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All sourcesNASA NTRSDOE OSTI
DOE OSTI2022

Coal Fired Power Plant Configuration and Operation Impact on Plant Effluent Contaminants and Conditions

The primary objective of this project is to characterize coal contaminants in coal-fired power plant wastewater as a function of coal type, unit configurations, and unit operation profile with uncertainty analysis. This project was in response to the U.S. Department of Energy (DOE) Solicitation DE-FOA-0001842. The project duration was between September 01, 2018, and December 31, 2021 (no-cost extension filed, due to the Covid-19 pandemic restrictions, and approved). Field and lab test program was conducted with the main goal to characterize coal contaminants in coal-fired power plant wastewater as a function of coal type, unit configurations, and unit operation profile with uncertainty analysis. In this project, the team of Lehigh University (prime recipient) and Western Kentucky University identified two suitable Thermoelectric Power Plants (TTPs) firing bituminous and sub-bituminous coals respectively, designed test plans, and performed sample collection. Sampling included coal from each TTPs power generation units, Wet Flue Gas Desulfurization (WFGD) slurry material and waste-water samples taken from the outlet of the water treatment tank prior to discharge and other pertinent locations. Coal samples are dried, crushed, and pulverized according to the American Society for Testing and Materials (ASTM) methods. The prepared coal samples are analyzed for normal proximate and ultimate analysis tests in addition to the toxic metals and anions according to ASTM methods. The FGD slurry materials are analyzed for toxic metals and anions according to Electric Power Research Institute (EPRI) or Environmental Protection Agency (EPA) methods, as appropriate. The wastewater samples from the water treatment tank outlet are analyzed for toxic metals and anions according to EPA methods. The effluent species analyzed include mercury, arsenic, selenium, nitrate/nitrite, bromide, and chlorine. This project provided results of effluent conditions as a function of coal type, unit configuration, and unit operation profile, and identified the levels of uncertainty in the effluent results.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2022

Evaluation and beneficiation of high sulfur and high alkali fly ashes for use as supplementary cementitious materials in concrete

Coal-fuel power plants with semi-dry or dry flue gas desulfurization (FGD) systems produce high sulfur and/or high alkali fly ashes due to comingling of fly ash with FGD products. Such fly ashes do not meet the SO 3 content limit (5.0% max.) of ASTM C618 or are unable to mitigate the alkali-silica reaction. The mineralogy of the sulfur present in these ashes can vary significantly (e.g., CaSO 4 , CaSO 3 , Na2SO 4 ) based on the FGD technology used and this affects the performance of these fly ashes in concrete. Thus, the single SO 3 % limit of ASTM C618 is unable to capture the complexity and performance of fly ash, and this results in elimination of potentially viable pozzolans for concrete. Here this study performs a systematic investigation of the effect of SO 3 type and content in fly ash on various performance parameters of cement-fly ash pastes and mortars, including workability (flow and flow retention), pore fluid pH, setting time, strength development, and potential for deleterious expansion. To better quantify and understand these effects, the study considers both real and doped fly ashes (i.e., a blend of specification-compliant fly ash with target sulfur compounds). The poor performance observed in the case of setting time and pore fluid pH was successfully mitigated using chemical admixtures.

36 MATERIALS SCIENCE↗
DOE OSTI2021

Concentrating Rare Earth Elements in Coal mine drainage Using Coal Combustion Products through Abandoned Mine Land Reclamation

