CO2 Avoided Research Articles

Technical and economic prospects of coal- and biomass-fired integrated gasification facilities equipped with CCS over time

This study analyses the impacts of technological improvements and increased operating experience on the techno-economic performance of integrated gasification (IG) facilities. The facilities investigated produce electricity (IGCC) or FT-liquids with electricity as by-product (IG–FT).Results suggest that a state-of-the-art (SOTA) coal-fired IGCC without CO2 capture has electricity production costs of 17€/GJ (60€/MWh) with the potential to decrease to 11€/GJ (40€/MWh) in the long term. Specific direct CO2 emissions may drop from about 0.71kgCO2/kWh to 0.59kgCO2/kWh. If CO2 is captured, production costs may increase to 23€/GJ (83€/MWh), with the potential to drop to 14€/GJ (51€/MWh) in the long term. As a result, CO2 avoidance costs would decrease from 35€/t CO2 to 18€/t CO2. The efficiency penalty due to CCS may decrease from 8.8%pt to 3.7%pt.CO2 emissions can also be reduced by using torrefied biomass (TOPS) instead of coal. Production costs of a SOTA TOPS-fired IGCC without CO2 capture are 18–25€/GJ (64–92€/MWh). In the long term, this may drop to 12€/GJ (44€/MWh), resulting in CO2 avoidance costs of 7€/t CO2. The greatest reduction in anthropogenic CO2 emissions is obtained by using biomass combined with carbon capture and storage (CCS). A SOTA TOPS-fired IGCC with CCS has, depending on the biomass price, production costs of 25–35€/GJ (91–126€/MWh) with CO2 avoidance costs of 19–40€/t CO2. These values may decrease to 15€/GJ (55€/MWh) and 12€/t CO2 avoided in the long term. As carbon from biomass is captured, specific direct CO2 emissions are negative and estimated at −0.93kgCO2/kWh for SOTA and −0.59kgCO2/kWh in the long term. Even though more carbon is sequested in the future concepts, specific emissions drop due to an increase in the energetic conversion efficiency of the future facilities.New technologies in IG-FT facilities have a slightly smaller impact on production costs. In the long term, production costs of FT-liquids from coal may drop from 13€/GJ to 9€/GJ if CO2 is vented and from 15€/GJ to 10€/GJ if CCS is applied. The use of TOPS results in 15–23€/GJ (Vent) and 17–24€/GJ (CCS) for SOTA facilities. These production costs may drop to 11–18€/GJ (Vent) and 12–19€/GJ (CCS) in the long term. Contrary to the IGCC cases, the coal-fired IG-FT facility shows the lowest CO2 avoidance costs. The CO2 emission of coal to FT-liquids with CCS is, however, similar to gasoline/diesel production from crude oil.

Economic feasibility and sensitivity analysis of integrating industrial-scale mineral carbonation into mining operations

Proposed carbon reduction measures—such as cap-and-trade—appear poised to have a significant impact on the financial feasibility of mining operations as point-source emitters of carbon dioxide (CO2). It is therefore necessary to proactively assess the ways in which these effects may be mitigated. Carbon sequestration through mineral carbonation is well suited for integration into mining operations. Its ability to make use of waste rock to trap and store CO2, given suitable geological conditions, can help to significantly reduce carbon emissions. This paper presents the first attempt at conceptually integrating a high temperature and pressure industrial mineral carbonation facility into a developing minesite. The Turnagain nickel site, a low-grade, high-tonnage Ni-sulphide deposit, located in Northern BC, contains an abundant amount of Mg–silicate minerals in its waste rock. These minerals have significant potential for use in mineral carbonation. In the presence of a mandatory cap-and-trade scheme in North America, there is the potential to produce an additional revenue stream through the generation and sale of carbon credits. Results of financial modeling have yielded a net present value (NPV) at an 8% discount rate of $131.5million for the integration of mineral carbonation into proposed mining operations at Turnagain, suggesting that the project may be viable from a financial standpoint. Sensitivity analysis has also demonstrated that the parameter with the greatest influence on project NPV is the CO2 avoidance ratio. This ratio, which takes into consideration the amount of CO2 released in the mineral carbonation process to determine the net amount of CO2 avoided, is critical to maximizing the amount of carbon credits available for sale in a cap-and-trade environment.

Techno‐economic analysis of a 300 MWe coal‐fired power plant retrofitted with post‐combustion CO2 capture

ABSTRACTTo evaluate the integrated system which post‐combustion capture was combined with a typical Chinese coal‐fired power plant and investigate the effect of coal ranks on techno‐economic analysis of the retrofitted power plant, the retrofitted power plant with post‐combustion CO2 capture (MEA) process and the economic performance were analysed using an Aspen Plus software and a cash flow model in this study (Aspen Technology Inc, 2001). The results indicated that the net power outputs of the retrofitted power plant dropped from 302.62 to 249.45 MWe for lignite, 254.97 MWe for bituminous coal and 249.90 MWe for anthracite, respectively. For three cases, the net efficiencies decreased about 7%. The cash flow model was also used for economic analysis. The annual cost of the total retrofitted power plant (CT) increased from 80.6 M$ /year to 87.5 M$ /year for lignite, 90.8 M$ /year for bituminous coal and 88.8 M$ /year for anthracite, respectively. The cost of power generation (CCOE) increased to 48.7 $ /MWh for lignite, 50.5 $ /MWh for bituminous coal and 48.4 $ /MWh for anthracite, respectively. There were significant effects of different coal ranks on the techno‐economic performance. The costs of CO2 avoided (CAVOID) for lignite, bituminous coal and anthracite were estimated to be 15.0 $ /tonne, 19.6 $ /tonne and 15.2 $ /tonne, respectively. © 2011 Curtin University of Technology and John Wiley & Sons, Ltd.

Scope for reductions in the cost of CO2 capture using flue gas scrubbing with amine solvents

A previous IEA GHG study of CO2 capture from a pulverized coal (PC) power plant using an amine solvent for flue gas scrubbing has been used as the basis for calculations of the reductions in electricity and CO2 avoidance costs that might be achievable through improved thermodynamic integration between the CO2 capture plant and the steam cycle, the use of a solvent with lower regeneration energy requirements and solvent storage to allow rapid load changes and electricity ‘storage’. It was predicted that the efficiency penalty for CO2 capture for PC plant with flue gas scrubbing using an amine solvent can be reduced to 20 per cent (from 28 per cent) with improved thermodynamic integration and lower-energy solvent, giving a 10 per-cent reduction in electricity costs, from $63.5/MW h to $57.4/MW h, and a 25 per cent reduction in the cost of CO2 avoid from $45/t to $34/t. These values are both lower than predictions for the gasifier-based coal power plant in the original IEA GHG study. Reductions in the average cost of electricity of 6–7 per cent were estimated using solvent storage, giving a cost of electricity of $56.73/MW h and $33/t CO2 avoided for an integrated plant with monoethanolamine (MEA) as the solvent. Also, CO2 venting would allow an additional 20-25 per cent increase in output to be maintained indefinitely when $/MW h electricity prices were 2–3 times greater than the $/t penalty for CO2 discharges.