is assumed in this is study that the biomass price is 110 SEK/MWh and electricity supplied

to or demand from the grid costs is 360 SEK/ MWh. The annual load is 8000 hours.

4.2 Results

Results of the economic analysis are given in TABLE 7. The 400 MWth conversion facilitiesdeliver methanol at 93.9 SEK/GJ and hydrogen at 75.75 SEK/GJ. It can be seen that the costsfor the gasification system, syngas processing and power generation generally make up thelarger part of the investment.

Developments in the gasification and reforming technology are important to decrease the

investments. On a longer term capital costs may reduce due to technological learning: acombination of lower specific component costs and overall learning. A third plant may be15% cheaper leading to 8 15% fuel cost reduction (Hamelinck et al, 2001).

The last rows of TABLE 7 show potential fuel production costs in smaller or biggerinstallations. Going to 1000 and 2000 MWth scales the fuel production costs reach costslevels as low as 78 SEK/GJ for methanol and 63.71 SEK/GJ for hydrogen.

On the long term different cost reductions are possible concurrently (Tijmensen 2000).Capital costs for a third plant built are 15% lower, and a large (2000 MWth) plants profit fromeconomies of scale.

FIGURE 17. Optimistic view scenario. Different cost reductions are predictable: (1) technological learning

reduces capital investment by 15% and (2) application of a large scale (2000 MWth) reduces unit investment

cost.

1

2

1

2

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TABLE.7 Economic analysis for the concepts considered, Costs in MSEK Jan 2006

UNIT METHANOL HYDROGEN

Total Pre-treatment MSEK 384.272 384.272

Gasification System -IGT - 719.843 719.843

Oxigen plant - 278.010 278.010

Gas Cleaning -

Tar Cracker -

Cyclones - 9.716 9.716

HTHX - 49.345 49.345

Bag house filter - 7.383 7.383

Condensing Scrubber - 10.514 10.514

Syngas Procesing -

Compresor - 17.602 17.602

Steam Reformer - 493.267 493.267

Shift reactor (installed) - 128.366 128.366

Selexol CO2 removal (ins) - 138.445 0.000

Methanol Production -

Make up Compressor - 114.678 0.000

Gas Phase Methanol - 75.373 0.000

Refining - 144.273 0.000

Hydrogen Production -

PSA units A+B - 0.000 371.442

Power Isle -

Gas Turbine + HRSG - 299.515 154.492

Steam Turbine + steamsystem - 92.862 108.457

Total Installed Invesment MSEK 2963.463 2732.708

Total Invesment corrected MSEK 901.613 831.408

Biomass input dry tonne/hr 80.000 80.000

Biomass input MWth 428.400 428.400

Load hours 8000.000 8000.000

Biomass input GJ/year 12.338 12.338

Annual Cost Capital MSEK 118.539 109.308

OM MSEK 39.851 36.748

Biomass MSEK 376.992 376.992

Cost/Income Power MSEK -79.978 -58.821

Total annual costs 455.403 464.227

Producction Fuel output MW HHV 186.809 225.001

Power output Mwe 27.800 20.424

Efficiency fuel % 53.6 59.3

Cost of fuel produced 80 MWth SEK/GJ 137.293 110.751

400MWth SEK/GJ 93.901 75.748

1000MWth SEK/GJ 84.468 68.138

2000MWth SEK/GJ 78.980 63.711

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Diesel and gasoline production costs vary strongly depending on crude oil process, but for anindication: current gasoline market prices lie in the range of: 12.98 US $/GJ (EIA, 2006).FIGURE 18 shows the production costs for methanol and hydrogen in this study plant. Acomparison was done between the biofuels and gasoline production costs, and it can be seen

that methanol and hydrogen production costs are slightly under the gasoline price.

Methanol Hydrogen

9.5 US$

75.8 SEK

11.8 US$

93.9 SEK

0

10

20

30

40

50

60

70

80

90

100

Price/GJ

GasolineProductionCost12.98 US$/GJ(EIA 2006)

FIGURE 18. Comparison between biofuels and gasoline production costs in US$/GJ.