Rare earth elements (REEs) (including scandium, yttrium and a group of 15 lanthanides) are often considered to be critical components in the productions of renewable energy hardware, electric vehicles, health care and military equipment, and consumer electronic products. The demand of REEs has been projected to be growing at an annual rate of 5-9% in the next 25 years. In 2011, the global demand of total rare earth oxides (REOs) was estimated to be approximately 105,000 tons, which is expected to grow to 210,000 tons by 2025. China overwhelmingly dominates the current worldwide rare earth productions but has strategically restricted its exports, causing significant instability for the global market. In response to the increasing demand for REEs and the supply dominance of China, identifying alternative sources of REEs has become a critical issue for the United States and other countries. Coal, coal ash, and coal mine drainage (CMD) are considered to be the alternative sources of REEs. In the U.S., high REE concentrations have been reported to be closely associated with coal deposits, including the Appalachian Basins. When surface and/or groundwater come in contact with geologic strata containing sulfide minerals exposed by coal mining, the accelerated oxidation of sulfide minerals in the presence of ferric iron and/or oxygen can produce sulfuric acid. The process promotes the weathering of REE-bearing rocks and minerals in the host geologic strata. Compared to average river water and seawater, the concentrations of REEs can be orders of magnitude higher in CMD. In this study, we demonstrated a trap-extract-precipitate (TEP) process that can effectively recover REEs from CMD. The three-stage TEP process uses alkaline industrial by-products to capture REEs from CMD and then applies an extraction/precipitation procedure to produce a feedstock that can be economically processed to produce marketable rare earth oxides. The alkaline industrial by-products tested in this study include the residual from a water softening process (DRWP sludge) and two types of stabilized flue gas desulfurization materials (sFGDs). sFGD material is a mixture of lime (CaO) and two coal combustion by-products, calcium sulfite FGD by-product and fly ash. The objectives of this study are to (1) validate the effectiveness and feasibility; (2) determine mechanisms controlling the rare earth recovery, (3) quantify the associated economic and environmental benefits, and (4) evaluate the full-scale application. To achieve these objectives, tasks to be carried out in this proposed project are organized into three phases. In the first phase, the research team collaborated with Ohio Department of Natural Resources, American Electric Power, The Wilds (a nonprofit wildlife conservation organization), and a private landowner to carry out field investigations aimed to screen and evaluate the seasonal changes of rare earths in the CMD discharges that have high recovery potentials. Next, the recovery of REEs from CMD was tested using a series of lab-scale column and batch tests under, respectively, percolation and completely mixed conditions. Results obtained from these lab-scale studies show that all three tested solids are very effective in retaining REEs. Over 98% of the CMD REEs that contacted the solids were captured before the solids exhausted their neutralization capacities. We also determined an extraction process using a non-acid, organic ligand extraction solution that can effectively remobilize the retained REEs from the spent solids (over 90%). The REE concentrate (>7.5 wt. % of total REEs) is then formed in an aeration process. The TEP process uses environmentally benign industrial by-products and a naturally-occurring organic ligand to mitigate CMD and recover REEs. Techno-economic analysis (TEA) and life-cycle assessment (LCA) was carried out in the third phase. The engineering-economic costs and net energy, net CO2 emissions, and water and other requirements were investigated to understand the economic and environmental implications of this process. This work uses mass and energy balances from laboratory-scale experiments to estimate the economic costs and environmental impacts. The results suggest that passive treatment systems that use DRWP sludge are preferred over those that use sFGD material, because of lower economic costs ($89,300/yr with a unit cost of $86/gT-REE vs. $89,800/yr, or $278/gT-REE) and improved environmental performance across all indicators from two different impact assessment methods. These differences are largely attributable to the larger capacity of DRWP sludge in the passive treatment application. We envision this TEP process can be integrated with abandoned mine land (AML) reclamation to create an approach that can add economic incentives for AML reclamation, remediate CMD discharge, and eliminate public safety hazards and threats to local environment and ecological systems posed by AMLs. It can restore lands and communities that are adversely impacted by legacy mining.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2022

Emissions mitigation technology for advanced water-lean solvent-based CO 2 capture processes

