Edward S. Rubin

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

Capture and sequestration of CO 2 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 CO 2 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 CO 2 capture system design, interactions with other pollution control systems, and method of CO 2 storage. The CO 2 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 CO 2 capture cost was afforded by the SO 2 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.

Uncovering Earth's virome

Viruses are the most abundant biological entities on Earth, but challenges in detecting, isolating, and classifying unknown viruses have prevented exhaustive surveys of the global virome. Here we analysed over 5 Tb of metagenomic sequence data from 3,042 geographically diverse samples to assess the global distribution, phylogenetic diversity, and host specificity of viruses. We discovered over 125,000 partial DNA viral genomes, including the largest phage yet identified, and increased the number of known viral genes by 16-fold. Half of the predicted partial viral genomes were clustered into genetically distinct groups, most of which included genes unrelated to those in known viruses. Using CRISPR spacers and transfer RNA matches to link viral groups to microbial host(s), we doubled the number of microbial phyla known to be infected by viruses, and identified viruses that can infect organisms from different phyla. Analysis of viral distribution across diverse ecosystems revealed strong habitat-type specificity for the vast majority of viruses, but also identified some cosmopolitan groups. Our results highlight an extensive global viral diversity and provide detailed insight into viral habitat distribution and host–virus interactions.

Coal: Energy for the future

Coal is by far the largest fossil fuel resource in the U.S. with known reserves adequate to meet expected demand without major increases in production cost well beyond the year 2010. In contrast, domestic natural gas, its principal fossil fuel competitor for power generation, is a more limited resource and increases in production cost and decreased availability are projected to occur after the year 2000, thus weakening its ability to compete with coal for power generation in the U.S. Renewable and nuclear energy sources are not expected to displace coal to a major extent during the 1995–2040 time period considered here. For manufacture of liquid and gaseous fuels, coal is projected to become competitive with other resources (petroleum, oil shale and bitumen) in the 2021–2040 time period. Increasingly strict requirements for environmental management of coal-generated waste streams are also anticipated with a growing incentive to reduce CO2 production through increased efficiency. This planning model imposes demanding requirements for conversion of coal to electricity and to clean gaseous and liquid fuels and, thus, for a strategic program of research, development and commercialization to most efficiently utilize coal resources in the 21st century. This review is based on an assessment of DOEs coal research, development, demonstration and commercialization programs for the time period 1995–2040. This assessment was conducted under the auspices of the National Research Council, in response to a request from the Acting Assistant Secretary for Fossil Energy. For the above time period, electric power generation is expected to dominate the use of coal, although a growing production of merchant medium Btu gas and liquid transportation fuels is anticipated during the period 2021–2040. The current DOE coal program emphasizes activities through 2010 and is focused almost exclusively on power generation technologies with small programs on other uses. Funding for many of the latter programs has been reduced significantly in recent years. The present study, with its longer time horizon, proposes an increasing emphasis on clean fuels research and on advanced research that addresses the barriers to higher efficiency in both power generation and fuels production to reduce CO2 emissions. Improvements will also be needed in control of air pollutants and the discharge of solid wastes. The power generation program addresses both near term goals that do not offer significantly higher efficiency, and also more ambitious goals based on combined cycles utilizing high performance gas turbines or fuel cells to potentially provide a 10–15 point increase in efficiency. These increases in efficiency will require extensive RD high temperature air/furnace heat exchanger for indirect fixed systems; hot gas cleanup system for PFBC and for gasification-based systems; high temperature turbine blades compatible with trace impurities that may escape the high temperature gas cleanup system; and high thermal efficiency gasification. Solution of these challenging problems will require a continued program of advanced research and component development. The choice of winners from the large array of technologies will also require augmented use of systems studies and development of realistic commercialization strategies. As natural gas prices rise, production of cleaned coal-based medium Btu gas for use in existing natural gas fueled-combined cycles and for industrial heat becomes economic and could relieve the pressure on the supply of natural gas for other uses. Conversion of this coal-based medium Btu gas to methane (SNG) might follow towards the end of the 2021–2040 time period. For this use, high efficiency oxygen blown-cold gas clean up gasification is needed. At present, however, the DOE gasification program is concentrated on air blown processes specifically aimed at integration with power generation. Production of medium Btu (synthesis gas) will allow concurrent production of hydrogen or Fischer-Tropsch liquids. The use of simplified once through processes with production of electric power from unconverted feed and low value products (such as methane) could bring costs of premium liquid fuels to a level competitive with 25–30

COMPARATIVE ASSESSMENTS OF FOSSIL FUEL POWER PLANTS WITH CO2 CAPTURE AND STORAGE

/bbl imported crude oil (DOE financing basis). Current projections indicated that the price of imported crude oil could be in this range in the 2021–2050 time frame. Direct liquefaction costs, with continued R&D, are believed to be approximately the same as indirect liquefaction, but with 5–10% higher efficiency and correspondingly less production of CO2. Given the long-term nature of opportunities for production of coal-derived gaseous and liquid fuels, DOE has a special role to play in supporting technology development aimed at cost reduction and efficiency improvement for these potentially important uses of coal.

Stochastic modeling of chemical processes

Studies of CO2 capture and storage (CCS) costs necessarily employ a host of technical and economic assumptions regarding the particular technology or system of interest, including details regarding the capture technology design, the power plant or gas stream treated, and the methods of CO2 transport and storage. Because the specific assumptions employed can dramatically affect the results of an analysis, published studies are often of limited value to researchers, analysts and industry personnel seeking results for alternative assumptions or plant characteristics. In the present paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and costs of PC, IGCC and NGCC power plants on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed. In particular, the effects on cost comparisons of higher natural gas prices and differential plant utilization rates are highlighted, along with implications of financing and operating assumptions for IGCC plants. The impacts of CCS energy requirements on plant-level resource requirements and multi-media emissions also are quantified. While some CCS technologies offer ancillary benefits via the co-capture of certain criteria air pollutants, the increases in specific fuel consumption, reagent use, solid wastes and other air pollutants associated with current CCS systems are found to be significant. To properly characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.

The Cost of Carbon Capture and Storage for Natural Gas Combined Cycle Power Plants

Conventional simulation models and process simulators treat the design variables in process calculations deterministically. Such an approach does not take into consideration the implicit and explicit uncertainties typically associated with process flowsheets, especially at the early stages of process development. This paper presents a new stochastic modeling capability implemented in the ASPEN process simulator, which provides a useful tool for design, analysis and decision-making in the face of uncertainties. The use of this new capability is illustrated for simple and complex chemical process flowsheets.

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

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

Integrated Environmental Control Modeling of Coal-Fired Power Systems

20-32/MWh (constant 2007

A Technical, Economic, and Environmental Assessment of Amine-Based CO2 Capture Technology for Power Plant Greenhouse Gas Control

) or

Techno-Economic Assessment of Polymer Membrane Systems for Postcombustion Carbon Capture at Coal-Fired Power Plants

22-40/MWh in current dollars. A risk premium for plants with CCS increases these ranges to