Toward Carbon-Negative Power Plants With Biomass Cofiring and CCS

By Janne Kärki
Research Team Leader, VTT Technical Research Centre of Finland
Antti Arasto
Business Development Manager,
VTT Technical Research Centre of Finland

The goal of CO2 emissions reductions and renewable energy incentives have led some power plant operators to broaden their fuel palette to include various carbon-neutral biomass fuels. Biomass can be carbon neutral because it binds carbon from the atmosphere that is then released when it is burned, minimizing net emissions.

Carbon capture and storage (CCS), another potential option to cut CO2 emissions from the power sector, is currently under extensive research, development, and demonstration globally. CCS is advancing toward commercialization, but there are still hurdles, mostly nontechnical, that are impeding its widespread deployment.

Greenhouse gas emission reduction targets are expected to be higher in the future and, therefore, the power sector and several other major industries may need solutions that can offer up to 80% reductions in emissions. In large-scale thermal power plants, this level of emissions reduction can be achieved by employing CCS, utilizing high shares of biomass fuels, or a combination thereof. By combining biomass cofiring and CCS, it is possible to achieve negative emissions (defined as capturing CO2 from biomass combustion and storing it permanently isolated from the atmosphere). This is one of the few large-scale options to remove CO2 from the atmosphere, which highlights the importance of these technologies. However, such technologies require stronger government and international support to encourage deployment. In addition, increased costs for CO2 emissions or CO2 emission performance standards (EPS) could help advance the technology.1–3

In locations where sustainable biomass is readily available, cofiring with coal harnesses the advantages of each fuel.

In locations where sustainable biomass is readily available, cofiring with coal harnesses the advantages of each fuel.


Cofiring of coal and various types of biomass is now a mature technology and is currently being successfully practiced globally. With technological advances, many limitations associated with it have been overcome. Many coal-fired plants have been converted or retrofitted to accommodate cofiring with limited impact on efficiency, operations, or lifespan.

However, there is much more to cofiring than simply adding a secondary fuel. Boiler technology and design remain critical issues when evaluating the maximum share of biomass that can be used without compromising boiler performance (output, efficiency, and power-to-heat ratio) or the lifetime of the boiler components.4

Various technologies have been developed to enable cofiring biomass with coal in pulverized coal (PC) boilers. The vast capacity of existing PC boilers offers great potential for increasing biomass utilization and economic benefits compared to new stand-alone biomass power plants, which also are usually significantly smaller than PC plants. With cofiring, capital costs are increased only marginally, while the high electrical efficiency of large PC boilers and the favorable properties of coal ash can be exploited to reduce the operational risks.

Utilizing biomass in an existing thermal power plant can be accomplished through direct or indirect cofiring. Direct cofiring is the most straightforward, most commonly applied, and lowest-cost concept for partially replacing coal or other solid fossil fuels with biomass. In direct cofiring, biomass and coal are burned together in the same furnace using the same or separate fuel handling and feeding equipment, depending on the biomass, targeted biomass share, and site-specific characteristics. The percentage of biomass that can be successfully employed in direct cofiring is modest, typically about 10%, and the type of biomass is limited mostly to pellet-type fuels. With torrefied biomass, however, higher shares are expected, up to tens of percentages. Indirect cofiring consists of converting the solid biomass to a gas or liquid prior to combustion in the same furnace with the other fuel. This allows for greater amounts of biomass to be used, up to 50%. However, this approach requires greater investment and a larger footprint.5

In general, fluidized bed boilers offer the best fuel flexibility. In a properly designed boiler, biomass fuels can be used with coal in any percentage from 0–100% in circulating fluidized bed (CFB) boilers. The variety of biomass fuel options is increasingly diverse, although the availability of some biomass fuels can be limited. Power plants with high fuel flexibility can adapt to the prevailing fuel market by optimizing the fuel mix.6

One possibility to utilize biomass in existing PC boilers is to convert them into bubbling fluidized bed boilers. These retrofits are routine for the major fluidized bed boiler technology suppliers, and numerous such conversions have been conducted in Europe. For example, at least eight conversions to enable pure biomass combustion have been carried out in Poland since 2008, with capacities from 100–200 MWth.


VTT Technical Research Centre of Finland has conducted several conceptual case studies on the feasibility of CCS and biomass cofiring. In the case study discussed below, the feasibility of a coal-fired oxy-combustion CFB boiler with 99% CO2 capture and storage (Case I) is compared to cofiring large shares of biomass (Case II 70% and Case III 30%, with the balance from coal). These cases are compared to a base-case CFB coal-fired (air-fired, no biomass cofiring, and no CCS) 500-MWfuel greenfield power plant situated in Finland that emits approximately 1.2 million tonnes CO2/year.