This technical final report submitted to DOE/NETL presents all the research activities performed during the entirety of DE-FE0031660 project-Emissions Mitigation Technology for Advanced Water-Lean Solvent-Based CO 2 Capture Processes which spans from October 2018 through March 2022. RTI International has been conducting studies from fundamental and operational aspects to reduce the overall amine emissions from the advanced Water-Lean Solvent (WLS) systems, specifically RTI’s Non-Aqueous Solvent (NAS). This technical final report will highlight the key findings from project which align closely to the project objectives which are: Identify the contribution of vapor loss, entrainment, and aerosols to the overall emissions of water-lean systems; Determine the significance of CO 2 capture system operating parameters to the amine emissions; Develop an emissions model based on critical operating parameters; Evaluate the effectiveness of emissions mitigation devices to reduce the amine emissions to <1 ppm under flue coal-fired flue gas; and, Determine the contribution of the ECTs to the overall CO 2 capture cost. The following are the key findings based on numerous tests using both lab-scale setups and parametric testing performed at RTI’s Bench-scale Gas Absorption System (BsGAS). During the BP1, the aerosol generation system and monitoring equipment were installed at BsGAS to produce and determine the aerosol characteristics during the NAS CO 2 capture process. The aerosol produced by this setup produced aerosols with the peak diameter and concentration of 50 micron and 1.2E10 7 cm -3 , respectively. These particle sizes and concentrations are matched to those observed in the actual coal-fired power plant flue gases and expected to be found at the absorber inlet of the CO 2 capture system. Over 1,300 hours of parametric testing have been conducted to evaluate the impact of the aerosols and operating conditions during the CO 2 capture with NAS on the overall amine emissions in the treated flue gas. At the worse condition tested, the presence of the aerosols in the flue gas could increase the overall emissions by 10X compared to the baseline emissions from NAS’s vapor pressure. CO 2 capture rate was found to be a main factor impacting the overall emissions as well as aerosol size and concentrations in the absorber off-gas. The higher CO 2 capture rate, the higher amine emissions in the treated gas. The temperature difference between the temperature bulge seen in the absorber and the water wash temperature also impacts the particle growth where the larger the temperature difference, the more amine emissions from aerosols in the treated gas. The majority of the aerosols did not grow substantially in the system, and the particle concentrations remained nearly constant between the absorber inlet and wash outlet. Only a small portion of the particles were found to grow significantly. The high efficiency demister with mesh size of 5-10 micron can be installed to remove a portion of the aerosols from the gas stream leaving the water wash. Overall, these results from parametric testing have established the emission baseline and validate our assumption on the need of emission control technologies (ECT) in order to minimize the emissions from the baseline NAS CO 2 capture process. Over 2,000 of BsGAS operating hours was used to investigate a handful of process improvements which led to a selection of the vital few changes that effectively control the amine emissions. These process improvements are lime-coated-filters for absorber gas inlet, advanced demister at the top of the absorber, a second water wash with amine recovery unit were designed, installed, and tested at BsGAS at the end of BP1. The result showed that the NAS CO 2 capture process with these additional emission control devices could lower the amine emission in the treated gas to about 1 ppm using a simulated coal-fire flue gas stream. The main contributor in lowering the amine emission came from the second water wash with amine recovery unit where the amine concentration in the scrubbing water was kept below 2 wt% through a continuous amine removal via an adsorbent bed, resulting in a low amine vapor pressure. The adsorbent bed was regenerated via a direct steam regeneration and the recover amine was returned to the absorber to minimize wastewater and makeup amine. A flue gas generation system was designed and installed during the first half of BP2 to support the emission testing using a real coal-derived flue gas. The system is capable of generating both coal- and natural gas- derived flue gases with the composition of the gaseous species highly resemble to that of the power plant flue gases. The particulates detected in the coal-derived flue gas showed the mean diameter of 1 micron. The CO 2 capture operating was then proceed using the real coal-derived flue gas where the amine emission was controlled to be about 0-3 ppm for the total run time of about 200 hours. Similar testing was conducted with natural gas-derived flue gas and the result showed a highly amine emission of 30 ppm under the total run time of 200 hours. The Principal Component Analysis (PCA) and the Partial Least Squares Projection to Latent Structures (PLS) techniques were applied to the parametric testing data to derive a multivariate statistical model. The model was validated and trained with half of the data collected, and the predictive ability of the model was evaluated using the remaining half of the data. The resulting empirical model was capable of predicting the overall emissions from the NAS process without the ECTs with ±15% accuracy (average absolute deviation, AAD) in BP1. As more emission data were obtained under the real coal-flue gas in the BP2, the model incorporated these new set of data to reflect the final process configuration, operating parameters, and amine emission. This results in the updated empirical model predicting the amine emission from the NAS CO 2 capture process with 84% goodness-of-fit (R 2 ), 85% predictability (Q 2 ), and 15% AAD. The study evaluates the use of RTI’s Non-Aqueous Solvent technology for 90% CO 2 capture from a net 650 MWe pulverized coal power plant, downstream of the flue-gas desulfurization unit. The captured CO 2 has a purity of > 95% CO 2 , and is dried, compressed to 15.3 MPa (2,215 psia), ready for sequestration. The analysis uses Case B12B from the DOE Baseline study on Bituminous Coal, Revision 4 where the Cansolv CO 2 capture plant is replaced by the RTI CO 2 Capture plant. The CO 2 capture plant has been sized to capture >90% CO 2 from flue gas derived from a net 650 MWe supercritical pulverized coal power plant. The CO 2 capture plant is equipped with emission control technologies that limits the amine emissions to < 1 ppm. Two different cases were evaluated for the technoeconomic study. The key difference between the two cases is the regenerator pressure. In Case 1, the regenerator operates at 0.195 MPa (28.3 psia), whereas in Case 2, the regenerator pressure is 0.44 MPa (64 psia) thus removing the need for the first stage of compression of the eight-stage compression train. Results from the TEA are compared against the DOE reference cases for SCPC plant with and without CO 2 Capture (Case B12A and Case B12B of the DOE Baseline study, respectively). Case 2 with CO 2 regeneration at higher pressure results in the lower cost of CO 2 capture. The total capital cost of the capture process has been estimated using 2018 dollars in Aspen Process Economic Analyzer and was estimated to be $579 MM. The capture plant operation leads to a total parasitic power loss rate of 96 MWe, resulting in a decrease in pulverized coal power plant efficiency of 7.8% points. The resulting cost of electric power increases from 64.4 mills/kWh, for no capture, to 97.5 mills/kWh, with 90% capture, an increase of 51% in the COE. The cost of capturing 90% CO 2 was estimated to be $38.2/tonne-CO 2 , and meets the DOE target of $40/t-CO 2 . Emission control technologies (ECT) investigated in this project includes a second water wash with use of activated carbon beds for removal of amine from the wash water prior to recirculation in the water wash. These ECT allow operation of the CO 2 capture plant with < 1 ppm amine emissions with the treated flue gas and contributes to $2.4/t-CO 2 captured. Amine emissions derived from thermal and oxidative degradations were investigated under this project along with the emissions derived from aerosols for the NAS system. The thermally degraded of the lean NAS showed less than 4% decreased of the original total amine content in the NAS at 150 °C while the result obtained at 120 °C showed no drop in total amine content, suggesting that thermal degradation of the NAS is minimal. These results also suggested that the thermally degraded species are not likely formed and contributed to the emissions due to the low regeneration temperature of the NAS at 90-105 °C. The oxidative degradation, on the other hand, could become problematic as some of these oxidative degraded species were observed during the NAS-5 testing at National Carbon Capture Center (NCCC) and SINTEF in our previous project. The rapid screening of selected inhibitors suggested that oxidative degradation of NAS can be suppressed using thiol containing compounds in amounts of at least 1 mol%. The detailed mechanistic degradation pathway was conceived for a specific amine used in NAS formulation during BP2. he reduction of the nitrosamines caused by the NO x present in the flue gas was also examined. The study suggested that the thermo-chemical treatment of the NAS solvent would be a more effective and economically viable compared to removing NO x at the DCC.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2021

