Global Technology Roadmap 

for CCS in Industry 

Biomass-based industrial CO2 sources: 

biofuels production with CCS 

Michiel Carbo 

FEBRUARY 2011

ECN-E--11-012 
Acknowledgments 

This Global Technology Roadmap is the collective effort of a large number of organisations. 

The Norwegian Ministry of Petroleum and Energy and the Global CCS Institute funded the project, which was coordinated by UNIDO. The International Energy Agency supplied most of the 

data used in the document. The IEA Greenhouse Gas R&D Programme and MASDAR provided 

substantial inputs and MASDAR also hosted first meeting in Abu Dhabi. Five sectoral consultants, Paul Zakkour (CarbonCounts), Jock Brown (DNV), Duncan Barker (Mott MacDonald), 

Jean-Pierre Birat (ArcelorMittal) and Michiel Carbo (ECN), wrote the sectoral assessments, 

which formed the substantial basis for the roadmap, and numerous individuals were instrumental in reviewing those assessments. The roadmap was eventually compiled by Heleen de 

Coninck and Tom Mikunda of the Energy research Centre of the Netherlands. 

2 ECN-E--11-012 

 
Contents 

List of tables 4

List of figures 4

1. Introduction 5

2. Current and projected CO2 emissions 6

3. Industry characteristics 10

3.1 Pulp and paper industry 10

3.2 Biofuels production 11

4. Technical overview of capture options 13

4.1 Ethanol 15

4.2 Fischer-Tropsch Liquids 16

4.3 Substitute Natural Gas (BioSNG) 17

4.4 Methanol to BioDME 18

4.5 Hydrogen 19

5. Estimated costs 20

6. Current environmental legislation and pressures 24

7. Major gaps and barriers to implementation 28

8. Actions and milestones 29

9. References 30

ECN-E--11-012 3 
List of tables 

Table 3.1 Capacities and CO2 emissions of European pulp and paper mills ........................ 10

Table 4.1 Indicative CO2 capture rates and CO2 concentrations per source ......................... 15

Table 5.1 Plant capacity, biomass and production cost for different biofuels ....................... 21

Table 6.1 Overview per country of blending mandates, biofuels targets and volumes 

required ................................................................................................................... 25

Table 6.2 Estimated typical and default values for future biofuels ......................................... 27

Table 8.1 Summary of actions for CCS deployment with biofuels production ....................... 29

List of figures 

Figure 2.1 World biomass use for different scenarios ................................................................ 6

Figure 2.2 Global deployment of CCS in industry and biofuels production in 2020 and 

2050 ......................................................................................................................... 7

Figure 2.3 Global deployment of CCS per industrial sector and feedstock in 2020 .................. 8

Figure 2.4 Global deployment of CCS per industrial sector and feedstock in 2050 .................. 8

Figure 3.1 Current and future cumulative global biofuel production according IEA Blue 

Map low-demand scenario ...................................................................................... 11

Figure 3.2 Cumulative capacities of planned second generation biofuel projects ................... 12

Figure 4.1 Routes to biomass with CO2 capture and storage ................................................... 13

Figure 4.2 Products from the gasification of biomass .............................................................. 14

Figure 5.1 Incremental cost of alternative fuels as a function of their CO2-equivalent 

saving potentials at USD 120/bbl ........................................................................... 20

Figure 5.2 The effect of negative emission accounting on total production cost for BioSNG, 

at a natural gas commodity price of 7.5 €/GJ ........................................................ 22

4 ECN-E--11-012 

 
1. Introduction 

The biomass industry involves a range of processes that convert a raw biomass feedstock into 

products such as pulp and paper, sugar, timber and final energy products. Biomass conversion 

combined with Carbon Capture and Storage (CCS) has the potential to generate useful energy 

products such as electricity, bioethanol, Fischer-Tropsch diesel, substitute natural gas (biomethane) and hydrogen, while removing CO2 from the natural carbon cycle for geological timescales (Rhodes and Keith, 2003). 

Under the most stringent climate change mitigation scenarios, an average minimum temperature 

increase of 1.4 °C is likely to occur during the 21st century (Van Vuuren et al., 2008). This corresponds to an increase of approximately 2.0 °C in comparison with preindustrial levels. Mitigation scenarios incorporate forcing targets below 3.5 Watt per m2

, which indicate that CO2 emissions in 2100 should be lowered by 20-60% with respect to 2000. Modelling suggests that the 

application of bioenergy with CCS (BECCS) is indispensable to in order to achieve deep emission reductions in the longer term, in particular under the most stringent climate change mitigation scenarios (Fischer et al., 2007). The use of CO2 neutral biomass has the potential to achieve 

net removal of CO2 from the atmosphere when used in combination with CCS. This is important 

as it allows offsetting historic CO2 emissions and emissions from dispersed sources. Fossil fuel 

conversion with CCS typically only mitigates 80 to 90% of the original CO2 emissions of a 

source (IPCC, 2005). BECCS technologies involve the use CCS with the conversion of biomass 

to electricity or biofuels, or hybrid concepts that can produce both. 

BECCS could also facilitate a further reduction of the net present value cost for meeting relatively low atmospheric CO2 concentration stabilization targets, when compared with CCS from 

fossil fuels only (Azar et al, 2006). The reduction of added costs appears to become more significant with ambitious atmospheric CO2 concentration stabilization targets. A general tendency 

that can be observed from various stabilization scenarios is that the CO2 emission abatement 

through the use of biomass grows relatively slowly during the first half of the century, with projected mitigation potentials of up to 7,000 million tonnes CO2 per year by 2050. While the 

abatement is expected to increase more rapidly during the second half of the century, with projected mitigation potentials of up to 27,000 million tonnes CO2 per year by 2100 (Fischer et al., 

2007). 

The scope of this assessment initially focuses on the conversion of biomass with CCS in the 

manufacturing industry and biofuels production; not taking into account electricity generation. 

Recent projections for 2020 and 2050 (IEA 2009b; IEA, 2010) indicate that the contribution of 

biofuels production with CCS to the combined share of biomass-based CCS in the manufacturing industry and biofuels production is by far the most significant. Therefore a number of concepts for the production of biofuels with CCS will be discussed more in-depth later during this 

assessment. 

ECN-E--11-012 5 
2. Current and projected CO2 emissions 

The direct CO2 emissions in industry amounted to approximately 7,600 million tonnes CO2 in 

2007, this figure involves both process related and fuel combustion emissions (IEA, 2010). The 

total CO2 emissions in the OECD countries are slightly lower than China; while the iron and 

steel, cement and chemicals sectors almost emit three-quarters of the total direct industrial CO2

emissions. The IEA BLUE Map low-demand scenario projects a significant increase of biomass 

use in particular for transportation fuels and power generation, which is displayed in Figure 2.1. 

The scenario also projects a large contribution for transportation biofuels combined with CCS. 

Figure 2.1 World biomass use for different scenarios (1 Mtoe = 0.041868 EJ)

The global deployment of CCS is projected to increase from a capture rate of 161 million tonnes 

stry and biofuels production sector. 

CO2 per year in 2020 to 4,032 million tonnes CO2 per year in 2050 (IEA, 2010). As depicted by 

Figure 2, biomass-based production of synthetic fuels and hydrogen with CCS covers 26.3% of 

the total CCS deployment in the manufacturing industry and biofuel production by 2020 and 

52.3% by 2050, in accordance with the BLUE Map low-demand scenario. 

