Engineering Papers⌕ Search

SEARCH · Engineering Papers

Results for “Clean Coal”

Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 217 records · Page 12
All sourcesNASA NTRSDOE OSTI
DOE OSTI2020

Enhancement of Optical Efficiency of CSP Mirrors for Reducing O&M Cost via Near-Continuous Operation of Self-Cleaning Electrodynamic Screens (EDS). Final Report

Over the past decade, techno-economical advancements in solar energy systems, particularly the improvement in the conversion efficiency of PV modules made with mono-crystalline silicon solar cells from 12% to 20%, as well as the cost reduction in manufacturing by a factor of about 10%, have made it possible to achieve a levelized cost of electricity (LCOE) in PV plants that is comparable to, or less than, the cost of deriving electricity from fossil fuels. Operating PV plants in mid-latitude sun-belt regions, where the solar irradiance level is highest, provides a high annual energy-yield (kWh/kWp) due to two factors: (1) the availability of predictable high solar irradiance throughout the year with the fewest interruptions in solar flux from clouds and rain, and (2) the increased conversion efficiency of crystalline solar cells, as recombination loss has decreased with increased intensity of the sunlight that illuminates the silicon solar cells. Semi-arid and desert regions, however, are plagued by high atmospheric dust concentrations and frequent sand storms. The deposition of a layer of dust on the optical surfaces of solar collectors such as PV modules and concentrating mirrors reduces the transmission efficiency of sunlight that actually reaches the solar cells or receivers, resulting in high energy-yield soiling loss. There are two major cost components to operating a solar plant: (1) installation costs, and (2) operation-and-maintenance (O&M) costs. There is no fuel cost; hence operating a solar plant in a semi-arid or desert region provides high returns on investment if soiling losses are mitigated via efficient cleaning methods and optimized cleaning frequency. If solar collectors are not cleaned, the accumulation of dust layers on solar collectors may cause the operation of such plants in arid regions to become economically unviable. Washing solar collectors with water and detergent, as is most commonly done now, is an efficient method for cleaning. The conventional approach in utility-scale solar plants is to use a large truck with a water tank and pump system for spraying deionized water on the surface of the solar collectors. Robotic cleaning with brushes, used for many solar plants, requires lesser water for cleaning. The water consumed using semi-automated cleaning of PV modules in utility-scale solar plants is approximately 2 liters/m 2 per cleaning cycle. The total optical surface area of the solar collectors in 1 TW-scale solar installation will be more than 3 × 109 m 2 ; hence an enormous amount of water be needed for cleaning. There simply is not enough fresh water in the sun-belt areas of the world for predicted cleaning needs. In solar power plants, the estimated cost of cleaning solar collectors includes expenses related to the equipment used, labor, cost of transportation of water, the energy required for cleaning, plus ancillary costs whereas the cost of water is not considered. The water used is obtained from sources located close to plant sites, unmindful of the environmental and societal impact as the power plants are oftentimes located in regions that face severe drought. This practice is very similar to the cost calculations in deriving the levelized cost of electricity (LCOE) in conventional power plants based on burning fossil fuel such as coal and gas, while disregarding the cost of climate change and health effects. Unless a water-free or low-water cleaning method is established, the expansion of solar plants may lose public support in areas suffering long intervals of drought. The goal of this research project has been the development and application of the Electrodynamic Screen (EDS) as a means for a water-free, scalable cleaning process applicable to solar-power installations, including rooftop applications. We describe here the development of an EDS film-based cleaning process as an emerging method for use on PV modules, parabolic troughs, and heliostats. This report aims to show the feasibility of integrating or retrofitting EDS films onto the optical surfaces of solar collectors (both PV and CSP) while maintaining high transmission or reflection efficiency. The cleaning action provided by the EDS film is an active method to remove dust deposits by electrodynamic force. Current lab-scale prototype EDS films, retrofitted onto solar panels and mirrors, have shown to be capable of maintaining optical transmission or specular-reflection efficiencies higher than 90% of initial values under clean conditions. The optical surfaces of solar collectors laminated with EDS films can remove more than 90% of deposited dust when the EDS is activated for less than two minutes. As an electrodynamic dust removal process, the EDS film-based method is designed primarily for the removal of dust in solar installations located in semi-arid and desert areas, where the atmosphere is often dry and dusty and rainfall is infrequent. While EDS film application minimizes water consumption and facilitates cleaning as frequently as needed, it has limitations in removing contaminants such as soot, organic pollutants deposited as fine films on the surface, and bird droppings. The dust removal efficiency of the EDS is maximum at relative humidity RH is 40 to 50% and decreases at when RH > 65%. Many solar plant sites undergo diurnal and seasonal cycles of high ambient, early afternoon temperatures and an RH that reaches the dew point early in the morning. These variations in atmospheric conditions do not limit the operation of the EDS film. This report presents a brief review of the progress and the potential of EDS film technology for mitigating the impact of dust on solar collectors via water-free cleaning, as well as current technical challenges regarding efficiency and durability. Our experimental data on the performance of EDS films show that: (1) the dust-removal efficiency (DRE) can reach levels higher than 90%, (2) the specular reflectivity (SR) of EDS film-laminated second-surface mirrors reach levels in excess of 90%, (3) the specular reflectivity restoration (SRR) can exceed 90%, (4) the output-power restoration (OPR) of PV modules can exceed 95%, and (5) the optical transmission efficiency (TE) of the EDS films can be greater than 90%. Working with Sandia National Laboratories (NM), Corning Research and Development Corporation (NY), Eastman Kodak (NY), Tomark-Worthen Industries (NH), and EDS Chile SPA (Chile), we have produced EDS film-laminated PV modules and demonstrated their self-cleaning functions without requiring water. We have demonstrated that the operational range of EDS films will cover the expected ambient temperature of solar fields at RH cycling varying from 20 to 95% as long as the EDS films are activated in the RH range 20 to 50%. (Typical solar-field climates in deserts and semi-arid lands often reach near dew point in coastal areas.) Our experiments on the application of hydrophobic-fluorinated nanoparticle coatings on EDS film surfaces show that the EDS operational range can be extended to higher RH levels that approach the dew point. At Eastman Kodak, as one of our industrial partners, we were able to establish a process for manufacturing EDS films using flexographic printing of the electrodes onto transparent polymer films. This process utilizes an existing manufacturing line at Eastman Kodak that allows fabrication of medium-scale EDS films (26 cm × 30 cm). The manufacturing process has the capacity to produce EDS films at high production speeds. The medium-scale EDS films that have been printed at Kodak were evaluated in the lab at Boston University. The EDS films produced at Kodak were laminated at Tomark-Worthen using an industrial scale vacuum laminator to produce EDS film stacks, which can be affixed onto the optical surfaces of PV modules or concentrating mirrors. The EDS film stack consists of the EDS films that have Willow® Glass (WG) which has a thickness of 100 μm as the front surface. The WG sheets obtained from Corning Research and Development Corporation are customized in size and shape to cover the active area of the EDS films. The back surface of the EDS film stack is integrated onto the optical surface of the solar panel or mirror using optically clear adhesive (OCA) films or silicone adhesives. The OCA films (thickness 25 μm) are produced by 3M. The EDS film stacks have the architecture: WG/OCA/EDS Film/OCA/ over PV module or solar mirror. The power-supply units needed for activating the electrodes of the EDS film were designed and produced at Boston University. These power supply units provide three-phase, 1.2 kV voltage pulses at a very low current (micro-ampere) level and at a low frequency (≈ 5 Hz). The voltage pulses are applied to the electrodes in a sequence such that the train of pulses resembles a unidirectional traveling wave of electrical field on the surface of the EDS film. The dust particles on the surface become charged electrostatically and are levitated by the Coulomb force. The lateral sweeping action of the traveling electric field created by the three-phase voltages pulses then sweeps the dust off the surface. The energy consumed by the EDS electrodes is less than 0.2 Wh/m 2 /cleaning cycle, enabling energy-efficient restoration of output power (OPR) of PV module or specular reflectivity restoration (SRR) for solar mirrors. The EDS system consists of (1) an EDS film stack laminated onto the solar collectors, (2) connection of the EDS film to its power supply unit and (3) Interconnection of the power supply to PV modules or solar mirrors. Design, construction and assessment of field-testing units that have EDS stack laminated PV modules for evaluating the performance of the EDS films in solar fields is being carried out at BU. Our progress under this project, aimed at the advancement of EDS film technology, has reached DOE Technology Readiness Level (TRL) 6. Based on the extensive laboratory evaluations and limited field trials, as well as contacts with potential users, we believe that the technology has reached its commercial stage. We are conducting a cost analysis using the National Renewable Energy Laboratory (NREL) System Advisory Model (SAM) and are preparing for field trials of EDS films in different solar fields in the US, Chile, India and in the Middle East. A brief description of EDS film performance, construction and testing of the field-test unit, autonomous operation of the field-test unit for evaluating EDS performance in increasing energy yield, associated revenue savings, and water conservation is presented.