The fuel mix affects the plant design, investment required, and operational parameters. The plant fuel input (on an energy basis) and designed steam parameters remain constant in all cases. Therefore, the use of biomass or oxy-combustion increases the required plant investment and operating costs. Additional investment for biomass cofiring is required for biomass handling and feeding equipment, additional loop seal heat exchangers, advanced coarse material removal, more expensive materials for heat transfer surfaces, larger flue gas ducts and fans, extra soot-blowers, and possibly injection of combustion additives. Additional O&M costs include additional chemical and maintenance costs. For the CFB-Oxy-CCS case, the main additional investment involves boiler block modifications, a cryogenic air separation unit (ASU), and a CO2 purification unit (CPU). The greatest impact of CCS on the O&M costs is the efficiency penalty, which in this study was assumed to be eight percentage points. The captured CO2 was assumed to be transported and stored abroad with an overall cost of €12/tonne CO2.7,8 The main assumptions and results, including net electricity output, are provided in Table 1.7,8


The principal goal of the modeling was to evaluate annual cash flows from an investor’s point of view in the three reduced-CO2 emission cases compared with the base case. The assumed fuel purchase prices were €10/MWh for coal and €20/MWh for biomass (based on LHV, including all costs and taxes), €75/MWh for electricity, and a CO2 allowance of €35/tonne [an estimated future price that is higher than EU Emissions Trading Scheme (EU ETS) trading values today]. Peak load utilization rates of the plants were 7500 hours per year. The overall costs (capital and operating) and profits for the four cases are presented in Figure 1.

FIGURE 1. Annual operating costs and overall profits of compared technologies (with default input values) in millions € per year

FIGURE 1. Annual operating costs and overall profits of compared technologies (with default input values) in millions € per year

The differences in electricity production, which can be attributed to the energy penalty in the CCS case, are taken into account as “substitutive electricity”, which enables the comparison of costs rather than annual cash flows, where income from electricity would dominate the chart. From Figure 1 it can be determined that operation of the base-case coal-fired power plant is the only option that is profitable under the economic assumptions made, although Case I with 30% biomass cofiring is relatively close to the base case. Based on the economics and emissions assumed, break-even prices (BEP) for CO2 emission allowances in the EU ETS, at which specific cases become favorable compared to the base case, were calculated. The BEPs were 46, 42, and 39 €/tonne CO2 for CFB-Oxy-CCS, 70% biomass cofiring, and 30% biomass cofiring, respectively. These break-even points are a bit higher than, but generally in line with, estimates presented by Lüschen and Madlener for biomass cofiring with CO2 avoidance cost range of €25–32/tonne.9

Note that if the modeling assumptions change, the model results vary dramatically. The most economical solution is mostly dependent on electricity prices, CO2 and fuel costs, and estimated peak load hours, which are all uncertain. For Finnish thermal power plants with CCS, break-even prices of €70–100/tonne were presented by Teir et al.10 In comparison to these reported values, the CFB-Oxy-CCS case was quite competitive, but this is highly dependent on CO2 transport and storage costs, which were much lower in our estimation.10 In addition, at some locations sufficient biomass may not be logistically or economically available. Similarly, CO2 storage sites are not universally accessible. Therefore, the exact modeling results should not be extrapolated to other regions or situations.

The CO2 emissions in the different cases modeled are presented in Figure 2. Both cases of biomass cofiring as well as the CFB-Oxy-CCS offer significantly reduced emissions. It can be seen that significant emission reductions can be achieved with CCS and high shares of biomass cofiring. Note that for the energy penalty in CFB-Oxy-CCS case, the substitutive electricity production is assumed to be produced by unabated coal-fired power; if the replacement electricity was provided by coal with CCS or some other blend of electricity, the carbon footprint of the oxy-combustion case would be even lower.

FIGURE 2. Categorized CO2 emissions for the four cases modeled in tonnes per year

FIGURE 2. Categorized CO2 emissions for the four cases modeled in tonnes per year

If more aggressive climate policies are enacted in the future, including other targets for renewable energy and other competition for biomass (existing forest industry, targets for liquid biofuels, etc.), a significant increase in biomass prices could result, at least in areas where sustainable biomass availability is limited. Increasing biomass prices would result in coal-fired oxy-combustion with CCS becoming economically advantageous compared to biomass cofiring with large shares.

