Systems Analysis of Physical Absorption of CO2 in Ionic Liquids for Pre-Combustion Carbon Capture.

This study develops an integrated technical and economic modeling framework to investigate the feasibility of ionic liquids (ILs) for precombustion carbon capture. The IL 1-hexyl-3-methylimidazolium bis(trifluoromethylsulfonyl)imide is modeled as a potential physical solvent for CO2 capture at integrated gasification combined cycle (IGCC) power plants. The analysis reveals that the energy penalty of the IL-based capture system comes mainly from the process and product streams compression and solvent pumping, while the major capital cost components are the compressors and absorbers. On the basis of the plant-level analysis, the cost of CO2 avoided by the IL-based capture and storage system is estimated to be $63 per tonne of CO2. Technical and economic comparisons between IL- and Selexol-based capture systems at the plant level show that an IL-based system could be a feasible option for CO2 capture. Improving the CO2 solubility of ILs can simplify the capture process configuration and lower the process energy and cost penalties to further enhance the viability of this technology.

A Techno-Economic Assessment of Hybrid Cooling Systems for Coal- and Natural-Gas-Fired Power Plants with and without Carbon Capture and Storage.

Advanced cooling systems can be deployed to enhance the resilience of thermoelectric power generation systems. This study developed and applied a new power plant modeling option for a hybrid cooling system at coal- or natural-gas-fired power plants with and without amine-based carbon capture and storage (CCS) systems. The results of the plant-level analyses show that the performance and cost of hybrid cooling systems are affected by a range of environmental, technical, and economic parameters. In general, when hot periods last the entire summer, the wet unit of a hybrid cooling system needs to share about 30% of the total plant cooling load in order to minimize the overall system cost. CCS deployment can lead to a significant increase in the water use of hybrid cooling systems, depending on the level of CO2 capture. Compared to wet cooling systems, widespread applications of hybrid cooling systems can substantially reduce water use in the electric power sector with only a moderate increase in the plant-level cost of electricity generation.

Opportunities for Decarbonizing Existing U.S. Coal-Fired Power Plants via CO2 Capture, Utilization and Storage.

This study employs a power plant modeling tool to explore the feasibility of reducing unit-level emission rates of CO2 by 30% by retrofitting carbon capture, utilization, and storage (CCUS) to existing U.S. coal-fired electric generating units (EGUs). Our goal is to identify feasible EGUs and their key attributes. The results indicate that for about 60 gigawatts of the existing coal-fired capacity, the implementation of partial CO2 capture appears feasible, though its cost is highly dependent on the unit characteristics and fuel prices. Auxiliary gas-fired boilers can be employed to power a carbon capture process without significant increases in the cost of electricity generation. A complementary CO2 emission trading program can provide additional economic incentives for the deployment of CCS with 90% CO2 capture. Selling and utilizing the captured CO2 product for enhanced oil recovery can further accelerate CCUS deployment and also help reinforce a CO2 emission trading market. These efforts would allow existing coal-fired EGUs to continue to provide a significant share of the U.S. electricity demand.

Techno-economic assessment of polymer membrane systems for postcombustion carbon capture at coal-fired power plants.

This study investigates the feasibility of polymer membrane systems for postcombustion carbon dioxide (CO(2)) capture at coal-fired power plants. Using newly developed performance and cost models, our analysis shows that membrane systems configured with multiple stages or steps are capable of meeting capture targets of 90% CO(2) removal efficiency and 95+% product purity. A combined driving force design using both compressors and vacuum pumps is most effective for reducing the cost of CO(2) avoided. Further reductions in the overall system energy penalty and cost can be obtained by recycling a portion of CO(2) via a two-stage, two-step membrane configuration with air sweep to increase the CO(2) partial pressure of feed flue gas. For a typical plant with carbon capture and storage, this yielded a 15% lower cost per metric ton of CO(2) avoided compared to a plant using a current amine-based capture system. A series of parametric analyses also is undertaken to identify paths for enhancing the viability of membrane-based capture technology.

The cost of carbon capture and storage for natural gas combined cycle power plants.

This paper examines the cost of CO(2) capture and storage (CCS) for natural gas combined cycle (NGCC) power plants. Existing studies employ a broad range of assumptions and lack a consistent costing method. This study takes a more systematic approach to analyze plants with an amine-based postcombustion CCS system with 90% CO(2) capture. We employ sensitivity analyses together with a probabilistic analysis to quantify costs for plants with and without CCS under uncertainty or variability in key parameters. Results for new baseload plants indicate a likely increase in levelized cost of electricity (LCOE) of $20-32/MWh (constant 2007$) or $22-40/MWh in current dollars. A risk premium for plants with CCS increases these ranges to $23-39/MWh and $25-46/MWh, respectively. Based on current cost estimates, our analysis further shows that a policy to encourage CCS at new NGCC plants via an emission tax or carbon price requires (at 95% confidence) a price of at least $125/t CO(2) to ensure NGCC-CCS is cheaper than a plant without CCS. Higher costs are found for nonbaseload plants and CCS retrofits.

Water use at pulverized coal power plants with postcombustion carbon capture and storage.