Please note that Figure 2.2 displays the distribution of CCS deployment for both the manufacturing indu

6 ECN-E--11-012 

 
CCS in 2020 (161 Mton CO2/yr) 

Gas (synfuels+H2)

2.6%

Biomass 

(synfuels+H2)

26.3%

Cement

14.0%

Chemicals

17.9%

Pulp and paper

0.7%

Iron and steel

38.6% 

CCS in 2050 (4,032 Mton CO2/yr) 

Iron and steel

22.4%

Pulp and paper

0.7%

Chemicals

6.6%

Cement

13.6%

Biomass 

(synfuels+H2)

52.3%

Gas (synfuels+H2)

4.5%

Figure 2.2 Global deployment of CCS in industry and biofuels production in 2020 and 

2050, based on data obtained from (IEA, 2010) 

Figure 2.2 illustrates that the contribution of CCS in the pulp and paper industry only covers a 

small share of the total projected CCS deployment by 2050. It must be noted that the pulp and 

paper industry currently consumes the largest biomass share in industry, 55 out of a total energy 

use of 190 Mtoe (IEA, 2010), which does not account for biomass use as process feedstock. The 

total direct and indirect CO2 emissions for the pulp and paper industry amounted 405 million 

tonnes CO2 per year in 2007, and in accordance with the BLUE Map low-demand scenario these 

are projected to decrease to 175 million tonnes CO2 per year by 2050 (IEA, 2010). The most 

important contributions to this reduction are energy efficiency improvements, fuel switching 

and the use of decarbonised electricity. 

One of the most important by-products in this industry is black liquor, which is an aqueous solution of lignin, hemicellulose and the spent pulping chemicals used during digestion of wood into 

paper pulp. Black liquor typically contains roughly half of the energy of the wood going into the 

digester. The black liquor stream is usually concentrated and is burned in a recovery boiler to 

generate steam and reclaim the pulping chemicals. The total global black liquor production 

amounted approximately 215 million tonnes (dry basis) in 2007, which corresponds to roughly 

60 Mtoe (Naqvi et al., 2010). 

Numerous studies illustrated that black liquor gasification combined with synthesis of transportation fuels could be very suitable for integration with CCS, both from a technological and economical perspective (Möllersten et al., 2003; Larsson et al., 2006; Naqvi et al., 2010; Petterson 

and Harvey, 2010). The projected total contribution of CCS combined with black liquor Integrated Gasification Combined Cycle (IGCC) power plants is relatively small at 30 million tonnes CO2 per year in 2050 (IEA, 2010). The costs for CCS appear similar to coal-fired IGCC 

with CCS. However, black liquor gasification with synthesis of transportation fuels and CCS 

has not been taken into account in the latter reference. It is recognized that the pulp and paper 

industry could be an early mover for large-scale biofuels production with CCS in the EU and 

North America; and therefore a cost-effective contributor to emission reductions through the 

implementation of BECCS. 

Figure 2.3 and Figure 2.4 illustrate the global deployment of CCS per industrial and biofuels 

production sector and feedstock in 2020 and 2050, respectively. These figures were compiled 

under the assumption that the fraction of biomass use as function of the total fuel consumption 

in a specific industrial sector can projected at the deployment of CCS in that sector. This approach results in an estimate of both the biomass-based and fossil fuel-based share of CCS deployment. The projected contribution of biomass-based CCS amounts 30.6% in 2020, of which 

ECN-E--11-012 7 
26.3% accounts for synfuels and H2. The projected contribution of biomass-based CCS is expected to increase to 58.8% in 2050, of which 52.3% accounts for synfuels and H2. The cement 

(4.5%), iron and steel (1.1%), chemicals (0.5%) and pulp and paper (0.4%) industries will cover 

a much smaller share of the global CCS deployment, therefore only the production of biomassbased transportation fuels in combination with CCS will be taken into account during this sectoral assessment. 

CCS in 2020 (161 Mt CO2/yr)

26.3%

36.8%

12.2%

17.4%

2.6% 0.4%

1.7%

0.5%

1.8%

0.3%

Biomass (synfuels + hydrogen)

Cement (biomass-based)

Iron and steel (biomass-based)

Chemicals (biomass-based)

Pulp and paper (biomass-based)

Iron and steel (fossil fuel-based)

Cement (fossil fuel-based)

Chemicals (fossil fuel-based)

Gas (synfuels + hydrogen)

Pulp and paper (fossil fuel-based)

Figure 2.3 Global deployment of CCS per industrial sector and feedstock in 2020, based 

on data obtained from (IEA, 2010)

CCS in 2050 (4,032 Mt CO2/yr)

52.3%

21.3%

9.1%

6.1%

0.4%

0.5% 1.1%

4.5%

4.5% 0.3%

Biomass (synfuels + hydrogen)

Cement (biomass-based)

Iron and steel (biomass-based)

Chemicals (biomass-based)

Pulp and paper (biomass-based)

Iron and steel (fossil fuel-based)

Cement (fossil fuel-based)

Chemicals (fossil fuel-based)

Gas (synfuels + hydrogen)

Pulp and paper (fossil fuel-based)

Figure 2.4 Global deployment of CCS per industrial sector and feedstock in 2050, based 

on data obtained from (IEA, 2010)

8 ECN-E--11-012 

 
The increase in biomass use will largely depend on the decarbonisation of the biofuels production sector, with a transition from fossil fuels to biofuels. The replacement of natural gas with 

biomass-derived substitute natural gas (SNG), and an increase demand of hydrogen for heat and 

power may also stimulate a growth of the biomass use. In the pulp and paper industry black liquor is a biomass derived residue that is locally available at relatively large quantities, and could 

be deployed -through gasification- for synthesis of biofuels in combination with CCS. 

ECN-E--11-012 9 
3. Industry characteristics 

3.1 Pulp and paper industry 

The production of pulp and paper involves different technologies that are able to convert wood 

in to pulp; these can be roughly divided in to chemical and mechanical pulping, and combinations of both. Kraft mills use chemicals to degrade the lignin that binds the cellulose fibers; 

combustion of the lignin compounds (called black liquor) in a recovery boiler allows reuse of 

these chemicals. Mechanical mills use grinding and –at some point in the process– steam treatment, this typically results in products that are less sturdy. Paper mills can use a combination of 

virgin and recycled pulp to produce paper. 

Table 3.1 illustrates that for Kraft over 90% of the CO2 is of biogenic origin, for mechanical approximately 50% and for paper mills less than 20%. The average European Kraft integrated 

pulp and paper mill emitted 1.2 million tonnes CO2, the average mechanical pulp and paper mill 

0.23 million tonne CO2 per year, and the average paper mill 0.17 million tonne CO2 per year. 

Table 3.1 Capacities and CO2 emissions of European pulp and paper mills (Jönsson and 

Mill type Kraft Kraft integrated Mechanical 

p

Paper1

Berntsson, 2010)

pulp pulp & paper ulp & paper 

Mills [no.] 21 29 45 76 

Pulp capacity 9,9 12,320 12,095 14,775 

[kADt/year]2

55 

Paper capacity 

[tonnes/year] 

- 16,131 22,132 27,169 

CO2 emissions [thousand tonnes/year]

Mills [no.] 21 29 43 70 

Fossil 1,391 3,164 4,759 9,420 

Biogenic 24,308 30,775 5,524 2,217 

Total 25,699 33,940 10,283 11,637 

1 Paper mills with capac e 200 thous es paper pe ere included

he total global CO2 emissions in the pulp and paper industry are estimated to amount to 405 

ff gases of pulp and paper mills can typically contain up to 13-14% CO2, and for Kraft mills 

ity abov and tonn r year w

2

 kilo air dried tonnes (90% dry solids) 

T

million tonnes per year (IEA, 2010). Roughly two third of these emissions originate from Kraft 

pulp and integrated pulp mills (Jönsson and Berntsson, 2010), and therefore approximately 60% 

of the CO2 emissions of total pulp and paper industry are biogenic. During recent years the 

global Kraft pulp production capacity has been growing at a relatively slow rate. The global potential for CO2 capture is estimated to be 300 to 350 million tonnes at present. 