Subtask 2.6 – Optimization of Aerosol Mitigation Technology for Postcombustion CO 2 Capture

Growing concerns over the impact of CO 2 emissions from combustion sources on global climate change have prompted numerous research and development projects aimed at developing cost-effective technologies for CO 2 capture. One family of technologies being demonstrated at pilot and full scale globally is postcombustion CO 2 capture (PCCC) systems that employ amine-based solvents. The captured CO 2 can be compressed and permanently stored underground or used for enhanced oil recovery (EOR). The proximity of North Dakota’s lignite-fired fleet of power plants to potential CO 2 storage options creates a unique atmosphere for PCCC within the state. However, the aerosols present in lignite flue gas present a challenge for large-scale PCCC at North Dakota power plants. Aerosols can negatively impact the long-term performance of amine-based solvents for CO 2 capture. Amine-based solvents are volatile, and aerosols provide nucleation sites where amine vapors can condense. Because aerosols cannot be easily captured at the column outlet using conventional technologies, the amine-laden aerosols escape the system and lead to accelerated solvent losses. Moreover, aerosol components can chemically react with amines to form degradation products that can permanently deactivate the amine, cause fouling, and lead to hazardous emissions. Many of the elements that have been shown to catalyze solvent degradation are present in lignite coals and can exacerbate solvent replacement economics. Understanding this issue is critical to the implementation of solvent-based CO 2 capture systems as applied to lignite-fired generation systems. The Energy & Environmental Research Center (EERC) designed and carried out this project to optimize aerosol mitigation technology for PCCC at a lignite-fired power plant. To meet the goal of this project, the following objectives were identified: Determine the effectiveness of a wet electrostatic precipitator (WESP) on collection of aerosols at a low-rank coal-fired power station. Determine the impact of aerosols on the efficiency and degradation products of amine-based carbon capture systems fired with low-rank fuels. Work was conducted at Minnkota Power Cooperative’s (MPC’s) Milton R. Young (MRY) Station Unit 2 using a slipstream of flue gas from the outlet of the plant’s flue gas desulfurization (FGD) unit. To gather initial data for sizing and specifying a WESP for this system, a temporary pilot-scale WESP was rented and installed on-site. Several different conditions were tested to examine the impact of flow rate, voltage, and current on WESP performance. The WESP was effective at removing large particulate (>200 nm) but caused an increase in fine particulate (<75 nm). Fine particulate material at the inlet and outlet of the WESP was collected, analyzed, and showed that crystalline sulfates carried over from the plant’s FGD unit were being converted to fine aerosols and SO 2 was being converted to SO 3 through the WESP. Additionally, the high moisture content of the flue gas stream at this sample location also contributed to an overall increase in aerosol mass under some of the test conditions. Using the results from the rented WESP, the project team installed a smaller-scale WESP upstream of the EERC’s slipstream CO 2 capture system. Flue gas was routed through a pilot-scale FGD unit to remove SO 2 to very low levels (~1 ppm) and then through a direct contact cooler (DCC) to further cool the gas and to remove moisture. The gas exiting the DCC was then routed through the new WESP before passing to the CO 2 absorber columns. Fluor’s amine-based solvent was used to scrub CO 2 from the slipstream through a set of two absorber columns. The rich solvent was regenerated in a stripper column by heating to drive off captured CO 2 . The system operated using a catch-and-release method where the CO 2 was separated to provide data on the process, but the captured CO 2 was released back into the host site stack. Aerosols and sulfur species were measured at multiple locations throughout the pilot-scale system. The inlet FGD and DCC removed much of the particulate matter and gaseous sulfur upstream of the WESP. With this configuration, the WESP achieved >95% particulate capture. The new WESP did not show any of the increases in SO 3 or other aerosol species that had been consistently observed with the larger-scale WESP installed immediately downstream of the plant’s full-scale FGD unit. Particulate samples captured and analyzed from the WESP inlet did not show any presence of crystalline sulfate materials, indicating that the pilot-scale FGD and DCC were efficient at reducing carryover from the plant’s full-scale FGD unit. A set of parametric tests were conducted on the new WESP to assess the impacts of flow rate, voltage, number of online WESP fields, and gas-phase sulfur content on aerosol and sulfur transformations. The results showed that the WESP performed similarly well at all sets of conditions. Sulfur and particulate matter exiting the WESP were further reduced through the absorber column as the amine-based solvent captured some of the residual contaminants. Solvent analysis showed that these species were slowly concentrating in the solvent over the duration of the test. When the WESP was taken offline and the sulfur slip through the FGD allowed to rise, the sulfate content in the solvent rose sharply, showing that the extra FGD and WESP were effective at reducing sulfate and cation uptake. This would be expected to extend amine-based solvent life by slowing the formation of heat-stable salts and other degradation products. This subtask was cofunded through the EERC–U.S. Department of Energy Joint Program on Research and Development for Fossil Energy-Related Resources Cooperative Agreement No. DE-FE0024233. Nonfederal funding was provided by the North Dakota Industrial Commission and MPC.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2023