Based on our results, CFB oxy-combustion with CCS could become more competitive with quite realistic prices for biomass and CO2 in the future. For example, with prices of €24/MWh for biomass, €85/MWh for electricity, and €50/tonne CO2 allowance, the CFB-Oxy-CCS becomes the most profitable case modeled, although all are almost equally competitive.7


The cases discussed thus far reduced CO2 emissions, but did not eliminate them. An opportunity exists, however, for coal/biomass cofiring with CCS to not only eliminate CO2 emissions, but actually offer negative CO2 emissions. This approach could help reach climate targets by offsetting historical emissions and emissions from sectors with expensive or more difficult large-scale emission reductions (e.g., the transportation sector) in the near term. In general, similar solutions are suitable for capturing CO2 from applications utilizing biomass as for fossil fuels. The main differences relate to the different kinds of impurities in the combustion process: ash and flue gas. In principle, there are no technical restrictions for capturing biogenic CO2 via cofiring. However, the current EU ETS does not recognize negative emissions, and thus no economic incentive exists for capturing biogenic CO2 from installations combusting even partly biomass.

Despite fluidized bed technology’s high flexibility regarding the fuels, challenges exist in the case of biomass cofiring. Some of these challenges may be emphasized when CCS is employed at the plant. For example, with oxy-fired fluidized bed boilers even small concentrations of chlorine from the biomass fuel can lead to harmful alkaline and chlorine compound deposits on boiler heat transfer surfaces. This is because of lack of nitrogen in furnace and the components’ increased concentrations as a result of flue gas recirculation.7


There are still technical and economic challenges restricting the application of biomass cofiring and CCS as emission reduction solutions. Both CCS and biomass cofiring offer pros and cons and their potential roles globally as carbon abatement tools are not yet certain. Both technologies must reduce the associated costs prior to widespread deployment.

The major costs associated with CCS result from equipment investment, loss of production due to the CCS energy penalty, and transportation and storage of CO2. First-generation CCS technologies are expected to result in efficiency decreases of eight to 12 percentage points.11 Obviously, significant improvements in reducing the energy penalty would be very helpful for the deployment of the CCS. One potential solution to increase the efficiency (of all plants) is combined heat and power, where over 90% process efficiency is achievable—if a large heat distribution system and relatively continuous heat consumption (or storage) in that system exist.12,13

The costs associated with biomass cofiring are mainly due to the higher prices of biomass fuel in comparison to coal, higher plant investment, and higher O&M costs. The use of biomass increases O&M costs of the cofiring retrofit plant through negative effects on the availability of the boiler (i.e., boiler-related issues cause increased plant downtime) and increased maintenance work and consumables. When considering a retrofit option for biomass, the feasibility of the investment and the willingness to invest are affected also by the remaining lifetime of the plant and the annual operating hours.5,14 An indicative comparison on the CAPEX and operating expenses (OPEX) in coal, biomass, and cofired CFB boiler with and without CCS is presented in Figure 3.

FIGURE 3. An indicative comparison of the CAPEX and OPEX in coal, biomass, and cofired CFB boiler with and without CCS *Without CO2 allowances

FIGURE 3. An indicative comparison of the CAPEX and OPEX in coal, biomass, and cofired CFB boiler with and without CCS
*Without CO2 allowances

The costs for CCS depend heavily not only on the characteristics of the facility and the operational environment but also on the assumptions related to future operation. From an investor’s point of view, the optimal solution depends on multiple factors, electricity and EU ETS prices being the most dominant. As far as capturing biogenic emissions (and achieving negative emissions) from power plants is concerned, the only realistic applications are facilities that cofire biomass with coal and implement CCS. Dedicated biomass-firing plants are not considered to be the optimal sites to apply CCS in the initial phase as these facilities are likely smaller than fossil-fueled facilities and do not currently need to reduce their CO2 emissions. When discussing the biomass cofiring option, one must also address questions related to how availability of biomass affects pricing and the competition for raw material between different users, such as the forest industry and liquid biofuel producers.


The possible and predicted high economic value on CO2 emissions as well as strict emission standards could provide a foundation for the development and deployment of biomass cofiring and CCS as individual or combined technologies. Both options are applicable for existing and new power plants and the technologies have already been demonstrated. Biomass cofiring is the most efficient means of power generation from biomass, and thus offers a CO2 avoidance cost lower than that for CO2 capture from existing power plants—provided reasonably priced carbon-neutral biomass is available. However, future policies on legislation, subsidies, and carbon accounting remain the most vital factors for successful biomass cofiring business.

Economically, the difference between biomass cofiring and CCS varies depending on site-specific circumstances. In general, however, the EU ETS price and electricity prices projected in the near future do not yet make CCS investment feasible. The economic viability of CCS in the EU is heavily dependent on the CO2 allowance price.

There is a path forward for neutral or even negative carbon emissions at power plants that combust coal. For negative net emissions, capturing biogenic emissions is a widely available option; power plants that cofire biomass with coal offer the greatest potential and most straightforward applications. However, the most important factors affecting the deployment of the combined carbon-mitigation technologies include the availability of biomass, coal, and CO2 transportation and storage options as well as the political will (expressed through carbon pricing and recognition of negative emissions) and acceptance of the technologies. In reality, these technologies are already available and nearly ready to be demonstrated and then deployed.


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