O

most of this CO2 is biogenic by origin. For Kraft mills retrofit of CO2 capture could be an option, using chemical absorption similar to post-combustion CO2 capture. Drastic process integration could potentially reduce the specific energy consumption for CCS and the associated 

capture costs substantially (Möllersten et al., 2003; Jönsson and Algehed, 2010). For mechanical 

pulp and stand-alone paper plants integration of CCS appears less viable due to the relatively 

high cost of capturing small volumes of CO2. 

10 ECN-E--11-012 

 
The estimated global black liquor production obtained from Kraft mills equaled approximately 

60 Mtoe in 2007 (Naqvi et al., 2010), while a typical Kraft mill produces 250 to 300 MWth of 

black liquor (Landälv, 2009). The fleet of recovery boilers is aging and a large number of boilers are expected to be replaced in the coming decade. This could open a window of opportunity 

for the gasification of black liquor; the latter would allow the synthesis of transportation fuels 

that have more added value than the production of heat or electricity. 

3.2 Biofuels production 

The current cumulative biofuel production mainly involves the production of bioethanol from 

sugar cane and grains, and biodiesel from oil seeds. The cumulative global production of these 

first generation biofuels amounted approximately 2.0 EJ in 2008 (REN21, 2009), as displayed in 

Figure 5. The production of bioethanol is a well-established industry, particularly in Brazil and 

the USA with 90% of the global bioethanol production using sugar cane and corn (respectively) 

as feedstock. Roughly two-thirds of the global biodiesel production stems from the European 

Union, with Germany and France being the largest producers. The feedstock is usually vegetable oil, such as rapeseed or soybean oil. 

The 2020 and 2050 projections for the global biofuels production in accordance with the IEA 

BLUE Map low-demand scenario (IEA, 2010) are also displayed in Figure 3.1. The total biofuels production is projected to increase to 3.2 EJ in 2020, with a slight increase for bioethanol 

from sugar cane and the introduction of ligno-cellulosic bioethanol and Fischer-Tropsch diesel. 

The total biofuels production is projected to further increase to 35.2 EJ in 2050. According to 

the IEA BLUE Map scenario the production of bioethanol from grains and biodiesel from oil 

seeds are potentially abandoned, while large increases are projected for bioethanol from sugar 

cane and ligno-cellulosic material, Fischer-Tropsch diesel. It also foresees in the deployment of 

gaseous energy carriers from biomass, being biogas, BioSNG and hydrogen. 

0

5

10

15

20

25

30

35

40

2008 2020 2050

Cumulative global biofuel production (EJ)

Hydrogen from biomass

Biogas/BioSNG

Biodiesel (Fischer-Tropsch)

Biodiesel (oil seeds)

Ethanol (ligno-cellulosic)

Ethanol (cane)

Ethanol (grains)

Figure 3.1 Current (converted from: REN21, 2009) and future cumulative global biofuel 

production according IEA Blue Map low-demand scenario (IEA, 2010) 

ECN-E--11-012 11 
Figure 3.2 displays the cumulative capacity of currently known planned second generation biofuel projects; this survey was conducted by IEA Bioenergy Task 39 (Bacovsky, 2010). Thermochemical, bio-chemical and hybrid conversion cover approximately 60%, 30% and 10%, respectively, of the global second generation biofuel production capacity in 2016. The total foreseen 

production of second generation biofuels in 2016 is roughly 3% of the total biofuels production 

in 2008. capacity [t/a]

Figure 3.2 Cumulative capacities of planned second generation biofuel projects (Bacovsky et 

al., 2010)

The IEA BLUE Map low-demand scenario (IEA, 2010) foresees a contribution of 80% thermochemical and 20% bio-chemical conversion for second generation biofuels production in 2020. 

The total foreseen production of second generation biofuels in 2020 is approximately 35% of 

the total biofuels production in 2008. This appears to be a fairly large discrepancy to be covered 

in just four years; a reason for this could be that the IEA Bioenergy Task 39 survey only includes projects from the respondents to a voluntary questionnaire. Furthermore a significant 

amount of demonstration projects are commissioned in the coming two to three years, which 

potentially could result commercial-scale facilities during the second half of this decade. It is 

also important to realize that the BLUE Map scenario envisions a certain global energy demand 

and CO2 emissions in 2050, which determines what the deployment of biofuels should be in 

2020 to achieve the long-term target. 

12 ECN-E--11-012 

 
4. Technical overview of capture options 

There are a number of routes to convert biomass into final energy products (see Figure 4.1). For 

this roadmap, because of the focus on CCS applications in biofuels production, only the gasification and biological processing routes will be covered. 

Figure 4.1 Routes to biomass with CO2 capture and storage (Rhodes and Keith, 2003) 

The replacement of fossil fuels with synthetic fuels that are produced from sustainable biomass 

readily provides a CO2 mitigation option. The use of biomass in biofuel production processes 

typically also results in high-purity CO2 by-product streams. In that case the combination of 

CO2-neutral biomass and CO2 capture and permanent storage potentially leads to a net CO2 uptake from the atmosphere, i.e. negative lifecycle emissions. 

Bio-chemical biomass conversion processes, for example fermentation, uses living microorganisms to breakdown the feedstock and produce liquid and gaseous fuels. A common 1st generation process to produce bioethanol, is the fermentation of sugar cane, sugar beet or corn starch, 

where a by-product of the reaction is a relatively pure stream of CO2. The production of liquid 

ethanol and gaseous CO2 is almost equal on mass basis. The separation of both compounds is 

straightforward since both compounds are present in different phases; hence no additional separation equipment is required. The CO2-rich off-gases from the fermentation tanks are dried and 

compressed to facilitate transport and storage. On a bio-ethanol plant with a net output of 235 

million litres per year, the addition of compression equipment only leads to a 0.9% increase in 

capital costs (Rhodes and Keith, 2003). 

Thermo-chemical biomass conversion, or gasification, is a thermal treatment that results in the 

production of gaseous products and a small amount of char and/or ash (Demirbas, 2002). During 

gasification, the biomass or black liquor is converted into gases by means of pyrolysis, which 

occurs at high temperatures of 875-1275 K. To reach these temperatures an oxidizing agent is 

needed. This can be air or oxygen (Gao et al., 2008). For synthesis of liquid or gaseous fuels it 

is essential that only a minimum amount of nitrogen is present during the synthesis. This reduces equipment sizes and cost, and increases the partial pressures of the reactants, which typically improves the product yield. This implies that relatively pure oxygen must be employed, 

typically obtained via cryogenic distillation of air, at significant thermodynamic and economic 

penalties. 

ECN-E--11-012 13 
Depending on a number of variables such as feedstock characteristics, temperature and gasifying agent, the gas composition consists of carbon monoxide, carbon dioxide, hydrogen, methane, nitrogen, as well as non-gaseous by-products such as char and tars. At gasification temperatures above 1275 K the resulting gas stream consists primarily of hydrogen and carbon monoxide, called synthesis gas or syngas. At relatively lower gasification temperatures, other components such as methane and higher hydrocarbons (tars) are also present in the resulting gas 

stream, and this is often referred to as producer gas. 

The gasification of biomass can lead to a number of products, most suitably represented in 

Figure 4.2, derived from (Smit, 2009). Carbon dioxide is a by-product during all the represented 

synthesis processes. The employed CO2 separation technologies are the same as those that are 

foreseen for pre-combustion CO2 capture at power plants. 

