Although a major factor in new CCUS investment plans in the United States, the Section 45Q tax credit alone is not expected to be sufficient to close the commercial gap to enable an operator to retrofit carbon capture facilities to a coal- or gas-fired power plant. However, it could be layered with complementary measures for early projects, including capital grants. Analysis by Friedmann et al. found that, while revenue enhancements may provide the lowest risk and best chance to accelerate the deployment of carbon capture, especially for gas plants, capital treatments are expected to provide better support for coal retrofits due to their capital intensity and scale.1

The Section 48A credit currently requires plants to have improved efficiency after retrofit, which is very challenging when incorporating carbon capture into existing plants due to the energy needs of the capture facility. Proposed amendments contained in the Carbon Capture Modernization Act would enable CCUS retrofits to coal plants to be eligible for the tax credit by addressing the requirement for plants to have greater efficiency after retrofit.

The three main carbon capture routes – post-, pre- and oxyfuel combustion – appear to have a small to negligible impact on the operational flexibility of thermal power plants, provided that the capture systems are designed properly. In fact, post- and pre-combustion capture applications could potentially increase the ramp rate and lower the minimum stable operating load if the capture system and power block are operated independently. Oxyfuel combustion applications, however, may impose additional constraints on the power plant’s flexibility in the absence of oxygen storage, due to the inertia of the oxygen production plant required for the capture process.

There are several techniques to enhance flexibility. Oxyfuel power plants could temporarily switch back to conventional air-firing mode, while power plants equipped with post- or pre-combustion systems could (partly) bypass the capture units. These options can help to temporarily boost power output as less or no energy is required for the capture process, although CO₂ would be vented to the atmosphere. Other flexibility options involve storage of oxygen (oxyfuel combustion), hydrogen (pre-combustion) or solvents (post-combustion), which enable the carbon capture process to continue during transient operation. While these storage requirements may entail slightly higher capital and operational costs, enhanced flexibility capabilities can also increase electricity sale revenues by boosting power output when electricity prices are high (arbitrage).2

Biomass co-firing with coal: Under this process, plant operators directly or indirectly add biomass to the combustion of coal.

Direct co-firing is a commercial technology that blends, mills and burns biomass with coal, or grinds it in a biomass mill or modified coal mill and then blends it with pulverised coal. The blended substance is either fed into the burners directly or through a dedicated biomass burner, or injected directly into the boiler.

The maximum share of biomass is relatively limited for direct co-firing in existing pulverised coal boilers without modifications, typically around 10-30%, due to prohibitively high maintenance costs and operating expenditure at shares higher than this. For newly built plants, these costs can be reduced through appropriate design and planning.

Indirect co-firing involves converting biomass in a dedicated fluidised bed gasifier that produces a combustible gas with low calorific value, which can be injected into the boiler of an existing coal power plant.

Whether using direct or indirect biomass co-firing, the higher the ratio of biomass to coal, the lower the CO₂ emissions emitted. The possible ratios depend on the characteristics of the biomass and the power plant design. Achieving elevated co-firing ratios has proved difficult for several reasons, including the fact that biomass has lower energy density and a different inorganic composition to hard coal, is vulnerable to biodegradation and is hydrophilic in nature.

Power plant modifications are often necessary to accommodate biomass, which requires investment and incurs higher costs. Investment costs for biomass co-firing are inherently site-specific and it is difficult to find reliable cost data. We estimate them to range between USD 700 per kilowatt (kW) and USD 1 000/kW for direct co-firing and USD 3 300/kW to USD 4 400/kW for indirect co-firing. To overcome these challenges and significantly increase the biomass co-firing share, certain plants are using thermal pretreatment technologies that increase the homogeneity, brittleness and/or energy density of biomass.

Dedicated biomass firing: It is possible to operate power plants exclusively using biomass. This typically takes place in purpose-built biomass plants, in modified pulverised coal boilers or in co-generation plants previously fired with coal or lignite, often using circulating fluidised bed (CFB) combustion technology.

CFB has the advantage of being flexible with regard to the biomass feedstock. CFB plants are usually smaller than utility boilers and are typically located in close proximity to urban areas or industrial facilities in order to supply heat. The size of dedicated biomass plants is limited by the availability of biomass and the transport costs associated with the feedstock.