Synthetic Calcium Carbonate Production by Carbon Dioxide (CO 2 ) Mineralization of Industrial Waste Brines

The global scale of CO 2 emission has crossed 36 B tons, and the United State represents 14% of the total emissions. In light of the high cost associated with current CO 2 capture processes ($60-to-150 per ton of CO 2 ), carbon capture and utilization (CCU), wherein CO 2 is converted to beneficial products, provides a pragmatic path to overcome the economic barrier for CO 2 emissions control. In particular, CO 2 mineralization offers an attractive route as it produces high-value mineral carbonates that sequester CO 2 in a stable form. For instance, fine precipitated calcium carbonate, a valuable product with unit price in the range of $230-280/t and a global market projected to reach 99 M tons in 2020, can be produced by capturing CO 2 within aqueous Ca 2+ solution. However, two critical challenges need to be overcome—(i) the need for costly processes such as electrolysis or addition of alkali hydroxides to maintain alkalinity during mineralization, and (ii) the geographic availability of Ca-rich solutions (or brines) which often renders efficient integration with power plants impractical. To simultaneously address these challenges, this project developed two novel routes to enable carbonate production based on efficient CO 2 mineralization. In one variation, the project developed a new alkaline carbonation process to capture CO 2 and produce calcite precipitates from coal ashes. Herein, coal ash is carbonated first in a sodium carbonate solution. The carbonation reaction produces sodium hydroxide and raises the solution pH. This high-pH hydroxide solution is then used for CO 2 capture, which converts the sodium hydroxide solution back to sodium carbonate to repeat the carbonation cycle. The carbonated ash residue is refined with a CO 2 pressure swing step to produce high-purity precipitated calcium carbonate. In another variation, Ca-rich produced water brine serves as the Ca-source to mineralize CO 2 . An H + /Na + ion-exchange cycle was designed to provision alkalinity during mineralization and regenerate the ion-exchange reagent in brines with high salinity. Ca-depleted brines can then be treated within a centralized water treatment facility. Both variations beneficially utilize reject streams—such as coal ashes and brines from oil and gas extraction or CO 2 storage operations—that are available at substantial quantities in the vicinity of coal power plants within the U.S. In addition to technology development, this project included techno-economic and life-cycle analysis to identify technically and economically appropriate solutions for power plants in different geographic locations. Taken together, the project provides a unique route to integrate CO 2 emissions control and waste handling/treatment for coal power plants, while producing a high-value product to offset the economic burden associated with waste management. The developed processes utilize post-desulfurization flue gas from coal-fired power plants as is. The CO 2 conversion reactions are performed in alkaline brines at ambient pressure from the flue gas, thereby minimizing the energy burden. By beneficiation of industrial waste streams with low energy input, the processes offers significant technical advantages in energy and CO 2 footprint over the current paradigm of precipitated calcium carbonate production, which involves calcination of limestone at processing temperatures in excess of 800 °C. Overall, this project developed viable CO 2 mineralization processes while strategically maximizing the economic benefit.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2024

Potential reductions in fine particulate matter and premature mortality following implementation of air pollution controls on coal-fired power plants in India

Coal-fired power plants (CFPPs) account for > 70% of electricity generation in India, but < 5% of facilities have installed technologies for sulfur dioxide (SO 2 ) and nitrogen oxide (NO X ) removal. Emissions of these pollutants lead to the formation of fine particulate matter (PM 2.5 ) and an increased risk of premature mortality for exposed populations. Here, we use a nested version of the GEOS-Chem global chemical transport model (0.5° × 0.625° resolution) for India to estimate reductions in PM 2.5 concentrations that could have been achieved by implementing existing emission control technologies like flue-gas desulfurization (FGD) and/or selective catalytic reduction (SCR). We quantify the associated burden of disease using the integrated exposure response (IER) and global exposure mortality model (GEMM) functions and compare the costs of premature mortality to those for FGD installation. Model simulations for 2010 suggest installation of FGD would have reduced mean annual PM 2.5 concentrations across India by 8%, compared to 3% with SCR installation, and 11% with both FGD and SCR. A 7–28% reduction in PM 2.5 was simulated for local communities closest to CFPPs (same model grid cell), leading to up to 17% reduction in annual premature mortality. Overall, more than 0.21–0.48 million premature deaths would have been avoided over a 10-year period if FGD had been implemented on all CFPPs, compared to 0.09–0.21 million with SCR and 0.22–0.72 million with both FGD and SCR. Benefits associated with such actions are approximately $\$18.1$–$\$604$ billion USD per year, which is equivalent to ~ 0.44 to 10% of India’s GDP. These results suggest that monetary benefits from avoided premature mortality far outweigh the capital and operational costs of FGD and/or SCR installation of $\$19.5$ billion and/or $\$32.8$ billion per year, respectively. This information is essential because the high costs of installation and operation are often given as reasons for delaying installation and commissioning. Finally, we conclude that policy actions to control air pollution from CFPPs are economically justifiable.