14 SOLAR ENERGY↗
NASA NTRS1977

Open-Cycle Gas Turbine/Steam Turbine Combined Cycles with synthetic fuels from coal

The Open-Cycle Gas Turbine/Steam Turbine Combined Cycle can be an effective energy conversion system for converting coal to electricity. The intermediate step in this energy conversion process is to convert the coal into a fuel acceptable to a gas turbine. This can be accomplished by producing a synthetic gas or liquid, and by removing, in the fuel conversion step, the elements in the fuel that would be harmful to the environment if combusted. In this paper, two open-cycle gas turbine combined systems are evaluated: one employing an integrated low-Btu gasifier, and one utilizing a semi-clean liquid fuel. A consistent technical/economic information base is developed for these two systems, and is compared with a reference steam plant burning coal directly in a conventional furnace.

Shah, R. P.↗
DOE OSTI2023

Effective removal of trace-level toxic metals from flue gas desulfurization wastewater using SiO 2 supported hydrogel sorbent

Flue gas desulfurization (FGD) wastewater generated from coal-fired power plants contain potentially harmful heavy metal pollutants that pose a threat to public health and clean water. In this work, we present a water stable polyethylenimine-n,n’-methylenebisacrylamide (PEI-MBAA) functionalized SiO 2 solid sorbent material (PMS-1.2/1/4) and investigate its metal adsorption kinetics, selectivity, regenerability, and space velocity. The kinetic studies of six of the toxic heavy metals (As, Cd, Cr, Pb, Se, and Hg) prepared with single elements in Milli-Q water showed the effect of chemical bonding and intraparticle mass transfer resistance on the sorption process. The selectivity studies demonstrated the significant adsorption efficiency toward trace-level heavy metals (Se, Cd, U, Al, etc.) from authentic industrial FGD wastewater. Through five consecutive adsorption–desorption cycles with the FGD (uptake)-citrate (release)-based buffer pair, the sorbent showed high heavy metal removal ability and good reusability. The maximum flow rate for the removal of Se from industrial FGD wastewater was determined to be as high as 8 bed volumes/minute of the sorbent bed. Finally, the results demonstrate the PMS-1.2/1.4 sorbent is a promising candidate for the removal of heavy metals from practical aqueous solutions.