The cost of converting a coal plant to biomass firing varies substantially. Costs are estimated to be around USD 600/kW for plant conversion using wood pellets and about USD 1 700/kW using wood chips. A recent example of an operator converting a coal-fired power plant to biomass is the Drax bioenergy plant in the United Kingdom, where they converted four 600 MW coal boilers to use biomass. In addition, in 2019 they started a project to capture1 tCO₂/day, with a second pilot project capturing 0.3 tCO₂/day to commence in Q3 2020.

The same capture technologies that are available to coal combustion power plants are also suitable for biomass co-firing and dedicated biomass firing, i.e. post-combustion capture or oxy-fuel combustion capture. We do not anticipate co-firing biomass to have a significant impact on post-combustion capture.

Biomethane for power generation: Biomethane obtained from fermentation and upgraded by CO₂ separation (and storage) or gasification-based biosynthetic natural gas can be used as fuel in gas-fired power technologies. One of the benefits is that there are virtually no co-firing ratio limitations; however, the availability of biogas may ultimately restrict its role in power generation. Additional costs for carbon capture technologies due to the use of biomass are limited, as conventional post-combustion capture technology can be applied.

Biomass gasification: Gasifying biomass allows a wide variety of biomass feedstocks to be used. We estimate the efficiency of dedicated biomass in integrated gasification combined‑cycle plants to be in the 35-44% range for plant sizes up to about 250 MW_e. There are currently no commercial integrated biomass gasification with CCUS facilities in operation. Pre-combustion capture technology is currently considered the most promising option for biomass gasification, offering the potential to benefit from experiences gained from fossil-fuelled integrated gasification combined‑cycle power plants with pre-combustion capture.3

Assuming strong climate ambition, long-term analysis of the energy system shows the CO₂ intensity of the global power sector becoming negative sometime around 2050. However, with a CO₂ capture rate of 85% (a rate commonly assumed in modelling) and an efficiency of 41%, a hard coal power plant with post-combustion CO₂ capture still emits 125 gCO₂/kWh. Oxy-fuelled CO₂ capture emits 83 gCO₂/kWh at a typically assumed capture rate of 90% and the same efficiency.

Therefore, in the long term, for fossil‑fuelled power plants with carbon capture technologies to play a role in a fully decarbonised power system, the sector needs to address these residual emissions. Increasing the capture rate is one way to reduce the remaining emissions and thus increase the attractiveness of fossil-fuelled power plants with carbon capture technologies.

From a technical perspective, higher capture rates are possible. Already today, the Petra Nova CCUS project captures as much as 95% of the CO₂ from the flue gas slipstream that it processes. Capture rates at post-combustion plants can be raised by increasing the CO₂ absorption capacity. This can be done by using a leaner absorber solvent, that is the regenerated solvent entering the absorber has a lower CO₂ concentration. This requires more energy for regeneration, faster solvent recirculation between the absorber and desorber columns, and higher or more absorbent columns.

Oxy-fuelled power plants could theoretically achieve a capture rate of 100%. Technically, the capture rate can be increased by removing CO₂ through an additional scrubbing step from vent streams leaving the plant. For pre-combustion capture plants, that is integrated gasification combined‑cycle coal power plants, a 100% capture rate cannot be realised due to equilibrium conditions in the physical absorption process. The IEAGHG highlights that the capture rate can be raised by increasing the conversion rate of carbon monoxide to CO₂ in the shift reaction after gasification and by increasing the CO₂ absorption capacity of the CO₂ capture unit in the same way as for the post-combustion system.

The IEAGHG suggests that CO₂ capture rates as high as 99.7% can be achieved at low additional marginal cost in coal- and gas-fired power plants equipped with carbon capture technologies. More specifically, an ultra-supercritical pulverised coal plant can be made CO₂ neutral (99.7% capture) at a 7% electricity generation cost increase over the usual 90% capture rate with only a 3% increase in CO₂ avoided cost. (Note that carbon neutrality means that the power plant only emits the amount of CO₂ present in the incoming combustion air.)

The most economical option to achieve a carbon-neutral ultra-supercritical coal plant may be co-combusting 10% biomass at 90% CO₂ capture. This would increase the CO₂ avoided cost by only 1.5% to around USD 62/tCO₂.

A natural gas-fired combined-cycle plant can theoretically be made CO₂ neutral (99% capture). Compared to the usual 90% capture rate, the electricity generation cost increases by 7% and the cost of CO₂ avoided by 8%.