63 RADIATION, THERMAL, AND OTHER ENVIRON. POLLUTAN↗
DOE OSTI2025

Ammonium-coordinated exchanger (ACE) functionalized silica sorbents for recovering/removing aqueous anionic contaminants

There are limited studies of functionalized silica anion exchange sorbents used for critical/heavy metal recovery/removal relative to polymeric and other inorganic materials. This work features ammonium-coordinated exchanger (ACE) anion exchange particle sorbents prepared by either acid-washing epoxy-crosslinked polyethylenimine (PEI) hydrogen bonded within/to a silica particle sorbent (two-step method) or reacting a di-chlorinated crosslinker, α,α-dichloro-p-xylene (DPX), with PEI within silica (single-step method). Energy dispersive X-ray spectroscopy (EDS) and infrared spectroscopy confirmed the presence of -NH 2 + ···Cl - and -NH 3 + ···Cl - groups, which removed oxyanionic species –arsenate, selenate, chromate, sulfate, phosphate, and nitrate– plus bromide from ideal solutions, authentic acid mine drainage (AMD), and authentic flue gas desulfurization (FGD) wastewater. Affinity of the anions for ACE varied across single- and mixed-element solutions. However, affinity for CrO 4 2- was among the highest in both cases. Total anion uptake by the optimized ACE, PEI-E3-HCl_1.1, reached 1.2 mmol anion/g-sorb. (0.56 mmol CrO 4 2- /g), or ∼2.3 mmol negative charge/g-sorb. This was close to the 0.52 mmol CrO 4 2- /g of a commercial anion exchange resin. Near-consistent removal of 20–80 % of each anion from FGD during an eight-cycle adsorption-desorption (1 M NaCl) test predicted good ACE viability for testing under practical conditions at larger scale.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2020

Computational Chemistry-Based Evaluation of Metal Salts and Metal Oxides for Application in Mercury-Capture Technologies

Anthropogenic mercury emission to the atmosphere adversely affects the environment, wildlife, and human health. Accordingly, the design and implementation of improved mercury-capture technologies have received increased attention. We present a computational chemistry-based screening study to guide the development of mercury-capture materials. We use density functional theory (DFT) to probe the efficacy of metal salts and metal oxides (NaCl, NaBr, KCl, KBr, CaCl 2 , CaBr 2 , NaNO 3 , and MgO) toward mercury capture and their ability to be regenerated for continued use. We focus on three primary sources of mercury emission as elemental gaseous mercury (Hg(0)) or oxidized gaseous mercury species (Hg(II); HgCl 2 or HgBr 2 ): (i) Hg(0) emission from artisanal Au production; (ii) Hg(II)/Hg(0) emission from inlet/outlet streams for flue-gas desulfurization (FGD) operation; and (iii) Hg(0) and Hg(II) emission from cement production. Our results suggest that CaCl 2 and CaBr 2 are good candidates for capturing Hg(0) in artisanal Au production. For FGD operation, KBr, MgO, CaCl 2 , and CaBr 2 are good candidates for capturing HgCl 2 and HgBr 2 , while CaBr 2 is the only studied material that can capture Hg(0) from the outlet FGD stream. For cement production, CaBr 2 is the only material of those studied that can capture Hg(0), HgCl 2 , and HgBr 2 . Furthermore, our DFT results can accelerate the development of cheap and regenerable mercury-capture materials, as well as better prevent the release of mercury to the environment.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2020

Guest-Controlled Incommensurate Modulation in a Meta-Rigid Metal–Organic Framework Material

Structural transitions of host systems in response to guest binding dominate many chemical processes. We report an unprecedented type of structural flexibility within a meta-rigid material, MFM-520, which exhibits a reversible periodic-to-aperiodic structural transition resulting from a drastic distortion of a [ZnO 4 N] node controlled by the specific host–guest interactions. The aperiodic crystal structure of MFM-520 has no three-dimensional (3D) lattice periodicity but shows translational symmetry in higher-dimensional (3 + 2)D space. In this work, we have directly visualized the aperiodic state which is induced by incommensurate modulation of the periodic framework of MFM-520·H 2 O upon dehydration to give MFM-520. Filling MFM-520 with CO 2 and SO 2 reveals that, while CO 2 has a minimal structural influence, SO 2 can further modulate the structure incommensurately. MFM-520 shows exceptional selectivity for SO 2 under flue-gas desulfurization conditions, and the facile release of captured SO 2 from MFM-520 enabled the conversion to valuable sulfonamide products. MFM-520 can thus be used as a highly efficient capture and delivery system for SO 2 .