36 MATERIALS SCIENCE↗
DOE OSTI2025

Hydrogen Production from Polyethylene Pyrolysis

Hydrogen is anticipated to play a pivotal role in the future of clean energy and decarbonization efforts, serving as an energy storage medium, a power generation source, and a clean fuel for transportation. While most hydrogen is produced from carbonaceous fossil feedstocks like natural gas, petroleum, and coal, there is growing interest in using refuse-derived fuels such as waste plastics and municipal solid waste (MSW) as alternative feedstocks. Thermochemical processes such as pyrolysis and catalytic cracking can convert nonrecyclable plastics and organic MSW components to produce hydrogen with lower life cycle greenhouse gas emissions when coupled with CO 2 capture. Such approaches not only address waste-management challenges but also reduce methane emissions from landfills. Furthermore, waste feedstocks are low cost and can support meeting demands for hydrogen across various industries. In this work we examined production of hydrogen from high-density polyethylene (HDPE) as a model polymer using pyrolysis. Analytical studies of pyrolysis utilizing gas chromatography–mass spectrometry (GC/MS) provide insights into conversion pathways for plastic waste, potentially reducing the environmental footprint of traditional hydrogen production methods. This work generates a baseline methodology for hydrogen production from plastic pyrolysis with and without a catalyst and the necessary product distribution baseline from key single plastics. The effect of pyrolysis temperature on the conversion of HDPE was evaluated both with and without a catalyst(s), and the product distributions measured via GC/MS were identified and hydrogen formation was quantified. These results will help guide future research efforts to optimize catalysts and processes for more efficient hydrogen production and mixed plastic waste management.

Catalysts↗
DOE OSTI2013

Removal of H{sub 2}S using molten carbonate at high temperature

Highlights: • The performance of molten carbonate for the removal of H{sub 2}S improves at higher temperatures. • The degree of H{sub 2}S removal is significantly affected by the CO{sub 2} concentration in syngas. • Addition of carbon elements, such as char and tar, decrease the negative effects of CO{sub 2}. • Continuous addition of carbon elements into molten carbonate enables continuous desulfurization. • Desulfurization using molten carbonate is suitable for gasification gas. - Abstract: Gasification is considered to be an effective process for energy conversion from various sources such as coal, biomass, and waste. Cleanup of the hot syngas produced by such a process may improve the thermal efficiency of the overall gasification system. Therefore, the cleanup of hot syngas from biomass gasification using molten carbonate is investigated in bench-scale tests. Molten carbonate acts as an absorbent during desulfurization and dechlorination and as a thermal catalyst for tar cracking. In this study, the performance of molten carbonate for removing H{sub 2}S was evaluated. The temperature of the molten carbonate was set within the range from 800 to 1000 °C. It is found that the removal of H{sub 2}S is significantly affected by the concentration of CO{sub 2} in the syngas. When only a small percentage of CO{sub 2} is present, desulfurization using molten carbonate is inadequate. However, when carbon elements, such as char and tar, are continuously supplied, H{sub 2}S removal can be maintained at a high level. To confirm the performance of the molten carbonate gas-cleaning system, purified biogas was used as a fuel in power generation tests with a molten carbonate fuel cell (MCFC). The fuel cell is a high-performance sensor for detecting gaseous impurities. When purified gas from a gas-cleaning reactor was continuously supplied to the fuel cell, the cell voltage remained stable. Thus, the molten carbonate gas-cleaning reactor was found to afford good gas-cleaning performance.

09 BIOMASS FUELS↗
DOE OSTI2019

Making Coal Relevant for Small Scale Applications: Modular Gasification for Syngas/Engine CHP Applications in Challenging Environments