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5. DISCUSSION AND CONCLUSIONS

The methanol and hydrogen production plants were modelled using the Aspen Plus flowsheetprogram. Mass balances and internal heat demand and supply were carried out. Both modelsgave directly the dimensions of streams and units for the economic calculation.

The biofuel production costs are calculated by dividing the total annual costs of a system bythe produced amount of fuel. Unit sizes, resulting from the plant modelling, are used tocalculate the total installed capital of biofuel plants, larger units benefit from cost advantages.

Conventional production costs of gasoline are about 13 US $/GJ according to EnergyInstitution of America. Production costs of methanol and hydrogen from biomass arecompetitive with conventional prices of gasoline according to this study. Neverthelessconsidering the 30% uncertainty rage in the estimates of the economic method applied one

should be careful in ranking the concepts.

Long term cost reductions mainly reside in slightly lower biomass costs, technologicallearning, and application of large scales (2000 MWth). This could bring the methanol andhydrogen production costs in the range of gasoline/diesel and even lower for sure.

Hydrogen as the ultimate fuel for fuel cell vehicles, has a high fuel economy and low costsper km driven, and will compete with gasoline. However, hydrogen requires new distributioninfrastructure which is the main bottleneck.

A methanol distribution system is probably easier to realise and FCVs fuelled by on-boardreformed methanol will initially have a greater range.

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6. REFERENCES

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Grgoire Padr, C., E., Putsche, V. Survey of the Economics of hydrogen Technologies.Technical Report, National Renewable Energy Laboratory, September 1999.

Hamelinck, C.N. Potential for CO2 sequestration and enhanced coal bed methane productionin the Netherlands. Netherlands agency for energy and the environment NOVEM, Utrecht,

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Hamelinck, Faaij. Future prospects for production of methanol and hydrogen from biomass.September 2001

Hamelinck, C.N., van Hooijdonk, G., Faaij, A. Prospects for Ethanol from LignocellulosicBiomass: Techno-economic Performance as Development Progresses. ISBN 90-393-2583-4,

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Henrich, E, Weirich, F. Pressurized Entrained Flow Gasifiers for Biomass. EnvironmentalEngineering Science 21 (1) 53-64, 2004.

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Iwasaki, W. A Consideration of the Economic Efficiency of Hydrogen Production fromBiomass. International Journal of Hydrogen Energy, 28, (2003), 939-944.

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7. ANNEX A : Properties of MeOH and H

2

TABLE 8.Properties of methanol and hydrogen (Lyde, 1993).

Property Unit Methanol Hydrogen

Chemical Formula CH3OH H2

Molecular Weight kg/kmol 32.042 2.02(x)

Composition, Weight %

Carbon 37.5 0

Hydrogen 12.6 100

Oxygen 49.9 0

Melting Point C -97.7 -259.4

Relative Density 0.79

Density at 20 C kg/m 791

Critical properties

Critical temperature K 512.6 33

Critical pressure MPa 8.092 1.293Critical density g/cm 0.272 0.031

Critical compression factor 0.224 0.307

Viscosity @25C mPas 0.544 8.81 .10-3

Auto ignition temperature C 385 1,0501,080

Flammability limits: Lower/ Higher volume % 6 / 37 4.0 / 75.0

Heat of Formation

Liquid kJ/mol -239.1

Gas kJ/mol -201.3 0.0

Gibbs Free Energy

Liquid kJ/mol -166.6

Gas kJ/mol -162.62

Entropy

Liquid J/mol.K 126.8

Gas J/mol.K 43.9 130.7

Heat capacity@ cst P @25 C J/gK 2.53

J/mol.K 44.06

Boiling point (at atmospheric pressure) C 64.6 -252.8

Heat of Vaporization kJ/mol 35.21 0.9

Vapour pressure @ 25 C kPa 17

Octane no.(1)