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2022

Recovering Rare Earth Elements from Coal Mine Drainage Using Industrial Byproducts: Environmental and Economic Consequences

Coal mine drainage (CMD) impairs tens of thousands of kilometers of U.S. waterways each year, in part with the leaching of low concentrations of rare earth elements (REEs). REEs are essential for modern technologies, yet economically viable natural deposits are geospatially limited, thus engendering geopolitical concerns, and their mining is energy intense and environmentally destructive. This work summarizes laboratory-scale experimentalresults of a trap-extract-precipitate (TEP) process and uses the mass and energy balances to estimate the economic costs and environmental impacts of the TEP. The TEP process uses the alkalinity and filtering capacity of stabilized flue gas desulfurization (sFGD) material or water treatment plant (WTP) sludge to remediate CMD waters and extract REEs. Passive treatment systems that use WTP sludge are cheaper than those that use sFGD material ($\$$89,300/year or $\$$86/gT-REE vs. $\$$89,800/year or $\$$278/gT-REE) and have improved environmental performance across all indicators from two different impact assessment methods. These differences are largely attributable to the larger neutralizing capacity of WTP sludge in the treatment application.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2025

Novel anaerobic selenium oxyanion reducers native to FGD wastewater for enhanced selenium removal

Biological treatment is a recognized approach for removing selenate and selenite oxyanions present in flue gas desulfurization (FGD) wastewater. However, the knowledge of the specific microbial species or communities responsible for reducing water-soluble selenium oxyanions to insoluble elemental selenium remains limited. In addition, the selenium oxyanion reduction genes and pathways have yet to be understood in these wastewaters. This study characterizes selenium oxyanion-reducing bacteria (SeRB) native to FGD wastewater, and the resulting elemental selenium particles formed. By selecting native SeRB microbes in a defined media, a novel resolution of these organisms has been achieved. This research identifies previously unrecognized selenium oxyanion-reducing capabilities in Anaerosolibacter, alongside predominant SeRB from Mesobacillus and Tepidibacillus genera. This work encompasses both 16S and metagenomic techniques to recover novel metagenome-assembled genomes, distinct to this environment. The biogenic selenium produced by these organisms was predominantly of elemental selenium, either amorphous or with a hexagonal structure. This study identifies the SeRB present in FGD wastewater and characterizes their selenium products, offering crucial insights to enhance the efficiency of biological treatment strategies and the potential of selenium recovery from this industrial waste.

59 BASIC BIOLOGICAL SCIENCES↗
DOE OSTI2022

Overview and How-to Tutorial Videos for Using NEWTS Data

Overview and How-to Tutorial Videos for Using NEWTS Data Video 1: Overview of NEWTS Database Video 2: How-to tutorial for EPA Flue Gas Desulfurization (FGD) Effluent NEWTS dataset Video 3: How-to tutorial for USGS Produced Waters NEWTS dataset Video 4: How-to tutorial for EPA Ash NEWTS dataset Video 5: How-to tutorial for Quillinan, et al 2018 DOE Geothermal Technology Office REE dataset Video 6: Tutorial video on navigating the NEWTS Dashboard, with an overview of NEWTS and navigating between the NEWTS Dashboard and Datasets (https://netl-doe.maps.arcgis.com/apps/dashboards/a5fa4192f7c6478dab3d6180d9c30b84) Video 7: Additional tutorial video on navigating the NEWTS Dashboard and investigating specific data points in the Dashboard and Datasets Video 8: Re-record of recent webinar giving an overview of the NEWTS Database and Dashboard, including interacting with the NEWTS Dashboard, locating specific data points, and finding the relevant streams in the NEWTS Database and datasets on EDX. Includes overview of the datasets, case studies, and steps for taking stream data from the database and modeling stream data in OLI Studio and Geochemist's Workbench. Note: Video 3 tutorial is also applicable to the USGS Brackish Water NEWTS dataset.

Aqueous Chemistry↗
DOE OSTI2025

NEWTS Economic Data Dashboard: Critical Materials for Energy

The NEWTS Economic Data Dashboard: Critical Materials for Energy is an economic screening tool for assessing the concentration and potential value of the 18 critical materials for energy in fossil energy-related wastewater across the United States. Datasets used to develop the dashboard and complete economic calculations are available as supplementary downloads. These resources were developed primarily using geochemical composition and volume data from the NEWTS Integrated dataset (version 1.0). Energy-related wastewater types presented in the dashboard include produced water (PW), brackish groundwater (BW), acid mine drainage (AMD), coal combustion residual leachate (CCRL), power plant flue gas desulfurization wastewater (FGD), and geothermal fluids. The concentrations of the following critical minerals were included in the analysis, when available: Al, Co, Cu, Dy, F, Ga, Ge, C, Ir, Li, Mg, Mn, Nd, Ni, Pt, Pr, Si, Tb. This economic screening tool was built to support identification of promising critical mineral feedstocks and economic research targets.

Critical Minerals; Critical Minerals and Materials↗
DOE OSTI2021

Energy Efficient Waste Heat Coupled Forward Osmosis for Effluent Water Management at Coal-Fired Power Plants