This Front-End Engineering Design (FEED) study is funded by the US Department of Energy (DOE), and managed by the National Energy Technology Laboratory (NETL) through a Cooperative Agreement awarded to the University of Alaska Fairbanks (UAF) to perform a technical and cost study for the design and installation of a Hamilton-Maurer International (HMI) gasifier for generating a clean syngas for firing in reciprocating engines. An existing diesel engine generator (DEG) and a commercially available spark ignition engine are used to generate electricity with the low-Btu syngas. Other than the HMI gasifier, only commercially available technologies were assumed for this study. An important objective of this design study was to estimate capital and operating costs of small modular coal and coal/biomass fired generating units to provide wind regulation services. Although this study is based on retrofitting an existing coal fired power plant with the HMI gasifier, sufficient data was developed to characterize greenfield units. The original concept was to provide clean syngas and tars/oils from the gasification process to the existing Colt-Pielstick PC2.6B diesel engine generator (9.6 MWe) installed at the UAF Atkinson Power Plant. The intent was to convert the diesel engine to operate in a dual fuel mode, firing both syngas and tars/oils. As the project progressed, Fairbanks Morse Engine (FME), current licensee for the Colt-Pielstick engine line, was not able to develop a modification package for the engine to allow for syngas firing. Although this type of modification is available for firing natural gas, the capability does not extend to syngas. Western Energy Systems, distributor for Innio Jenbacher, was able to offer the Jenbacher Model JMS620 engine. After review of available options, the project team selected a design configuration using two Jenbacher engines rated at 1965 kWe each to fire the syngas, with the oils/tars directed to the Colt Pielstick diesel to be blended with ultra-low sulfur diesel oil (ULSD). The Jenbacher engines are expected to operate at continuous base load, with some load-following ability, while the existing diesel engine will operate in grid support service, with loads varying from a nominal 25% to 100%. An annual capacity factor for the diesel engine is projected to be between 50% and 60%. The overall gasifier and gas clean-up system is sized to produce enough syngas to adequately fuel three Jenbacher Engines for a nominal power output of 5.9 MWe, but this study assumes that only two Jenbacher engines will be installed due to space constraints in the Atkinson Power Plant, and because of expected air emission permit limitations. There is still potential that the excess syngas capacity equivalent to about 2 MWe could be used as supplemental fuel for the DEG. The exhaust from the Jenbacher engines is passed through heat recovery units to generate low pressure steam, thereby providing a significant portion of the steam required for operating the gasifier. The overall performance of the HMI gasifier/engine configuration is summarized as follows: 1) Overall electric efficiency, Jenbacher and diesel engines, based on gasifier fuel production (syngas and pyrolysis liquids) is 35.2% LHV, 2) Overall cogenerating efficiency (electricity plus steam), based on gasifier fuel production (syngas and pyrolysis liquids) is 54.8% LHV, 3) Overall electric efficiency, Jenbacher and diesel engines, based on coal input, is 29.6% LHV, and 4) Overall cogenerating efficiency, electricity plus steam, based on coal input is 46.0%. This project is estimated to have a Bare Erected Cost (BEC) of $\$$ 33.4 million and a Total Plant Cost (TPC) of $\$$ 45.7 million. Based on the original scope, sending both the clean syngas and the oils and tars to the existing diesel engine, the BEC and TPC values would have been $\$$ 23.3 million and $\$$ 32.1 million, respectively. A variable Cost of Electricity (COE) is calculated to reflect only those costs that will be incurred by incremental operation of the system for the HMI gasifier/Jenbacher engine combination. Operation of the diesel engine is determined separately. The variable COE values are: Case 1: 100% Usibelli Coal: (a) HMI gasifier/Jenbacher Engines -- 8.3 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh, and Case 2: 80% Usibelli Coal + 20% wood chips (proportion based on Btu input, LHV basis): (a) HMI Gasifier/Jenbacher -- 13.7 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh. The incremental cost of operating the gasifier/Jenbacher system increases with co-firing of wood chips due to the high cost of this material, over five times as costly as Usibelli coal delivered to the Atkinson Power building. The diesel cost is constant as the oils and tars are priced at the same value as the ULSD for the purposes of fueling the diesel engine. Section 8 of this report provides details of the O&M costs. The overall power system is configured to be modular and scalable to provide a wide range of generating capacity using the same components. This allows for reduction in cost, risk, schedule time to engineer and construct, and provides some degree of repeatability for air permitting.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2017

Models and Simulation Environment for the Design and Optimization of Hybrid Energy Systems

The energy landscape in the U.S. is changing with proposed federal regulations limiting carbon dioxide emissions and with government credits for 'clean' energy technologies. This shift in the market conditions, especially in deregulated markets, has already resulted in the closing of coal power plants. Previously these coal plants served to balance variation in load. The resulting loss of electricity production is being made up in part with increased renewable generation. This set of governmental policy changes potentially presents expanded opportunities for both renewable energy and nuclear energy to become significant energy sources in the future. Potential synergies exist that can reduce greenhouse gas (GHG) emissions and provide affordable, sustainable energy. Combining multiple energy production, conversion, storage, and consumption facilities can leverage these potential synergies. This research focuses on integrating nuclear power plants within systems with increased renewable penetration, referred to as a nuclear renewable hybrid energy system (NRHES). Industrial-scale nuclear renewable hybrid energy systems have the potential to provide grid services such as dispatchable generation, storage, ancillary services, and power regulation. The problem of designing, analyzing, and optimizing the NHRES is being undertaken by a multi-laboratory team. The effort requires the collaboration of experts across engineering disciplines with methods and results to be shared by these experts. To facilitate collaborations a common system modeling and analysis language is adopted along with open-source libraries and interface standards that support data exchange among the models. Modelica was selected as the common language based on its prior use by team members at each of Idaho National Laboratory, Oak Ridge National Laboratory, and Argonne National Laboratory.

22 GENERAL STUDIES OF NUCLEAR REACTORS↗
DOE OSTI2015

Life-cycle assessment of greenhouse gas and air emissions of electric vehicles: A comparison between China and the U.S.