Figure 4.2 Products from the gasification of biomass (Smit, 2009) 

Integration of additional separation equipment to facilitate CCS is typically not necessary during 

conversion of biomass to biofuels, either because gaseous CO2 can be readily separated from the 

liquid product, or because CO2 separation equipment is already in place to comply with required 

product specifications (Carbo et al., 2010a). The CO2 product stream needs to be dried and 

compressed to facilitate transport and storage. For both bio-chemical and thermo-chemical biomass conversion routes the additional CO2 capture costs for dehydration and compression and 

are estimated to amount 6-12 $ per tonne CO2 (Dahowski and Dooley, 2008). 

The different routes for CCS during biofuel production vary significantly in terms of characteristics and estimated costs. Only capture of process-related CO2 emissions has been taken into 

account, since these provide high-purity and often also high-pressure CO2 streams. Capture 

from diluted sources, such as an on-site Combined Heat and Power (CHP) unit is financially 

less interesting, due to the limited scale of the CO2 source and the heavily diluted flue gas 

stream. For this matter four different biofuel conversion routes are described in more depth: 

bioethanol through biomass fermentation, as well as Fischer-Tropsch liquids, BioSNG, and hydrogen through biomass gasification and subsequent synthesis. Table 4.1 summarizes indicative 

CO2 capture rates and CO2 product stream concentration per CO2 source. 

14 ECN-E--11-012 

 
able 4.1 Indicative CO2 capture rates and CO2 concentrations per source 

CO2 source Carbon in captured high-purity CO2 concentration in high-

 stream1

T

CO2 stream/ purity CO2

Carbon in feed stream [mol%] [mol%] 

Ethanol 15-35% ~99% 

FT diesel ~50% >95% 

BioSNG 40-45% >95% 

BioDME ~50% >95% 

Hydrogen >90% >95% 

.1 Ethanol 

Ethanol is currently produced through the bio-chemical conversion of mainly agricultural crops, 

ugar (sugar cane, sugar beet, molasses and sorghum) or starch (potato, 

la-

 steps, which are needed to increase the ethanol concentration. Sucrose is 

ntly 

2 tured and stored. It 

 

4

which contain either s

corn, barley and wheat). The starch in the latter crops should be converted to sugars prior to 

further conversion. 

The predominant conversion technology is biomass fermentation followed by a series of distil

tion and dehydration

extracted from sugar-rich agricultural crops by mechanically pressing the cooked biomass and a 

subsequent fractionation. Yeast converts the sucrose which results in ethanol and carbon dioxide 

as waste products of the metabolism. The ethanol product obtained from the fermentation is diluted with water, which could be removed through distillation up to ethanol purities of approximately 96 wt%. The formation of a low-boiling water-ethanol azeotrope prevents further purification through distillation. This so-called hydrated ethanol is suitable to use as fuel, although 

not for blends with gasoline. Further purification to anhydrous ethanol –which allows blending 

with gasoline– is established by using molecular sieves that absorb the remaining water content. 

The use of starch-based crops requires grain milling or grinding followed by liquefaction and 

fractionation. The latter steps take place simultaneously during cooking after the addition of water. Either enzymatic or acidic hydrolysis is used to convert starch to hexose, which can be fermented to produce ethanol and CO2 as described above. The combined amount of ethanol produced in the US and Brazil was approximately 42 billion liters in 2007 (IEA Bioenergy, 2008). 

This corresponds to a CO2 release during the fermentation of 32 million tonnes CO2 per year in 

both countries. In the USA the average plant size is about 200 million liters of ethanol per year, 

which translates to 140 thousand tonnes high-purity CO2 that could be captured and stored. 

Significant R&D efforts are dedicated to the conversion of lignocellulosic feedstock into ethanol 

through fermentation. These types of feedstock are typically cheaper and more abunda

available than food crops, although the molecular structure –and therefore the conversion in to 

ethanol– is more complex. Lignocellulose consists of cellulose, hemicellulose and lignin; the 

first two can be converted to sugars and subsequently fermented, although hydrolysis of these 

compounds typically is more complex than of starch. Lignin is an aromatic polymer that can not 

be fermented and is typically combusted to generate heat and/or electricity. 

Based on the initial carbon content of the sugars that are fermented in a bioethanol plant 67% of 

the carbon leaves as ethanol, and 33% as high-purity CO that could be cap

must be noted that the distribution of carbon in the outlet streams of the entire plant can vary 

significantly with different feedstocks and plant configurations, for example by combustion of 

lignin in a combined heat and power unit in a lignocellulosic bioethanol plant. 

1

 After dehydration 

ECN-E--11-012 15 
One of the first commercially operated ethanol plants integrated with CCS, and thus biomassbased industrial CO2 capture and storage project, started operation in the U.S.A. during the third 

uarter of 2009 (Chaparral Energy, 2010). At present approximately 60% (170-180 thousand 

lon tonnes CO over three years in the Mt. Simon Sandstone saline formation. The CO is oblant in Sao Paolo state, Brazil (GEF, 2010). For a typical sugar mill size in Sao Paolo state of 

version of lignocel-

 by gas cleaning, Fischer-Tropsch synthesis and reropsch liquid products are diesel and kerosene. 

sch 

ynthesis. Furthermore, high temperatures reduce the tar concentration in the produced synthesis 

moval prior to further synesis. Entrained flow gasification requires biomass pre-treatment to allow high-temperature 

d catalysts, cobalt-based catalysts display no activity for 

e water-gas reaction and therefore the H /CO-ratio should be corrected upfront by a separate 

e from methane to heavy waxes. The process is also highly exothermic 

nd adequate heat removal is required to control the desired product specification. Cobalt-based 

q

tonnes CO2 per year) of the total produced CO2 is captured at the Arkalon bioethanol plant in 

Liberal, Kansas, and transported to an oil field near Booker, Texas, for enhanced oil recovery. 

A similar pilot project in the U.S.A. is managed by the Midwest Geological Survey Consortium 

and started operation early 2010 (MGSC, 2010). This project foresees the injection of 1.0 mi

li 2 2

tained from the Archer Daniels Midland Company (ADM) bioethanol plant in Decatur, Illinois. 

The Global Environment Facility (GEF) of the United Nations Development Programme 

(UNDP) awarded a grant for implementation of CCS at a sugar fermentation-based ethanol

p

25 million liters of ethanol per year, this implies that 20 thousand tonnes of CO2 per year will be 

stored in a local saline formation. Implementation is foreseen in early 2012. 

4.2 Fischer-Tropsch Liquids 

The production of Fischer-Tropsch liquids involves the thermo-chemical con

lulosic biomass into synthesis gas, followed

fining to the final product. Typical Fischer-T

High-temperature biomass gasification technologies result in a synthesis gas that primarily consists of hydrogen and carbon monoxide, which are two primary reactants in Fischer-Trop

s

gas. Two types of gasifiers that are suitable for synthesis gas production with high H2 and CO 

concentration can be distinguished: pressurized fluidized bed and entrained flow gasifiers 

(Higman and van der Burgt, 2008). Both use oxygen obtained from an Air Separation Unit 

(ASU), to minimize the nitrogen concentration in the synthesis gas. 

After fluidized bed gasification roughly 5% of the carbon ends up in the ash, while the synthesis 

gas contains a moderate amount of tar that requires conversion or re

th

gasification. Pre-treatment can occur through torrefaction, which involves biomass upgrading 

though a mild heat treatment (250-300 °C) that increases the heating value, reduces the moisture 

content and eases milling (Gerhauser et al., 2010). Another pre-treatment method involves biomass pyrolysis, which involves a moderate heat treatment (450-550 °C) that results in a pyrolysis oil slurry and char. The Carbo-V concept by Choren is commercially available and includes 

pyrolysis of biomass at moderate temperature and subsequently high-temperature (> 1300 °C) 

conversion of the pyrolysis oil to synthesis gas, while the char is added and converted in a secondary quench step (Rudloff, 2010). 

