Fangwei Cheng

Direct air capture (DAC) of carbon dioxide (CO2) is energy intensive given the low concentration ( 0.1%) of CO2 in ambient air, but offers relatively strong verification of removals and limited land constraints to scale. Lower temperature solid sorbent based DAC could be coupled on-site with low carbon thermal generators such as nuclear power plants. Here, we undertake a unique interdisciplinary study combining process engineering with a detailed macro-energy system optimization model to evaluate the system-level impacts of such plant designs in the Texas electricity system. We contrast this with using grid power to operate a heat pump to regenerate the sorbent. Our analysis identifies net carbon removal costs accounting for power system impacts and resulting indirect CO emissions from DAC energy consumption. We find that inefficient configurations of DAC at a nuclear power plant can lead to increases in power sector emissions relative to a case without DAC, at a scale that would cancel out almost 50% of the carbon removal from DAC. Net removal costs for the most efficient configurations increase by roughly 18% once indirect power system-level impacts are considered, though this is comparable to the indirect systems-level emissions from operating grid-powered heat pumps for sorbent regeneration. Our study therefore highlights the need for DAC energy procurement to be guided by consideration of indirect emission impacts on the electricity system. Finally, DAC could potentially create demand pull for zero carbon firm generation, accelerating decarbonization relative to a world without such DAC deployment. We find that DAC operators would have to be willing to pay existing or new nuclear power plants roughly $30–80/tCO2 or $150–400/tCO2 respectively, for input energy, to enable nuclear plants to be economically competitive in least cost electricity markets that do not have carbon constraints or subsidies for nuclear energy.

In electricity systems with many variable renewables, flexible operation of natural gas combined cycle (NGCC) power plants with carbon capture and sequestration (CCS) can increase their economic value. This study evaluates NGCC-CCS plants with solvent storage for such operation, using a modular modeling framework for accuracy and efficiency. The model divides NGCC-CCS plants into subcomponents, applying linear constraints for energy and mass balances, and addressing unit commitment (UC) constraints in thermal power plants. This approach employs linear relaxation of UC decision variables alongside a generator clustering method for flexible CCS modeling. Integrated into a power system model, it shows the hourly operations of NGCC-CCS and impacts on system performance. The results indicate faster computational times than traditional binary UC methods, with minimal errors. Flexible NGCC-CCS plants reduce operating costs, especially during peak demand, proving beneficial in grids with increasing renewable energy.

The Inflation Reduction Act (IRA) in the U.S. offers significant incentives for low-carbon hydrogen and liquid fuels, impacting their cost-competitiveness by the early 2030s. This study examines the IRA’s effects on producing hydrogen and synthetic liquid fuel from natural gas, electricity, biomass, and ethanol. Findings show that with IRA credits, green hydrogen and blue hydrogen (from natural gas with carbon capture) become cost-competitive with traditional gray hydrogen. Biomass-derived hydrogen isn’t cost-competitive under current IRA provisions. However, if biomass gasification with carbon capture could claim IRA credits, it would be cheaper than gray hydrogen. For synthetic liquid fuels to compete with petroleum fuels, the IRA’s clean fuels credit, ending in 2027, requires extension or additional policy support. The subsidies per unit of CO2 mitigated for these pathways, except electricity-derived synthetic fuel, range from $65 to $384 per ton, within or below U.S. estimates of the social cost of carbon for 2030–2040.

This study examines the environmental and economic viability of different fuel production methods as part of U.S. net-zero greenhouse gas emission strategies. It conducts lifecycle assessments for hydrogen (H2), synthetic natural gas (SNG), and Fischer-Tropsch liquid (FTL) fuels, considering three sources: biomass with carbon capture and storage (CCS), natural gas with CCS, and renewable electricity. The study finds that hydrogen production, especially from biomass with CCS, is more cost-effective and efficient in reducing greenhouse gas emissions than FTL and SNG. Sensitivity analysis reveals the significant impact of capital costs and capacity factors on the levelized costs of carbon mitigation (LCCM), with natural gas-based processes being particularly sensitive to feedstock price changes. Biomass-based fuels with CCS show the highest potential for carbon mitigation and become increasingly cost-effective at higher carbon pricing. These results emphasize the critical importance of biomass-based hydrogen production with CCS in achieving U.S. net-zero emissions goals.