We evaluated the fuel-cycle emissions of greenhouse gases (GHGs) and air pollutants (NOx, SO2, PM10, and PM2.5) of electric vehicles (EVs) in China and the United States (U.S.), two of the largest potential markets for EVs in the world. Six of the most economically developed and populated regions in China and the U.S. were selected. The results showed that EV fuel-cycle emissions depend substantially on the carbon intensity and cleanness of the electricity mix, and vary significantly across the regions studied. In those regions with a low share of coal-based electricity (e.g., California), EVs can reduce GHG and air pollutant emissions (except for PM) significantly compared with conventional vehicles. However, in the Chinese regions and selected U.S. Midwestern states where coal dominates in the generation mix, EVs can reduce GHG emissions but increase the total and urban emissions of air pollutants. In 2025, EVs will offer greater reductions in GHG and air pollutant emissions because emissions from power plants will be better controlled; EVs in the Chinese regions examined, however, may still increase SO2 and PM emissions. Reductions of 60–85% in GHGs and air pollutants could be achieved were EVs charged with 80% renewable electricity or the electricity generated from the best available technologies of coal-fired power plants, which are futuristic power generation scenarios.

Electric vehicles↗
DOE OSTI2016

High Pressure Biomass Gasification

According to the Billion Ton Report, the U.S. has a large supply of biomass available that can supplement fossil fuels for producing chemicals and transportation fuels. Agricultural waste, forest residue, and energy crops offer potential benefits: renewable feedstock, zero to low CO 2 emissions depending on the specific source, and domestic supply availability. Biomass can be converted into chemicals and fuels using one of several approaches: (i) biological platform converts corn into ethanol by using depolymerization of cellulose to form sugars followed by fermentation, (ii) low-temperature pyrolysis to obtain bio-oils which must be treated to reduce oxygen content via HDO hydrodeoxygenation), and (iii) high temperature pyrolysis to produce syngas (CO + H 2 ). This last approach consists of producing syngas using the thermal platform which can be used to produce a variety of chemicals and fuels. The goal of this project was to develop an improved understanding of the gasification of biomass at high pressure conditions and how various gasification parameters might affect the gasification behavior. Since most downstream applications of synags conversion (e.g., alcohol synthesis, Fischer-Tropsch synthesis etc) involve utilizing high pressure catalytic processes, there is an interest in carrying out the biomass gasification at high pressure which can potentially reduce the gasifier size and subsequent downstream cleaning processes. It is traditionally accepted that high pressure should increase the gasification rates (kinetic effect). There is also precedence from coal gasification literature from the 1970s that high pressure gasification would be a beneficial route to consider. Traditional approach of using thermogravimetric analyzer (TGA) or high-pressure themogravimetric analyzer (PTGA) worked well in understanding the gasification kinetics of coal gasification which was useful in designing high pressure coal gasification processes. However, similar approach for biomass gasification was not very useful and was the impetus for this study. Specifically, we aimed this study at three broad objectives: (i) defining operating conditions at which C 2 -C 4 hydrocarbons are formed since these represent loss of carbon efficiency, (ii) understanding the formation of tar species which create downstream processing difficulties in addition of carbon efficiency loss, and (iii) kinetics of biomass gasification where it would be possible to understand the effect of operating conditions and gas phase composition.

09 BIOMASS FUELS↗
DOE OSTI2017

High Temperature Chemistry of Aromatic Hydrocarbons. Final Technical Report

The primary goal of this research was to uncover the principal reaction channels available to polycyclic aromatic hydrocarbons (PAHs) at high temperatures in the gas phase and to establish the factors that determine which channels will be followed in varying circumstances. New structure-property relationships for PAHs were also studied. The efficient production of clean energy from fossil fuels will remain a major component of the DOE mission until alternative sources of energy eventually displace coal and petroleum. Hydrocarbons constitute the most basic class of compounds in all of organic chemistry, and as the dominant species in fossil fuels, they figure prominently into the programs of the DOE. Much is already known about the normal chemistry of hydrocarbons under ambient conditions, but far less is known about their intrinsic chemistry at temperatures close to those reached during combustion. An understanding of the fundamental molecular transformations, rearrangements, and interconversions of PAHs at high temperatures in the gas phase, as revealed by careful studies on small, well-designed, molecular systems, provides insights into the underlying chemistry of many important processes that are more complex, such as the generation of energy by the combustion of fossil fuels, the uncatalyzed gasification and liquefaction of coal, the production of fullerenes in fuel-rich flames, and the formation of soot and carcinogenic pollutants in smoke (e.g., benzo[a]pyrene). The rational control of any of these processes, whether it be the optimization of a desirable process or the minimization of an undesirable one, requires a clear knowledge of the basic chemistry that governs the fate of the species involved. Advances in chemistry at the most fundamental level come about primarily from the discovery of new reactions and from new insights into how reactions occur. Harnessing that knowledge is the key to new technologies. The recent commercialization of a combustion synthesis of C 60 and other fullerenes depended critically on a knowledge of hydrocarbon reactions at high temperatures in the gas phase, and the research supported by this project enabled further advances in the realm of carbon-rich materials.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
NASA NTRS1976

Experimental clean combustor program, alternate fuels addendum, phase 2

The characteristics of current and advanced low-emissions combustors when operated with special test fuels simulating broader range combustion properties of petroleum or coal derived fuels were studied. Five fuels were evaluated; conventional JP-5, conventional No. 2 Diesel, two different blends of Jet A and commercial aromatic mixtures - zylene bottoms and haphthalene charge stock, and a fuel derived from shale oil crude which was refined to Jet A specifications. Three CF6-50 engine size combustor types were evaluated; the standard production combustor, a radial/axial staged combustor, and a double annular combustor. Performance and pollutant emissons characteristics at idle and simulated takeoff conditions were evaluated in a full annular combustor rig. Altitude relight characteristics were evaluated in a 60 degree sector combustor rig. Carboning and flashback characteristics at simulated takeoff conditions were evaluated in a 12 degree sector combustor rig. For the five fuels tested, effects were moderate, but well defined.