Research octane no. 107 130+

Motor octane no. 92 (RON + MON)/2 100

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ANNEX B: Abbreviations

BIG/CC Biomass Integrated Gasification Combined Cycle

COP Conference of the partiesFCV Fuel Cell VehicleGCH Gas converted Hydrogen PGCM Gas converted Methanol ProcessGHG Greenhouse gasHHV Higher Heating ValueICEV Internal Combustion Engine VehicleIPCC Intergovernmental Panel on Climate ChangePSA Pressure Swing Absorption.Syngas abbreviation for synthesis gasSynthesis gas A gas containing primarily hydrogen (H2) and carbon monoxide

(CO), or mixture of H2and CO; intended for synthesis in a reactorto form methanol and /or other hydrocarbons (synthesis gas mayalso contain CO2, water, and other gases).

WGS Water Gas Shift

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ANNEX D: Stream Results for Methanol Production.

TABLE. 9 Stream Results for the Syngas System in Methanol Production.

Substream: MIXED

Mole Flow kmol/hr FUEL STEAM-G OXIGEN 1 2 3

CH4 611.179 0 0 175.088 175.088 175.08

CO 542.953 0 0 1793.638 1793.638 1793.63

CO2 632.150 0 0 966.627 966.627 966.31

C2H2 0.867 0 0 2.44E-05 2.44E-05 2.44E-0

C2H4 158.762 0 0 0.005 0.005 0.0045

C2H6 104.579 0 0 0.010 0.010 0.0095

C3H8 1.344 0 0 1.78E-06 1.78E-06 1.78E-0

H2 240.744 0 0 2154.057 2154.057 2154.04

N2 0.806 0 0 13.749 13.749 13.749

O2 31.788 0 744.028 5.21E-15 5.21E-15 0

C 616.655 0 0 1.75E-22 1.75E-22 0 H2O 521.249 1321.545 0 1476.899 1476.899 337.93

NH3 26.260 0 0 0.373 0.373 0.031

SO2 1.057 0 0 2.19E-07 2.19E-07 2.13E-0

H2S 0.248 0 0 1.305 1.305 1.293

CH30H 0 0 0 0.001 0.001 4.72E-0

Total Flow kmol/hr 3490.640 1321.545 744.0279 6581.752 6581.752 5442.10

Total Flow kg/hr 79360 23808 23808 126976 126976 106437.1

Total Flow cum/hr 10470.479 1456.704 905.986 21522.962 12329.785 139756.7

Temperature C 600 250 25 900 400 40

Pressure bar 20 34.5 20 30 30 1.013

Vapor Frac 0.823 1 1 1 1 1 Liquid Frac 0.177 0 0 0 0 0

Solid Frac 0 0 0 0 0 0

Enthalpy kcal/mol -22.274 -56.299 -0.0445 -26.970 -31.468 -29.44

Entropy cal/mol-K 2.014 -13.502 -6.0361 10.541 5.569 8.895

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TABLE. 9 Continuation of the Stream Results for the Syngas System in Methanol Production.

Substream:

MIXED

Mole Flow kmol/hr 6 7 STEAM-SR 8 9 CO2 10 11 CH4 43.771 43.771 0 43.771 43.771 0 43.771 43.771