Two types of catalyst are commercially used for the Fischer-Tropsch synthesis: iron- and cobalt-based catalysts. Unlike iron-base

th 2

water-gas shift reactor. Before the Fischer-Tropsch synthesis, CO2 and other trace impurities are 

selectively removed in the acid gas removal section. The absence of CO2 during the FischerTropsch synthesis improves the yield. CO2 is separated using commercially available absorption 

technologies, and upon regeneration of the liquid solvent a high-purity CO2 stream is available 

for capture and storage. 

Fischer-Tropsch synthesis produces a range of products, which depending on the operating conditions and catalyst, rang

a

16 ECN-E--11-012 

 
catalysts are commonly used in fixed reactors, while iron-based catalysts are commonly used in 

slurry reactors. Saturated steam is generated in the reactor to maintain appropriate temperature 

levels. After the Fischer-Tropsch synthesis the gaseous products are separated and either used to 

generate electricity, or these are fed to an autothermal reformer to produce synthesis gas that is 

fed back to the gasification outlet stream. The liquid products are distilled to produce the final 

products and a heavy fraction; the latter undergoes an additional hydrocracking step to increase 

the final product yield. 

A Fischer-Tropsch liquids plant based on an oxygen-blown CFB gasifier emits roughly 5% of 

the initial carbon input as CO2 in the flue gas of the combined heat and power unit, 6% in the 

har, 37% in Fischer-Tropsch liquids and 52% as high-purity CO2 that could be captured and 

 of 45 MWth and an output of 18 million liter fuel. Wood chips are 

onverted in the Carbo-V gasifier; the synthesis gas is cleaned, conditioned and led to the 

ass, folpression, the methane-rich product stream 

n producer gas should be obtained from the 

asifier, since the absence of nitrogen facilitates compliance with specifications for injection in 

d combustion reactor 

engtsson, 2007). The first reactor uses steam for fluidisation and typically yields high initial 

 condense at temperares below 400°C, and cause equipment fouling and plugging. The carcinogenic nature of tars 

c

stored (Carbo et al., 2010a). 

The first commercial biomass-to-liquids plant is the Choren Beta plant in Freiberg, Germany, 

(Rudloff, 2010) with an input

c

Fischer-Tropsch synthesis. Commercial operation is expected to start late 2010. 

4.3 Substitute Natural Gas (BioSNG) 

BioSNG is produced through the thermo-chemical conversion of lignocellulosic biom

lowed by gas cleaning and methanation. After com

could be injected in any existing natural gas grid. 

One of the most important aspects during the design of a bioSNG plant is the selection of the 

appropriate gasification technology. A nitrogen-lea

g

high-pressure natural gas grids. This requirement leaves three possible biomass gasification 

technologies: oxygen-blown pressurised Entrained Flow (EF), oxygen-blown pressurised fluidised bed (both BFB and CFB) and steam/air-blown indirect gasification at atmospheric pressure. 

The net biomass-to-bioSNG efficiency on LHV-basis for these technologies amount 54.3%, 

58.1% and 66.8%, respectively (van der Meijden et al., 2010). The net efficiency for indirect 

gasification based bioSNG plants is significantly higher since this configuration does not require 

a capital and energy-intensive Air Separation Unit (ASU). Oxygen-blown BFB and CFB biomass gasification are more developed than indirect gasification at present. However, for 

BioSNG production the focus will be on indirect gasification, since this technology has a significantly higher yield and is expected to mature during the next decade. 

Indirect gasification concepts typically consist of two reactors: Biomass pyrolysis takes place in 

the first reactor by heated bed material obtained from the secon

(B

methane concentrations in the producer gas stream, due to the moderate gasification temperatures (800 – 900°C). The carbon conversion in the first reactor is typically 80 – 90%; the unconverted fraction is combusted in the second air-blown fluidised bed combustion reactor, to 

pre-heat the bed material prior to feeding it back to the pyrolysis reactor. The use of bed material for heat transfer between both reactors limits the operating pressure to approximately 7 bara 

(van der Meijden et al., 2010). At significantly higher pressures the gaseous volume becomes 

too small to provide sufficient transport of bed material for heat transfer. 

An important disadvantage of gasification at moderate temperatures is the formation of tars 

(Milne et al., 1998). Tars are higher aromatic hydrocarbons that typically

tu

also poses strict handling implications from a safety and environmental point of view. Thermal 

or catalytic cracking of tars is undesirable, since these technologies are expected to reform a 

significant part of the methane content in the producer gas. Oil-based scrubbing appears more 

ECN-E--11-012 17 
appropriate since tars are removed above the water dew point temperature, which avoids contamination of water with tar compounds. After regeneration of the scrubbing oil these tars can 

be fed back to the combustion reactor of the indirect gasifier. 

After tar removal, unsaturated hydrocarbons are hydrogenated, sulphurous and chlorine components are removed and CO2 is separated. The latter takes place using commercially available 

atural gas sweetening technologies (absorption), to provide a product gas with the appropriate 

ield in the methanation section. 

ownstream of the methanation reactors, the product stream primarily consists of methane and 

ki et al., 2010), while water-gas shift, CO2 separation and methanation techologies are commercially available and have been proven downstream of coal gasification apE.ON. The first phase comprises a 20 MWth

ioSNG plant to be operational in 2012; it will be constructed in Göteborg, Sweden. For this 

 downstream of the same gasification 

e Fischer-Tropsch liquids section of this assessment. The 

-gas shift reactor, with H2S and CO2 removal positioned 

e mature market for DME as transportaon fuel (Clausen et al., 2010). 

nd operates at a pressure of 30 bar. From 2010 

 2012 a BioDME pilot plant will be operated downstream of the gasifier as part of the EU FP7 

n

stoichiometric composition of H2, CO and CO2. A near pure CO2 stream will be available upon 

regeneration of the absorption liquid, which can be compressed to facilitate transport to the CO2

storage site. Traces of CO2 that are not separated will be converted to methane in the methanation section. Commercially offered methanation processes are based on a sequence of fixed-bed 

reactors with intermediate cooling; the catalyst is nickel-based. 

Gasification in indirect gasifiers typically takes place at relatively low pressure; hence the 

cleaned producer gas is compressed to increase the methane y

D

water with traces of hydrogen and carbon monoxide. An interesting feature of a bioSNG plant is 

the net production of water, in contrast to fossil fuel power plants with CCS. The produced water is removed during bioSNG upgrading, and is therefore relatively clean which eases waste 

water treatment. 

Dedicated biomass gasification and gas cleaning technologies are still under development at this 

stage (Kopyscins

n

plications. A BioSNG plant based on indirect gasification emits roughly 20% of the initial carbon input as CO2 in flue gas, 40% as methane in BioSNG and 40% as high-purity CO2 that 

could be captured and stored (Carbo et al., 2010a). 

The largest commercial BioSNG project is the Göteburg Biomass Gasification Project, GoBiGas, which was initiated by Göteborg Energy and 

b

plant an indirect FICFB gasifier will be deployed with Haldor Topsøe’s TREMP fixed bed 

methanation technology downstream (Mastrup, 2010). The second phase involves an 80 MWth

SNG plant, which is scheduled to be operational by 2016. 

4.4 Methanol to BioDME 

The methanol to BioDME synthesis is typically positioned

technologies as described under th

H2/CO-ratio is adjusted in a water

downstream. The methanol yield in a single reactor can be relatively high, although a recycle or 

a second reactor is required to further increase the yield and reduce by-product formation. Any 

remaining by-products will be separated prior to the DME synthesis, which converts two ethanol molecules to one molecule dimethyl ether and one molecule water (Landälv, 2009). Any unconverted methanol is recycled or sold as by-product. 