Gleason, C. C.↗
DOE OSTI2025

Systems Analysis of Biomass and Coal Co-firing Power Plants with Deep Carbon Capture Toward Net-zero Emissions

Achieving a net-zero emission economy in the United States requires integrating diverse low-carbon and negative-emission technologies into the existing fossil fuel-dominant power fleet. Potential technologies from the low-carbon portfolio include renewable power, fossil power with carbon capture and storage (CCS), bioenergy with CCS (BECCS), and direct air capture (DAC). Renewable power is a clean energy source but has to pair with costly battery storage to provide dispatchable electricity. Fossil power with CCS offers dispatchable electricity yet still relies on DAC to offset residual emissions, even when deploying deep CCS with more than 90% CO2 capture. Coal-biomass co-firing with CCS, a subset of BECCS, is a reliable energy production technology that can be retrofitted from existing electricity generation units (EGUs). Power plant retrofit maximizes the use of the current U.S. coal power fleet without the need for large-scale deployment of new renewable power, battery storage, or DAC. Retrofitting coal-biomass co-firing with deep CCS in EGUs is a promising option, but not a universal solution. Biomass co-firing at a power plant introduces economic challenges and indirectly poses pressure on land and water resources. Meanwhile, retrofitting deep CCS affects plant efficiency and raises electricity generation costs. Overall, the technical feasibility and economic viability of plant retrofits vary across EGUs, as they are contingent upon the regional availability of biomass, unit-specific characteristics, site-specific fuel supply costs, and adjacent CO2 storage potential. Government incentives like 45Q can improve the retrofit viability, though the impact requires further quantification. A comprehensive analysis at the unit level is essential to address the question regarding the fate of the U.S. coal-fired electricity generation fleet toward the net-zero emission goal. This study conducts a systematic techno-economic-environmental assessment of EGUs to identify the viability of biomass co-firing and deep CCS retrofits in the U.S. coal-fired power fleet. Specifically, it characterizes the techno-economic performance of deep carbon capture, estimates life cycle greenhouse gas (GHG) emissions, and conducts a fleet-level assessment on retrofit viability. The key objectives are (1) to estimate the unit-specific performance and retrofitted cost under various biomass co-firing levels and CO2 capture rates; (2) to determine the possibility of reaching net-zero emission at the fleet level; (3) to quantify the cumulative capacities that are suitable for plant retrofits under current and future biomass supply scenarios; and (4) to improve the understanding of policy impacts on such retrofits to help the power sector’s transition to a net-zero economy. Techno-economic Model of Deep Carbon Capture. This study develops the performance and economic models for Monoethanolamine-based post-combustion CO2 capture at 95–99% capture rates. The process is simulated in Aspen Plus, analyzing the performance of carbon capture technology by varying the plant sizes, solvent lean loading, CO2 concentrations, and flue gas inlet temperature. Based on the key inputs and output parameters of CO2 capture, a reduced-order performance model of deep carbon capture is formulated. In addition, an engineering-economic model integrating the performance metrics is developed to estimate the capital as well as operation and maintenance (O&M) costs. Capital cost estimations follow the framework of the Integrated Environmental Control Model (IECM) and incorporate data regressions from three technical reports by IECM, the National Energy Technology Laboratory (NETL), and the National Renewable Energy Laboratory. The O&M cost estimation utilizes the actual inventory consumption rate and labor requirements. Both performance and cost models are embedded into IECM v13.0-beta, a fossil-fuel power plant modeling tool. Life Cycle Assessment of Power Plants. This study estimates the GHG emissions of power plants through life cycle assessment (LCA). The LCA scope includes fuel supply, combustion-based power generation, and CO2 transport and storage. The fuel-based life cycle module is designed following the framework of the NETL Unit Process Library and CO2U LCA Guidance Toolkit. The module is then incorporated into IECM v13.0-beta. The process-based LCA is applied to estimate the GHG emissions of coal and biomass supply, coal- and coal-biomass co-firing power plant operation, as well as CO2 pipeline transport and geographical sequestration. An uncertainty analysis is conducted to quantify the variability and uncertainty associated with the LCA using the Latin Hypercube Sampling (LHS) method. Fleet-level Assessment. This study evaluates the technical and economic feasibility of selected coal-fired EGUs, examines the role of tax credits in retrofit viability, and assesses the competitiveness of retrofitted units against other low-carbon options. Unit screening identifies EGUs for the study, focusing on new, efficient baseload units with air pollution controls. The power plant databases are then established to organize unit-specific information on performance and operating conditions from the relevant public databases. Biomass for co-firing retrofits is selected based on home and neighboring county availability, ensuring sustained operation with at least a 5% co-firing level. The CO2 storage site is determined by state-level storage potential, with ArcGIS Pro and NETL CO2 Saline Storage Cost Model used to identify the optimal balance between the nearest transport distances and affordable storage costs. The latest IECM v13.0-beta is then employed to configure and evaluate the eligible EGUs with or without the deployment of deep CCS and biomass co-firing. A supply curve is established to illustrate the cumulative installed capacity suitable for retrofits at different cost levels. A sensitivity analysis on tax credits for carbon sequestration is performed. Finally, a unit-level cost comparison is conducted among retrofitted plants, renewable power with battery storage, and abated fossil fuels with DAC. Expected Results. This study evaluates the technical, economic, and environmental metrics of each EGU across an array of CO2 capture rates and biomass co-firing level scenarios. Unit-level comparisons will identify critical factors influencing technical performance. The supply curves with and without tax incentives will provide insights into the impact of tax credits on biomass co-firing and CCS deployment. The cost comparisons with renewables and DAC-retrofit will assess the competitiveness of the retrofitted units. Life cycle emissions from each unit will be assessed to identify the scenarios under which net-zero emissions can be achieved. These analyses are expected to determine the total coal-fired capacity suitable for serving as a low-carbon energy source with or without tax incentives. The study results are novel in identifying optimal unit-specific strategies for producing carbon-neutral power, whether through retrofitting EGUs with deep CCS, biomass co-firing, DAC, or installing renewable power with battery. The findings will provide insight into nationwide efforts to ensure reliable, affordable, and low-carbon electricity. It also will inform investment decisions and policies in the deployment of deep carbon capture and negative emission technologies for a net-zero energy future.