Coal-fired power plants account for nearly 50% of U.S. electricity supply and about a third of U.S. emissions of CO(2), the major greenhouse gas (GHG) associated with global climate change. Thermal power plants also account for 39% of all freshwater withdrawals in the U.S. To reduce GHG emissions from coal-fired plants, postcombustion carbon capture and storage (CCS) systems are receiving considerable attention. Current commercial amine-based capture systems require water for cooling and other operations that add to power plant water requirements. This paper characterizes and quantifies water use at coal-burning power plants with and without CCS and investigates key parameters that influence water consumption. Analytical models are presented to quantify water use for major unit operations. Case study results show that, for power plants with conventional wet cooling towers, approximately 80% of total plant water withdrawals and 86% of plant water consumption is for cooling. The addition of an amine-based CCS system would approximately double the consumptive water use of the plant. Replacing wet towers with air-cooled condensers for dry cooling would reduce plant water use by about 80% (without CCS) to about 40% (with CCS). However, the cooling system capital cost would approximately triple, although costs are highly dependent on site-specific characteristics. The potential for water use reductions with CCS is explored via sensitivity analyses of plant efficiency and other key design parameters that affect water resource management for the electric power industry.

Regulating the geological sequestration of CO2.

Governments worldwide should provide incentives for initial large-scale GS projects to help build the knowledge base for a mature, internationally harmonized GS regulatory framework. Health, safety, and environmental risks of these early projects can be managed through modifications of existing regulations in the EU, Australia, Canada, and the U.S. An institutional mechanism, such as the proposed Federal Carbon Sequestration Commission in the U.S., should gather data from these early projects and combine them with factors such as GS industrial organization and climate regime requirements to create an efficient and adaptive regulatory framework suited to large-scale deployment. Mechanisms to structure long-term liability and fund long-term postclosure care must be developed, most likely at the national level, to equitably balance the risks and benefits of this important climate change mitigation technology. We need to do this right. During the initial field experiences, a single major accident, resulting from inadequate regulatory oversight, anywhere in the world, could seriously endanger the future viability of GS. That, in turn, could make it next to impossible to achieve the needed dramatic global reductions in CO2 emissions over the next several decades. We also need to do it quickly. Emissions are going up, the climate is changing, and impacts are growing. The need for safe and effective CO2 capture with deep GS is urgent.

Technology innovations and experience curves for nitrogen oxides control technologies.

This paper reviews the regulatory history for nitrogen oxides (NOx) pollutant emissions from stationary sources, primarily in coal-fired power plants. Nitrogen dioxide (NO2) is one of the six criteria pollutants regulated by the 1970 Clean Air Act where National Ambient Air Quality Standards were established to protect public health and welfare. We use patent data to show that in the cases of Japan, Germany, and the United States, innovations in NOx control technologies did not occur until stringent government regulations were in place, thus "forcing" innovation. We also demonstrate that reductions in the capital and operation and maintenance (O&M) costs of new generations of high-efficiency NOx control technologies, selective catalytic reduction (SCR), are consistently associated with the increasing adoption of the control technology: the so-called learning-by-doing phenomena. The results show that as cumulative world coal-fired SCR capacity doubles, capital costs decline to approximately 86% and O&M costs to 58% of their original values. The observed changes in SCR technology reflect the impact of technological advance as well as other factors, such as market competition and economies of scale.

Effect of government actions on technological innovation for SO2 control.

The relationship between government actions and innovation in environmental control technology is important for the design of cost-effective policies to achieve environmental goals. This paper examines such relationships for the case of sulfur dioxide control technology for U.S. coal-fired power plants. The study employs several complementary research methods, including analyses of key government actions, technology patenting activity, technology performance and cost trends, knowledge transfer activities, and expert elicitations. Our results indicate that government regulation appears to be a greater stimulus to inventive activity than government-sponsored research support alone, and that the anticipation of regulation also spurs inventive activity. Regulatory stringency focuses this activity along particular technical pathways and is a key factor in creating markets for environmental technologies. We also find that with greater technology adoption, both new and existing systems experience notable efficiency improvements and capital cost reductions. The important role of government in fostering knowledge transfer via technical conferences and other measures is also seen as an important factor in promoting environmental technology innovation.

A technical, economic, and environmental assessment of amine-based CO2 capture technology for power plant greenhouse gas control.

Capture and sequestration of CO2 from fossil fuel power plants is gaining widespread interest as a potential method of controlling greenhouse gas emissions. Performance and cost models of an amine (MEA)-based CO2 absorption system for postcombustion flue gas applications have been developed and integrated with an existing power plant modeling framework that includes multipollutant control technologies for other regulated emissions. The integrated model has been applied to study the feasibility and cost of carbon capture and sequestration at both new and existing coal-burning power plants. The cost of carbon avoidance was shown to depend strongly on assumptions about the reference plant design, details of the CO2 capture system design, interactions with other pollution control systems, and method of CO2 storage. The CO2 avoidance cost for retrofit systems was found to be generally higher than for new plants, mainly because of the higher energy penalty resulting from less efficient heat integration as well as site-specific difficulties typically encountered in retrofit applications. For all cases, a small reduction in CO2 capture cost was afforded by the SO2 emission trading credits generated by amine-based capture systems. Efforts are underway to model a broader suite of carbon capture and sequestration technologies for more comprehensive assessments in the context of multipollutant environmental management.