An interesting feature of a BioDME plant is the opportunity for co-production of methanol and 

DME, which could be used to bridge the gap to a mor

ti

Chemrec has operated a 3 MWth oxygen blown black liquor gasifier at Piteå, Sweden (Landälv, 

2009). This pilot facility was started up in 2005 a

to

BioDME project. This project foresees the production of 4 tonnes DME per day, which will be 

used for field tests with 14 trucks. This project is coordinated by Volvo. 

18 ECN-E--11-012 

 
A larger commercial project is foreseen in Domsjö, Sweden. This project involves a 200 MWth

Chemrec oxygen blown black liquor gasifier, and the downstream synthesis of 450 tonnes 

ethanol per day or 300 tonnes DME per day. The final investment decision for this project will 

 gasoline project (Mastrup, 2010). This 

ilot plant will be installed downstream of the Carbona gasifier at GTI in Des Plaines, Illinois, 

ids section of this assessment. The water-gas shift reaction however, 

quence of reactors with intermediate cooling, to maximize the carbon 

m

be made late 2011, while start-up is scheduled in 2013. 

In parallel to the above mentioned methanol to BioDME projects, the U.S. Department of Energy awarded a 25 million USD grant for a methanol to

p

which processes 20 tonnes of wood per day corresponding to an input of roughly 5 MWth. 

4.5 Hydrogen 

The hydrogen production in principal uses the same gasification technologies as described under

the Fischer-Tropsch liqu

likely takes place in a se

monoxide conversion to hydrogen. CO2 and trace impurities will be selectively removed in the 

acid gas removal section, using commercially available absorption technologies. The resulting 

hydrogen-rich stream still contains traces of CO and CO2, therefore this stream is further purified in a Pressure Swing Adsorption (PSA) unit. The bulk of the initial carbon input can be captured as pressurized high-purity CO2, being roughly 80 t0 90%. Part of the carbon is captured in 

the char or slag (depending on the gasifier type) and the PSA off-gases. 

To the knowledge of the author no commercial demonstration plants for the production of biobased hydrogen are either in operation or planned at present. 

ECN-E--11-012 19 
5. Estimated costs 

Cost data for biomass-to-biofuel conversion processes are scarce, in particular for conversion 

processes combined with CCS. The most important reason for this is that BECCS forms a relatively new field in research and development. Plants for the production of second generation 

biofuels are still relatively small in size, up to the commercial demonstration phase, which could 

result in less accurate cost figures. 

Typically the capital investment of biomass conversion plants is higher than for fossil fuel conversion plants. This is mainly attributable to the nature of biomass: the energy density is usually 

lower than for instance coal, the moisture content higher and the composition of biomass is less 

homogenous and more fibrous. Therefore more equipment for biomass pretreatment is required 

in comparison with coal and natural gas. Large-scale import of biomass is expected to result in 

higher prices on an energy basis than for fossil fuels, which also contributes to higher prices for 

biofuels. 

These phenomena can also be observed in Figure 5.1. This figure displays the incremental cost 

and lifetime well-to-wheel CO2 savings for various synthetic fuels and biofuels using conventional gasoline as a reference (without accounting for negative CO2 emission reduction through 

BECCS). The incremental cost for biomass-to-liquids (BTL) in comparison with gasoline is 

roughly zero, while the cost significantly decreases for CTL despite of the relatively high CO2

emissions. 

Figure 5.1 Incremental cost of alternative fuels as a function of their CO2-equivalent 

saving potentials at USD 120/bbl (IEA, 2010)

Note 1: Negative CO2-eq savings means the use of the fuel results in higher WTW CO2-eq 

emissions than using gasoline. 

Note 2: Assumes oil priced at USD 120/bbl. Costs reflect a bottom-up technology cost analysis of 

making each fuel, including feedstock production, transport, conversion to fuel, fuel transport, 

storage and retail supply to vehicles. 

Note 3: Natural gas and BioSNG are assumed to be widely used in different end uses, sharing the 

costs of the transmission and distribution infrastructure required. 

20 ECN-E--11-012 

 
An overview of reported biofuel production plant capacities and associated biomass and biofuel 

production costs is provided in Table 5.1. A large share of the production cost comprises the 

biomass cost. It must be noted that the reported figures should be divided by the plant efficiency 

to provide the actual share of biomass cost as part of the production cost. An additional complication is that only a few studies report the integration opportunities for CCS, although these are 

often not substantiated by cost figures, such as CO2 capture or avoidance cost. 

Table 5.1 Plant capacity, biomass and production cost for different biofuels

ody biomass) 

Ethanol Hamelinck Solomon et Eriksson & Range

(from wo & Faaij al. Kjellström

2006 2007 2010

Plant capacity (MWth,in) 400 Not specified 295 295-400

Biomass cost (€/GJ) 3.0 Not specified 3.5 3.0-3.5

Ethanol cost (€/GJ)2 22.0 18.7 19.7-21.5 18.7-22.0

Fischer-Tropsch Yamashita Hamelinck Kreutz et al. Van Vliet et Range

et al. & Faaij al. 

2004 2006 2008 2009 

Plant capacity (MWth,in) 430 400 660 400 400-660

Biomass cost (€/GJ) 1.5 3.0 3.8 1.8-4.6 1.5-4.6

FTL cost (€/GJ)2 13.8-20.8 18.0 2 18 13 1.5 .0-48.5 .8-48.5

BioSNG Gassner & Åhman Carbo et al. Hacatoglu Range

Maréchal et al. 

2009 2010 2010b 2010 

Plant capacity (MWth,in) 150 100 500 400 100-500

Biomass cost (€/GJ) 9.2 4.5 4.0 2.8 2.8-9.2

BioSNG cost (€/GJ)2 16.4-26.9 20.0 13.3 1 13 3.1 .1-26.9

BioDME RENEW Larsson et Clausen et Range

al. al.

2008 20 20 08 10

Plant capacity (MWth,in)

3

 479 500 -601 2,302 479-2,302

Biomass cost (€/GJ) 5.1-7.8 0.9-1.9 4.6 0.9-7.8

BioDME cost (€/GJ)2 16.1-21.0 7.6-12.8 11.9 7.6-21.0

Hydrogen Hamelinck Sarkar & Range

& Faaij Kumar

2006 2010

Plant capacity (MWth,in) 400 456 400-456

Biomass cost (€/GJ) 3.0 2.2 2.2-3.0

H2 cost (€/GJ)2 16.0 7.5 7.5-16.0

1

 Exchange rates: EUR/USD: 1 ; EUR/SEK: 1.0:9.5 

he incremental cost of CO2 capture in case of biomass-to-biofuel conversion processes is gen-

.0:1.3

2

 Production cost 

T

erally low, since a high-purity CO2 stream is readily available for capture. The incremental capture costs are therefore limited to CO2 dehydration and compression, and typically only amount 

6-12 $ per tonne CO2, mainly depending on the CO2 transportation pressure. 

ECN-E--11-012 21 
During the calculation of the total CO2 avoidance cost, the price difference between a biofuel 

he production of BioSNG illustrates what the effect would be of the inclusion of negative 

igure 5.2 demonstrates the effect of the inclusion of negative emission accounting for BioSNG. 

he inclusion of negative emission accounting results in decreasing BioSNG production cost at 

and its fossil fuel counterpart is also taken into account. The IEA Blue Map low-demand scenario foresees gradually decreasing fossil fuel commodity prices in the long-term as a result of 

reduced demand; since a significant part of the demand will be fulfilled with biofuels. This scenario also foresees much higher effective commodity prices due to the inclusion of a CO2 price 

of 175 USD per tonne CO2 in 2050. 