This project sought to evaluate the technical and economic viability of the Aquapod©, a transformational low energy (<200 kJ/kg water) waste heat coupled forward osmosis (FO) technology, to manage effluents, meet cooling water demands, and achieve water conservation in a coal-fired power plant environment. The Aquapod© process is innovative because it is heat-driven, avoids the evaporation of water, and uses no toxic chemicals such as ammonia or amines. The Aquapod© process accomplishes this using an aqueous two-phase system (ATPS) coupled FO process. The evaluation revealed that the Aquapod© process offers a pathway to exploit waste heat resources within a power plant to achieve flue-gas desulfurization (FGD) wastewater volume reduction and water recovery with minimal pretreatment. Water recovery of 80% from FGD wastewater was achieved with minimal pretreatment, exceeding the project target of 50%. The estimated electrical energy of 2.16 kWh/m 3 of water produced for the Aquapod© process met the project target of < 3.6 kWh/m 3 . The heat required for the process operation was approximately 186 kJ/kg of produced water, which was slightly lower than the project target of 200 kJ/kg. The estimated treatment cost for installing and operating the Aquapod© process in conjunction with a spray dryer evaporator to achieve zero-liquid discharge (ZLD) of the 100 gpm FGD wastewater was $13.24/m 3 over a 30-year lifetime. As a point of reference, this study’s host power plant currently incurs a cost of $3.70/m 3 – $8.87/m3 on a discharged volume basis to discharge its wastewater into the publicly owned treatment works (POTW) after physical-chemical treatment. Therefore, the Illinois power plant would incur an incremental cost increase of $4.37/m 3 – 9.54/m 3 to achieve ZLD using the Aquapod© and spray dryer combination. Ample opportunities exist to further lower the ZLD capital and operating costs in the next design iteration to attain pipe parity at the higher end of the site treatment costs.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2021

Novel Algae Technology for CO2 Utilization

The United States, the world’s largest energy user and second largest CO2 emitter, is heavily dependent on fossil energy. In 2014, U.S. coal burning utilities emitted ~1562 million (MM) tons/year (TPY) of CO2 into the atmosphere, accounting for 76% of the total US power sector emissions1. Hence, reducing the CO2 emission footprint from coal plants is widely viewed as a key element in mitigating global warming. Despite significant interest, implementation of CO2 capture technologies has been constrained by the high capture cost which significantly increases the total cost of electricity. Not only is capturing CO2 with traditional technologies expensive, but generally the CO2 has little value and additional expense must be incurred for sequestration. This project funded by a SBIR grant from the U.S. D.O.E. to Helios-NRG in collaboration with the State University of New York at Buffalo (UB) and Membrane Technology and Research Inc. (MTR) aimed to develop a novel, algae based technology to capture CO2 from the effluent of coal-based power plants and convert it to renewable bio-fuels and higher value co-products such as animal feed and nutraceuticals with the potential to enable a substantial reduction in the net cost of carbon capture. The Phase 2 project was aimed at further demonstrating the technical feasibility of the proposed multi-stage continuous (MSC) flow CO2 capture system and the generation of high-value co-products to offset the CO2 capture cost. The project was completed and the project objectives were met and exceeded. A first-of-a-kind integrated, laboratory scale MSC process unit was fabricated and tested in a greenhouse. The tests were conducted with the preferred algae species identified in Phase I and simulated flue gas containing contaminants at levels typically present in the post flue gas desulfurization (FGD) stream, including ~12% CO2, acid gas (SOX, NOX), and a large number of heavy metals. The tests were successful and demonstrated a 25g/m2/day seasonal average algae productivity and an 80% CO2 capture efficiency. Two new algae species were identified for high-value nutraceutical production. Studies to improve growth rate and nutraceutical content of these algae species were performed and a pathway for further improvements was identified. A new dewatering technology called DeAqua was further advanced. Significant improvement in the performance index was achieved. The anti-fouling membrane was developed and fabricated into a module. The fabricated membrane module was tested with algae slurry and demonstrated improved fouling resistant properties, that can potentially reduce the cost and energy of the critical dewatering step. Test data were used to simulate operation of the overall process. The preliminary economic analysis was updated and modelled based on a 5000-acre algae farm. To the extent possible, the financial and operating assumptions used were the same as those used in the DOE’s 2022 projections for algae technology for CO2 capture and utilization. The results showed the proposed technology’s potential to significantly reduce the cost of CO2 capture compared to current options and that the high value products generated from the CO2 captured can make a step change in the cost of carbon capture. Plans to advance the technology to Phase 2B were developed and potential end-user partners were identified.

Maloney, James↗
DOE OSTI2021

Demonstrations of Holistic, Lower Cost/Energy Effluent Water Management Approaches for Coal-Fired Energy Plants

The project work conducted under DOE award DE-FE0031678 was comprised of three overarching project goals: (1) evaluate the performance of Saltworks’ Flex EDR Selective process for treating wet flue gas desulfurization (FGD) wastewater, (2) conduct bench-scale testing of wastewater encapsulation as a byproduct management technology for the EDR generated brine, and (3) develop a dynamic water balance model encompassing the results of the aforementioned testing.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2021

Co-Generation Wastewater Treatment at Coal-Fired Energy Plants (Final Report)

Steam electric energy generation typically results in the discharge of one or more effluent streams. Coal-fired energy plant air quality regulations have had the effect of transferring pollutants previously in the flue gas to water by means of the flue gas desulfurization (FGD) system. Combined physical-chemical and biological treatment solutions are currently the most economical approach for treating FGD wastewater. Multi-effect evaporators are significantly higher cost but can meet potential upcoming regulations that are more stringent.

01 COAL, LIGNITE, AND PEAT↗