Biomass Co-firing↗
DOE OSTI2017

Benefits of Integration of Aerojet Rocketdyne and RTI Advanced Gasification Technologies for Hydrogen-Rich Syngas Production

The key objective for this project was to evaluate the potential to achieve substantial reductions in the production cost of H 2 -rich syngas via coal gasification with near-zero emissions due to the cumulative and synergistic benefits realized when multiple advanced technologies are integrated into the overall conversion process. In this project, Aerojet Rocketdyne’s (AR’s) advanced gasification technology (currently being offered as R-GAS™) and RTI International’s (RTI’s) advanced warm syngas cleanup technologies were evaluated via a number of comparative techno-economic case studies. AR’s advanced gasification technology consists of a dry solids pump and a compact gasifier system. Based on the unique design of this gasifier, it has been shown to reduce the capital cost of the gasification block by between 40 and 50%. At the start of this project, actual experimental work had been demonstrated through pilot plant systems for both the gasifier and dry solids pump. RTI’s advanced warm syngas cleanup technologies consist primarily of RTI’s Warm Gas Desulfurization Process (WDP) technology, which effectively allows decoupling of the sulfur and CO 2 removal allowing for more flexibility in the selection of the CO 2 removal technology, plus associated advanced technologies for direct sulfur recovery and water gas shift (WGS). WDP has been demonstrated at pre-commercial scale using an activated amine carbon dioxide recovery process which would not have been possible if a majority of the sulfur had not been removed from the syngas by WDP. This pre-commercial demonstration of RTI’s advanced warm syngas cleanup system was conducted in parallel to the activities on this project. The technical data and cost information from this pre-commercial demonstration were extensively used in this project during the techno-economic analysis. With this project, both of RTI’s advanced WGS technologies were investigated. Because RT’s advanced fixed-bed WGS (AFWGS) process was successfully implemented in the WDP pre-commercial demonstration test mentioned above, this technology was used as part of RTI’s advanced warm syngas technology package for the techno-economic analyses for this project. RTI’s advanced transport-reactor-based WGS (ATWGS) process was still conceptual at the start of this project, but one of the tasks for this project was to evaluate the technical feasibility of this technology. In each of the three application-based comparison studies conducted as part of this project, the reference case was based on an existing Department of Energy National Energy Technology Laboratory (DOE/NETL) system study. Each of these references cases used existing commercial technology and the system resulted in > 90% carbon capture. In the comparison studies for the use of the hydrogen-rich syngas generated in either an Integrated Gasification Combined Cycle (IGCC) or a Coal-to-Methanol (CTM) plant, the comparison cases consisted of the reference case, a case with the integration of each individual advanced technology (either AR or RTI), and finally a case with the integration of all the advanced technologies (AR and RTI combined). In the Coal-to-Liquids (CTL) comparison study, the comparison study consisted of only three cases, which included a reference case, a case with just RTI’s advanced syngas cleaning technology, and a case with AR’s and RTI’s advanced technologies. The results from these comparison studies showed that the integration of the advanced technologies did result in substantial benefits, and by far the greatest benefits were achieved for cases integrating all the advanced technologies. For the IGCC study, the fully integrated case resulted in a 1.4% net efficiency improvement, an 18% reduction in capital cost per kW of capacity, a 12% reduction in the operating cost per kWh, and a 75–79% reduction in sulfur emissions. For the CTM case, the fully integrated plant resulted in a 22% reduction in capital cost, a 13% reduction in operating costs, a > 99% net reduction in sulfur emissions, and a reduction of 13–15% in CO 2 emissions. Because the capital cost represents over 60% of the methanol Required Selling Price (RSP), the significant reduction in the capital cost for the advanced technology case resulted in an 18% reduction in methanol RSP. For the CTL case, the fully integrated plant resulted in a 16% reduction in capital cost, which represented a 13% reduction in diesel RSP. Finally, the technical feasibility analysis of RTI’s ATWGS process demonstrated that a fluid-bed catalyst with sufficient attrition resistance and WGS activity could be made and that the process achieved about a 24% reduction in capital cost compared to a conventional fixed-bed commercial process.