T

emission accounting for the synthesis of biofuels with CO2 capture and storage. During the production of BioSNG through indirect gasification the total carbon content of the inlet stream is 

distributed over the following outlet streams: 40% as BioSNG, 40% in high-purity CO2 stream 

and 20% as flue gas which is vented. The net greenhouse gas emissions on plant level are presumably almost zero. 

F

Starting points are the lower and upper boundary of BioSNG production cost with no CO2 price 

in place, representing an Nth plant and a first-of-a-kind plant, respectively. A natural gas commodity price of 7.5 € per GJ was assumed, while the combustion of natural gas results in a CO2

emission of approximately 55 kg CO2 per GJ if life cycle CO2 emissions are omitted for the sake 

of simplicity. 

T

increasing CO2 prices, and provides an incentive to implement CCS. The use of natural gas is 

also expected to result in increasing costs when CO2 prices increase. This further reduces the 

price gap between natural gas and BioSNG. The total CO2 avoidance cost for an Nth BioSNG 

plant with CCS and inclusion of negative emission accounting therefore amounts approximately 

60 € per tonne CO2, and 205 € per tonne CO2 for a first-of-a-kind plant with CCS. 

0

5

10

15

20

25

30

0 50 100 150 200 250

CO2 price [EUR/ton CO2]

Fuel Cost [EUR/GJ]

BioSNG with CCS @ 26.9 EUR/GJ

BioSNG with CCS @ 13.0 EUR/GJ

Natural Gas @ 7.5 EUR/GJ

Figure 5.2 The effect of negative emission accounting on total production cost for BioSNG

(range 13.0-26.9 EUR/GJ according to Table 3), at a natural gas commodity price 

of 7.5 €/GJ 

22 ECN-E--11-012 

 
It is apparent that the total CO2 avoidance costs will increase at lower natural gas commodity 

prices. If the CO2 price gradually increases to 175 USD per tonne CO2 in 2050 (CO2 price as 

suggested by the IEA Blue Map scenario) and negative emissions would not be accounted for, 

the broad implementation of BioSNG to replace natural gas will take place much slower. The 

latter would imply that the total CO2 avoidance cost for an Nth BioSNG plant with CCS would 

amount approximately 100 € per tonne CO2. The total CO2 avoidance costs associated with 

other biofuel types display similar tendencies when it comes to the inclusion of negative emission accounting. 

ECN-E--11-012 23 
6. Current environmental legislation and pressures 

The production of biofuels is inherently dependent on the demand for biofuels. For environmental and energy security reasons, several countries around the world have implemented policies and measures to enhance the use of biofuels. Initial biofuel policies mainly pursued blending of bioethanol and biodiesel with their fossil equivalents (IEA Bioenergy, 2009a). These 

policies mainly involved obligatory measures as well as tax breaks and subsidies. Since then 

policies gradually expanded towards flexible vehicles that are able to run on a range of fossil/biofuel blends, and the introduction of fuel standards for bioethanol and biodiesel. Moreover, 

overall biofuel targets and minimum annually required volumes were set. 

There are a number of regions in the world that have taken steps to encourage the use of biofuels in transportation fuels, primarily through mandating a certain percentage of biomass-derived 

fuel to be blended with conventional fossil fuels. Policies which mandate ethanol blending, currently in Brazil and the US, have been designed for the purposes of energy security rather than 

efforts to reduce CO2 emissions from transport. Policies primarily involve promoting 1st generation biofuels, which in addition to exhibiting variable greenhouse gas emission savings of between 20% to 70%, (Concave, 2008), have been criticized on various aspects from effecting 

grain and livestock prices, to the greenhouse gas emissions stemming from land-use change for 

biomass cultivation. 

Table 6.1 provides an overview of blending mandates, biofuel targets and required volumes per 

country. The non-OECD nations that have established biofuel policies are generally countries 

that either produce biofuels or biofuel feedstock. The main driver for developing these policies 

is usually energy security as opposed to climate change mitigation. Other countries did not 

mandate blends; define targets or required volumes, but created incentives to increase the biofuel production, such as Mexico, Guatemala, El Salvador Malaysia and Indonesia. 

24 ECN-E--11-012 

 
Table 6.1 Overview per country of blending mandates, biofuels targets and volumes required 

(Jank et al., 2007; Bringezu et al., 2009; Jumbe et al., 2009; Eisentraut, 2010)

Blending mandates Biofuel targets Volumes required per year 

Bioethanol Biodiesel Biofuels total Bioethanol Biodiesel 

Argentina E5 B5 

Australia 

Belgium 5.75% 

Bolivia B20 (2015) 

Brazil E22-E25 B5 (2013) 

Canada E5 B2 (2012) 

China E10 (9 provinces) 13 bl (2020) 

Columbia E10 B5 2.5 bl (2013) 

Croatia 5.75% 

Dominican 

Rep. 

E15 (2015) B2 (2015) 

EU Total 10% (2020) 

France 10% (2015) 

Germany 12-15% (2020) 1.45 (2020) 8.3 (2020) 

Ghana 20% (2015) 

India E10 (13 states) B5 (10 states) 2.3 bl (2020) 

Italy E1 B1 

Japan 5% (2030) 6 bl (2030) 

Malaysia B5 

New Zealand 3.4% (2012) 

Paraguay B5 

Peru E7.8 B5 

Philippines E10 (2011) B2 (2011) 

Portugal 10% 

South Africa 4.5% (2013) 

Thailand E10 B5 (2011) 10% (2012) 

UK E5 B5 

Uruguay E5 (2014) B5 (2012) 

USA 20% (2022) 130 bl (2022) 

Brazil is the country with the most long-standing biofuel policy, aimed at mainly producing bioethanol from sugarcane, for which the country has excellent climatic conditions. The rationale 

was mainly energy security and foreign currency concerns in the 1970s, when petroleum prices 

soared (IEA Bioenergy, 2009b). The policy employed was a combination of public (including 

World Bank) and private investment in the sugarcane plantation area and a subsidy on the use of 

bioethanol. The subsidy, which reached 2 billion USD in 1996/1997, was complemented by a 

renewable fuel standard of ethanol in petrol (and more recently of biodiesel in diesel, based on 

soybean as a feedstock). Already in the 1980s, a significant number of vehicles produced in 

Brazil ran on pure ethanol. Starting in 2003, the favourable market conditions for biofuels led to 

the adaptation of vehicles that are suitable for both fossil- and bio-based fuels, the so called 

flexcars (Pelkmans et al., 2008). 

Brazil is also the world’s largest exporter of biofuels, mostly to the United States, Europe, Korea and Japan. While export markets are still growing, Brazilian companies continue to build 

new ethanol plants. With an almost 25,000 million litre production of bioethanol in 2008, the 

high-purity CO2 emissions of these ethanol plants could amount to an estimated 19 million tonnes CO2 per year. 

Accepting the limitations of 1st generation biofuels, the US Renewable Fuels Standard (RFS) 

has mandated the blending of 2nd generation biofuels from 2010 onwards. The US has previECN-E--11-012 25 
ously had strong policies to support ethanol production from corn, but with the enactment of the 

RFS, further increases in biofuel production in the next decade is expected occur through the 

use of 2nd generation biofuels. Production of 2nd generation biofuels in the use are expected to 

increase from current negligible amounts to 60.6 billion liters per year in 2020, out of a total 

predicted biofuel production of 136 billion liters per year. 