CO 1924.945 1924.945 0 1482.208 1482.208 0 1482.208 1482.208

CO2 966.318 966.318 0 1409.056 7.045 1402.01037 7.045 7.045

C2H2 2.44E-05 2.44E-05 0 2.44E-05 2.44E-05 0 2.44E-05 2.44E-05

C2H4 0.005 0.005 0 0.005 0.005 0 0.005 0.005

C2H6 0.010 0.010 0 0.010 0.010 0 0.010 0.010

C3H8 1.78E-06 1.78E-06 0 1.78E-06 1.78E-06 0 1.78E-06 1.78E-06

H2 2547.982 2547.982 0 2990.719 2990.719 0 2990.719 2990.719

N2 13.749 13.749 0 13.749 13.749 0 13.749 13.749

O2 0 0 0 0 0 0 0 0

C 0 0 0 0 0 0 0 0

H2O 206.621 206.621 1030.844 794.728 794.728 0 794.728 794.728

NH3 0.031 0.031 0 0.031 0.031 0 0.031 0.031

SO2 2.13E-07 2.13E-07 0 2.13E-07 2.13E-07 0 2.13E-07 2.13E-07

H2S 1.29336047 1.29336047 0 1.29336047 0 1.293 0 0

CH30H 4.72E-05 4.72E-05 0.00E+00 4.72E-05 4.72E-05 0.00E+00 4.72E-05 4.72E-05

Total Flow kmol/hr 5704.725 5704.725 1030.844 6735.569 5332.266 1403.304 5332.266 5332.266

Total Flow kg/hr 106437.115 106437.115 18570.950 125008.065 63261.789 61746.276 63261.789 63261.789

Total Flow cum/hr 12931.120 6467.952 23.527 7585.590 6032.186 1522.416 4858.318 4509.230

Temperature C 672.85 200 210 200 200 200 268.433 230

Pressure bar 35 35 35 35 35 35 50 50

Vapor Frac 1 1 0 1 1 1 1 1

Liquid Frac 0 0 1 0 0 0 0 0 Solid Frac 0 0 0 0 0 0 0 0

Enthalpy kcal/mol -21.896 -25.758 -64.962 -31.086 -14.978 -92.348 -14.475 -14.761

Entropy cal/mol-K 11.181 5.549 -30.381 2.532 2.461 -2.086 2.739 2.191

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TABLE. 10 Stream Results for the Steam System in Methanol Production.

Substream:

MIXED

Mole Flow kmol/hr C-WATER1STEAM-

1 CLE-H2OW-

WATER S-1BAR S-8BAR S-8BAR2C-

WATER2 STEAM

CH4 0 0 0 0.005 0 0 0 0 0

CO 0 0 0 0.005 0 0 0 0 0

CO2 0 0 0 0.309 0 0 0 0 0

C2H2 0 0 0 1.18E-08 0 0 0 0 0

C2H4 0 0 0 2.19E-07 0 0 0 0 0

C2H6 0 0 0 3.13E-07 0 0 0 0 0

C3H8 0 0 0 8.07E-12 0 0 0 0 0

H2 0 0 0 0.012 0 0 0 0 0

N2 0 0 0 4.94E-05 0 0 0 0 0

O2 0 0 0 0 0 0 0 0 0

C 0 0 0 0 0 0 0 0 0

H2O 2470.125 1543.134 109802 110941 1301.673 1301.673 1301.673 1301.673 1301.6

NH3 0 0 0 0.342 0 0 0 0 0

SO2 0 0 0 6.65E-09 0 0 0 0 0

H2S 0 0 0 0.012026 0 0 0 0 0

CH30H 0 0 0 0.000757 0 0 0 0 0 Total Flow

kmol/hr 2470.125 1543.134 109802 110942 1301.673 1301.673 1301.673 1301.673 1301.6

Total Flow kg/hr 44500 27800 1978117 1998656 23450 23450 23450 23450 2345

Total Flow cum/hr 44.153 150060 1963 2041.668 102139.3 21941.85 14385.729 23.267 10222

Temperature C 10 896.571 10 40 671 1347.981 792.081 10 671.75

Pressure bar 1 1 1.0133 1.0133 1 8 8 1 1

Vapor Frac 0 1 0 0 1 1 1 0 1

Liquid Frac 1 0 1 1 0 0 0 1 0

Solid Frac 0 0 0 0 0 0 0 0 0

Enthalpy kcal/mol -69.017 -49.833 -69.017 -68.433 -52.096 -44.883 -50.919 -69.017 -52.08

Entropy cal/mol-K -41.108 1.500 -41.108 -39.147 -0.647 0.939 -3.600 -41.108 -0.63

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TABLE. 11 Stream results for the Gas Turbine in Methanol Production.