08 HYDROGEN↗
DOE OSTI2021

Transitioning Coal Power Plants to Nuclear Power

Most large U.S. power companies are setting zero-carbon-emission goals and is a reflection of utility commitments to carbon reduction and policies at the Federal and State levels. Increasing the rate of coal power plant (CPP) retirements has been seen across the industry. Previous transitions of coal to gas fuel are becoming less desirable as having zero carbon emissions become ever more import. As CPPs are retired, a reliable and affordable zero-emission power replacement is desired. Nuclear power plants (NPP) is the only existing dispatchable and clean source of energy that can directly replace a CPP. The report covers different factors that affect CPP to NPP projects.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2019

The Occurrence and Concentration of Rare Earth Elements in Acid Mine Drainage and Treatment By-products: Part 1—Initial Survey of the Northern Appalachian Coal Basin

The conventional rare earth element (REE) industry has historically sought to develop ore deposits where geologic processes have produced mineralized zones with commercially attractive REE concentrations. These deposits are extremely uncommon, particularly in the USA. Given the criticality of these materials and the need for sustainable domestic supply, the current research seeks to leverage other autogenous processes that lead to concentrated REE resources. One such process is the generation of acid mine drainage (AMD). AMD is very common in many coal mining districts and results from the exposure and oxidation of pyrite during mining. During the generation and migration of AMD, liberated sulfuric acid mobilizes several metal ions including REEs. Treatment of AMD is required under U.S.C §1251, the Clean Water Act, and often consists of neutralization, oxidation, and metal hydroxide precipitation. To investigate the deportment of REEs during this process, a field sampling campaign was undertaken, whereby the concentration of REEs in AMD and AMD precipitates was measured directly. In the nine sites evaluated in this study, the REE concentrations of the precipitates varied from 29 to 1286 ppm with an average of 517 ppm among the sampled sites. The individual elements were enriched compared with the associated bulk Northern Appalachian (NAPP) coal material by factors ranging from 3 to 15. Furthermore, the distribution of REEs in all precipitate samples favored the heavy REEs (HREEs) when compared with traditional REE ores. Finally, this research represents the first part of multi-part research endeavor to characterize, classify, and determine the practicality of refining REEs from AMD and its by-products.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2018

Experience with Chemical Looping Combustion of Coal in a 200 kW Dual Fluidized Bed Reactor

The University of Utah recently commissioned a dual fluidized bed process development unit (PDU) for investigating chemical looping combustion (CLC) and chemical looping with oxygen uncoupling (CLOU) of coal. The reactors and supporting systems were sized to support at least 200 kW of coal input based on available reaction rate data. Both the air reactor and fuel reactor are circulating fluidized beds and bed material passes between the reactors via loop seals. The reactors are refractory-lined rather than electrically heated, so the system must be preheated with natural gas before chemical looping combustion can begin. Air and steam are preheated through a combination of electric heating and natural gas burners and reactor product gas flows through heat exchangers and bag houses to cool and clean the gas of particulate. As is typical with pilot-scale systems, several operational challenges were encountered as the system was brought online and operation progressed from heatup and initial testing with gaseous fuels towards full CLOU processing of coal. The system hardware and operational procedures have undergone several modifications, but the PDU can now reliably be preheated to the operating temperature and coal can be fed at the target feed rate. This paper presents the PDU, describes the procedures for evaluating carbon conversion, CO2 capture and CO2 purity, and presents initial results from chemical looping combustion of coal with non-CLOU and CLOU carriers. General experience of operating the plant and notable challenges and solutions are also presented.

Whitty, Kevin J.↗
DOE OSTI2025

Life Cycle Assessment of Methanol from Fossil, Biomass, and Waste Sources, and Its Use as a Marine Fuel in Dual-Fuel Engines

Methanol is gaining interest in the marine sector from energy security and reducing emissions perspective. This study provides a comparative life cycle assessment of methanol as a marine fuel, across GHG and criteria air pollutant emission metrics, when it is used in a dual-fuel engine. Twelve methanol pathways from four different feedstock categories were considered, including (1) cellulosic biomass forest residues and clean pine mix, corn stover, switchgrass, and miscanthus; (2) organic wastes renewable natural gas from wastewater sludge, swine manure, food waste, and landfill gas; (3) fossil resources coal and natural gas (NG); and (4) e-methanol using captured carbon dioxide. When used in a dual-fuel engine with pilot fuel, life cycle GHG emissions for woody biomass-based methanol were approximately 19 gCO 2 e MJ −1 , while emissions from waste-based sources ranged between −154 and 31 gCO 2 e MJ −1 . Methanol from renewable sources showed a GHG reduction potential between 58 and 226% compared to conventional NG-based methanol (122 gCO 2 e MJ −1 ), primarily due to the avoided emissions from conventional waste management. When carbon from process emissions were captured, the reduction could be up to 327%. All pathways exhibited lower NO X , and particulate matter emissions compared to the baseline marine fuel (MGO 0.1% sulfur), while woody biomass and coal pathways had higher SO X emissions.

09 BIOMASS FUELS↗