An alternative for the policy measures addressed in Table 4 is the introduction of low-carbon 

fuel standards. These standards aim at the reduction of the overall lifecycle CO2 emissions of 

transportation fuels. A reduction target is defined and fuel providers can choose their preferred 

method to reduce CO2 emissions, such as biofuel blending, increase refinery efficiencies, capture and storage of CO2 during production, and buying credits from other parties. Low carbon 

fuel standards are seen as more flexible than most of the other policy measures at moderate 

abatement costs. However, an important disadvantage is that fuels could be obtained from unregulated markets or the fuel production could be shifted, which subsequently could hamper the 

energy security and result in CO2 leakage (Yeh and Sperling, 2010). 

Low-carbon fuel standards are being employed in the US RFS and the European Union Renewable Energy Directive (EU RED) and involve the establishment of a minimum GHG emissions 

saving of a biofuel compared to its fossil fuel equivalent. The EU Directive mandates member 

states to enact policies that ensure that second generation biofuels account for a 10% share in 

gasoline and diesel consumption by 2020. This mandate is supplemented by the introduction of 

a biofuel ‘sustainability criteria’. Part of the sustainability criteria, covers the minimum emissions saving to be achieved by biofuels, compared to the gasoline or diesel fuel it replaces. The 

minimum requirement for emissions savings is 35% from 2013, rising to 50% by 2017 and 60% 

by 2018. These mandated emissions savings are comparable to the requirements under the US 

RFS, which states that lifecycle GHG emission savings for 2nd generation (cellulosic) biofuels 

must be 60%, and 50% for biomass-derived diesel2

. 

Of particular interest to the incentives for application of CCS in biofuel production, in the EU 

RED calculation methodology for the GHG emissions from the production and use of biofuels 

and bioliquids, the emissions saving through CCS can be subtracted from the total emissions 

from the use of the fuel. The typical and default greenhouse gas emission savings for various 

biofuel production pathways are presented in Table 6.2. However, given that the future 2nd generation biofuels are expected to be able to reach GHG emissions savings of up to 95% compared 

to fossil fuels, it is unclear whether the minimum emissions savings requirements set by the US 

and EU legislation will warrant the application of CCS for compliance purposes. 

 

2

 Compared to the average baseline emissions of gasoline and diesel in 2005. 

26 ECN-E--11-012 

 
Table 6.2 Estimated typical and default values for future biofuels3

 (EU, 2009) 

 

3

 Not net carbon emissions from land-use change 

ECN-E--11-012 27 
7. Major gaps and barriers to implementation 

CO2 capture and storage from biomass-based industrial sources is a mitigation technology that 

only receives little interest at present. The 4th assessment report of the IPCC (Fischer et al., 

2007) recognized BECCS as a technology that could potentially be the key in pursuit of low atmospheric CO2 concentration stabilization levels. However, the combination of biomass conversion with CCS generally tends to be overlooked by the biomass-based industry, biofuels production sector and CCS communities. From the perspective of the biomass community the acceptance of CCS is generally low, while the focus of the CCS community is on the use of fossil fuels specifically tailored for electricity generation with CCS. Consequently, the number of research papers on biomass conversion with CCS to date only amount approximately one hundred. Furthermore, the technology lacks industrial supports to pursue broad implementation, 

while there is a lack of awareness amongst policy makers. 

Even though the 2006 IPCC Guidelines for National Greenhouse Gas Inventories allow for 

negative emissions to be allocated in national GHG inventories (IPCC, 2006), the concept has 

yet to be transposed into current policy frameworks (IEA, 2009b). An example of that is the 

third phase of the EU Emission Trading System, where the potential inclusion of biomass conversion only involves biomass co-firing during electricity production. Installations that exclusively4

 use biomass as process input stream are excluded from the system. This allows the emission of CO2 without fiscal penalties, although it does not result in financial benefits since CO2

credits are not allocated to these installations. The exclusion from the EU ETS has the potential 

to encourage bio-based industries; however the policy does not recognize the potential of 

achieving ‘negative emissions’ through combination of CCS with biomass conversion processes. In order to incentivize CCS in biomass-based industries, operators that capture and store 

CO2 must be effectively credited for doing so. 

Currently CO2 capture and storage in general is not creditable under the Kyoto Protocol’s Clean 

Development Mechanism (CDM) due to issues around certainty of storage in a temporally constrained crediting mechanism. This has the consequence that the CO2 capture and storage from 

biofuel production also cannot benefit from the carbon price in the CDM. An additional gap for 

developing nations could be that the subsurface CO2 storage potential is generally mapped to a 

lesser extent in comparison with developed nations. 

 

4

 97% 

28 ECN-E--11-012 

 
8. Actions and milestones 

The actions necessary to improve the deployment of CCS with biofuels production must be 

viewed from a broader perspective of demand for alternative transport fuels and energy carriers. 

In distinction between the other sectors covered in the UNIDO Global Technology Roadmap for 

CCS in Industry, the biomass-based sector is small and underdeveloped. Demand for biofuels, 

biogas and other biomass derived products is currently slight, effectively suppressed by conventional fuels such as gasoline, diesel and natural gas which still dominate the market. Furthermore, the technologies to produce biofuels from biotic feedstocks that are less likely to compete 

with food supply, termed 2nd generation biofuels, are at present in development and demonstration stages. Nevertheless, the IEA BLUE Map scenario states that reducing global CO2 emissions by 50% by 2050 will require an intensification of biofuel production, and substantial application of CCS within this emerging sector. An overview of actions is provided in Table 8.1. 

Table 8.1 Summary of actions for CCS deployment with biofuels production 

ACTIONS 

Research 

• Research conducted to develop methods for the inclusion of negative emissions in existing policy mechanisms, such as the EU ETS

• Research conducted to analyze the impact that negative emissions could have on the 

global carbon market

• Continued research into biomass-to-liquid technologies, the gasification of biomass for 

the production of 2nd generation biofuels 

• Research networks established 

Technological development 

• Demonstration activities and scale-up of biomass gasification to continue

• Demonstration plant for gasification of biomass with CCS by 2015

• Expansion of demonstration plants for bioethanol production with CCS

Policy 

• Policies that increase the demand for biomass-based products must continue to by 

implemented in developed and developing countries 

• Biomass with CCS must be recognized by governments as a potential cost-effective 

abatement option, and incorporated into future policies relating to CCS deployment in

general 

• A BECCS stakeholder network should be formed, to facilitate more effective lobbying 

for the technology

One of the first actions to be undertaken in the near future is the formation of a BECCS stakeeanwhile, more detailed scientific studies are needed on costs, long-term contribution on 

achieve a substantial contribution of biomass-based industrial CO2 capture and storage by 2050. 

holder network. This requires mobilization of all relevant entities: policy makers, NGO’s, scientific community and industry champions. The involvement of bodies such as the IEA, UNIDO 

and GCCSI is considered to be essential in the formation of such a network. Other early movers 

are nations that could have a short-term interest in application, such as Brazil, Sweden, the USA 

and Indonesia. This network increases awareness amongst stakeholders and potentially facilitates the establishment of policies aiming at BECCS deployment. 

M

GHG reduction and early opportunities. Furthermore a dedicated BECCS pilot and demonstration programme should be facilitated by policy makers. All the above measures are required to 

ECN-E--11-012 29 
9. References 

Åhman, M., 2010, “Biomethane in the transport sector-An appraisal of the forgotten option,” 

Energy Policy, 38, 208-217. 

Azar, C., Lindgren, K., Larson, E.D. and Möllersten, K., 2006, “Carbon capture and storage 

from fossil fuels and biomass – Costs and potential role in stabilizing the atmosphere,” 

Climatic Change, 74, 47-79. 

Bacovsky, D., Dallos, M. and Wörgetter, M., 2010, “Status of 2nd generation biofuels demonstration facilities in June 2010,” Report no. T39-P1b, IEA Bioenergy Task 39 Liquid fuels 

from biomass. 

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