Substream:

MIXED

Mole Flow kmol/hr F-GASES AIR CAIR CSYN LPCSYN

CH4 43.624 0 0 3.23E-09 3.23E-09CO 592.588 0 0 15.073 15.073

CO2 6.806 0 0 637.079 637.079

C2H2 0 0 0 1.70E-16 1.70E-16

C2H4 0.005 0 0 1.47E-18 1.47E-18

C2H6 0.009 0 0 2.56E-21 2.56E-21

C3H8 1.75E-06 0 0 0 0

H2 1211.747 0 0 12.518 12.518

N2 13.735 3762.028 3762.028 3775.765 3775.765

O2 0 989.330 989.330 3.83E-06 3.83E-06

C 0 0 0 1.85E-21 1.85E-21

H2O 1.607 0 0 1306 1306

NH3 0.005 0 0 0 0

SO2 9.01E-08 0 0 8.89E-08 8.89E-08

H2S 0 0 0 1.20E-09 1.20E-09

CH30H 9.106 0 0 2.86E-11 2.86E-11Total Flow

kmol/hr 1879 4751 4751 5747 5747

Total Flow kg/hr 20747 137045 137045 157792 157792

Total Flow cum/hr 1589 113758 10887 25456 378572

Temperature C 30 15 513 1200 519

Pressure bar 30.120 1 28.792 27.792 1

Vapor Frac 1 1 1 1 1

Liquid Frac 0 0 0 0 0Solid Frac 0 0 0 0 0

Enthalpy kcal/mol -9.335 -0.072 3.535 -13.546 -19.725

Entropy cal/mol-K 1.083 0.799 1.321 6.107 7.132

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TABLE. 12 Stream Results for the Steam Turbine in Methanol Production.

Substream: MIXED

Mole Flow kmol/hr 18 19 20 21 22 23 24 26

CH4 0 0 0 0 0 0 0 0CO 0 0 0 0 0 0 0 0

CO2 0 0 0 0 0 0 0 0

C2H2 0 0 0 0 0 0 0 0

C2H4 0 0 0 0 0 0 0 0

C2H6 0 0 0 0 0 0 0 0

C3H8 0 0 0 0 0 0 0 0

H2 0 0 0 0 0 0 0 0

N2 0 0 0 0 0 0 0 0

O2 0 0 0 0 0 0 0 0

C 0 0 0 0 0 0 0 0

H2O 5738 5738 3443 2295 2295 1148 1148 1148

NH3 0 0 0 0 0 0 0 0

SO2 0 0 0 0 0 0 0 0

H2S 0 0 0 0 0 0 0 0

CH30H 0 0 0 0 0 0 0 0

Total Flow kmol/hr 5738 5738 3443 2295 2295 1148 1148 1148

Total Flow kg/hr 103376 103376 62025 41350 41350 20675 20675 20675

Total Flow cum/hr 3953 8223 4934 3289 4257 2129 2129 11636

Temperature C 501 363 363 363 319 319 319 102

Pressure bar 86 34.5 34.5 34.5 25 25 25 3

Vapor Frac 1 1 1 1 1 1 1 1

Liquid Frac 0 0 0 0 0 0 0 0

Solid Frac 0 0 0 0 0 0 0 0Enthalpy kcal/mol -54.166 -55.204 -55.204 -55.204 -55.531 -55.531 -55.531 -57.183

Entropy cal/mol-K -11.809 -11.605 -11.605 -11.605 -11.537 -11.537 -11.537 -10.974

TABLE. 13 Stream Results for the work produced by the turbines in Methanol Production.

GT-W1 GT-WOUT ST-W1 ST-W2 ST-WOUT TOTAL WORK

POWER MW 20.13 -20.74 -6.86 -7.72 -9.91 -30.65

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TABLE 14. Stream Results for the Heat Recovery Steam Gas System for Methanol Production.

Substream: MIXED

Mole Flow kmol/hr 15 18 LPCSYN COOLGAS

CH4 0 0 3.23E-09 3.23E-09

CO 0 0 15.073 15.073

CO2 0 0 637.079 637.079

C2H2 0 0 1.70E-16 1.70E-16

C2H4 0 0 1.47E-18 1.47E-18

C2H6 0 0 2.56E-21 2.56E-21

C3H8 0 0 0 0

H2 0 0 12.518 12.518

N2 0 0 3775.8 3775.8

O2 0 0 3.83E-06 3.83E-06

C 0 0 1.85E-21 1.85E-21

H2O 5738.2 5738.2 1306.3 1306.3NH3 0 0 0.001 0.001

SO2 0 0 8.89E-08 8.89E-08

H2S 0 0 1.20E-09 1.20E-09

CH30H 0 0 2.86E-11 2.86E-11

Total Flow kmol/hr 5738.2 5738.2 5746.8 5746.8

Total Flow kg/hr 103375.8 103375.8 157791.6 157791.6

Total Flow cum/hr 2619.1 3952.6 378572.1 266641.5

Temperature C 328.291 501 519.029 284.972

Pressure bar 86 86 1 1

Vapor Frac 1 1 1 1

Liquid Frac 0 0 0 0

Solid Frac 0 0 0 0Enthalpy kcal/mol -56.077 -54.166 -19.725 -21.633

Enthalpy kcal/kg -3112.724 -3006.656 -718.369 -787.859

Enthalpy MMkcal/hr -321.785 -310.820 -113.354 -124.319

Entropy cal/mol-K -14.612 -11.809 7.132 4.282

Entropy cal/gm-K -0.811 -0.656 0.260 0.156

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ANNEX F: Stream Results for Hydrogen Production.

TABLE 15. Stream Results for the Syngas System in Hydrogen Production.

Substream: MIXEDMole Flow kmol/hr FUEL STEAM-G OXIGEN 1 2 3 4 5

CH4 611.179 0 0 175.088 175.088 175.083 175.083 175.083

CO 542.953 0 0 1793.638 1793.638 1793.633 1793.633 1793.633

CO2 632.150 0 0 966.627 966.627 966.318 966.318 966.318

C2H2 0.867 0 0 2.44E-05 2.44E-05 2.44E-05 2.44E-05 2.44E-05

C2H4 158.762 0 0 0.0046 0.0046 0.0046 0.0046 0.0046

C2H6 104.579 0 0 0.0095 0.0095 0.0095 0.0095 0.0095

C3H8 1.344 0 0 1.78E-06 1.78E-06 1.78E-06 1.78E-06 1.78E-06

H2 240.744 0 0 2154.057 2154.057 2154.046 2154.046 2154.046

N2 0.806 0 0 13.749 13.749 13.749 13.749 13.749

O2 31.788 0 744.028 5.21E-15 5.21E-15 0 0 0

C 616.655 0 0 1.75E-22 1.75E-22 0 0 0

H2O 521.249 1321.545 0 1476.899 1476.899 337.932 337.932 337.932

NH3 26.260 0 0 0.373 0.373 0.031 0.031 0.031

SO2 1.057 0 0 2.19E-07 2.19E-07 2.13E-07 2.13E-07 2.13E-07

H2S 0.248 0 0 1.305 1.305 1.293 1.293 1.293

METHA-01 0 0 0 0.001 0.001 4.72E-05 4.72E-05 4.72E-05

Total Flow kmol/hr 3490.640 1321.54 744.028 6581.752 6581.752 5442.100 5442.100 5442.100

Total Flow kg/hr 79360 23808 23808 126976 126976 106437.095 106437.095 106437.095

Total Flow cum/hr 10470.479 1456.704 905.986 21522.962 12329.785 139756.675 10912.763 13032.586

Temperatura C 600 250 25 900 400 40 563.522867 727

Pressure bar 20 34.5 20 30 30 1.013 35.013 35.013

Vapor Frac 0.823 1 1 1 1 1 1 1 Liquid Frac 0.177 0 0 0