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All sourcesNASA NTRSDOE OSTI
DOE OSTI2023

Conclusions from 3 years of continuous capture plant operation without exchange of the AMP/PZ-based solvent at Niederaussem – insights into solvent degradation management

A many times heard mantra of solvent degradation management in amine-based post combustion capture is “keep the solvent clean” to minimize solvent consumption. It is assumed that the amine losses would decrease by the removal of metals, degradation products, and reactive trace components which are captured from the flue gas, like NO 2 (as potentially driving components of the amine degradation besides dissolved O 2 ). However, this theoretical hypothesis – based on results from laboratory experiments typically generated with fresh amines – disregards the complexity of the solvent matrix, interaction of potential metal catalysts with degradation products and oxidizing agents, and specific chemical requirements which must be fulfilled before a degradation mechanism can proceed. Degradation of the solvent CESAR1 (aqueous solution of 3.0 molar 2-amino-2-methylpropan-1-ol (AMP) and 1.5 molar piperazine (PZ)) is investigated in a unique long-time test campaign (testing time up to now 40 months; 24/7 operation) without replacement of the solvent inventory at the capture pilot plant at the lignite-fired power plant in Niederaussem. Three solvent management strategies with different effect mechanisms are investigated and evaluated: (a) removal of only anionic compounds and trace elements (within 75 days solvent inventory treated two times) and anionic as well as cationic compounds and trace elements (114 days, inventory treated four times) from the solvent by ion exchange, (b) adsorptive removal of trace elements from the solvent by active carbon in 35% of the operating time, and (c) removal of >80% NO 2 by flue gas pretreatment with thiosulfate/sulfite solution (dosing for 2,000 h). The results of the testing program clearly show that “solvent cleanliness” is not a well-defined parameter and that results from laboratory tests, tests without fully representative industrial flue gasses, and short-term testing of monoethanolamine cannot be generalized for other solvents and industrial application. Furthermore, these results showcase that specific degradation management considering solvent, capture plant and flue gas quality is reasonable. Overshooting efforts for solvent management are contra-productive and produce unnecessary waste streams, efficiency losses and costs.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2026

Collaborative Approach to Identify Degradation Mechanisms and Validate Aging Protocols for a Diverse Set of DAC Materials (TCF Base Technology-Specific Final Report)

This work supports the mission of the U.S. Department of Energy to promote American energy leadership, technological innovation, and economic growth through the development of technologies for cost effective carbon capture. While capture technologies can provide carbon dioxide for enhanced oil recovery, many capture materials suffer from oxidative, hydrolytic and/or thermal degradation which leads to capacity loss and unwanted emissions such as ammonia. Short lifetimes increase operational costs and cost studies suffer from uncertainty because the true lifetimes of many capture materials are unknown. In this study, a suite of capture materials were studied to quantify their degradation, provide insight into the mechanisms that lead to their uptake loss and provide validated accelerated aging protocols for industry.

36 MATERIALS SCIENCE↗
DOE OSTI2022

Oxygen Solubility in Aqueous Amine Solvents with Common Additives Used for CO 2 Chemical Absorption

Major sources of anthropogenic CO 2 are power generation and transportation industries where researcher continue to explore CO 2 emission mitigation strategies as applied to these CO 2 sources through carbon capture, utilization, and sequestration (CCUS). The most mature CO 2 capture technology is post-combustion carbon capture (PCCC) using aqueous amine solutions/solvents, however solvent degradation and regeneration costs are slowing the widespread adoption of PCCC. Solvent degradation of the aqueous amine solutions is mainly caused from the temperature gradient between the absorber and stripper columns and common flue gas components such as SOx, NOx, and oxygen (O 2 ). The two main classifications of solvent degradation are thermal degradation, occurring when the amine reacts with itself at elevated temperatures and anaerobic conditions and oxidative degradation. Oxidative degradation reactions can occur from oxygen mass transfer and free radical oxidation. Metals, such as iron from the corrosion of steel structures used in industrial applications such as PCCC, can help to catalyze these reactions. Various oxidative degradation studies have shown how O 2 concentrations in flue gas and, to a lesser extent, temperature influence the extent of oxidative degradation. Accurately measuring the O 2 solubility, commonly referred to as dissolved oxygen (DO), in a quick, continuous, and efficient manner in aqueous amine solvents should contribute to determine the effectiveness of mitigation strategies for oxidative degradation. Knowing that commercial PCCC amine solvents contain components beyond water, amine, carbonate species and CO 2 , this investigation was conducted to determine the oxygen solubility changes of common aqueous amines solutions with commonly used and published solvent additives. The impact of carbon loadings with and without the additives was also examined. A commercial dissolved oxygen probe was used to measure the DO concentrations and compared them against standard Winkler Method titration values. The results show that antifoam shows minimal change in [DO]. MBT yielded lower DO values, and NaVO 3 showed a higher DO concentration due to interferences. These results indicate that most common amine solvent additives should be expected to minimally impact oxygen solubility and amine oxidative degradation.

60 APPLIED LIFE SCIENCES↗
DOE OSTI2022

Mitigation Methods for Piperazine Oxidation in Post-Combustion Carbon Capture

Piperazine is a promising second-generation solvent for amine scrubbing in post-combustion CO2 capture. However, the oxidative degradation of PZ can cause environmental problems and economic loss. This work presents the effects of two mitigation methods: carbon treating and N2 sparging, on the PZ oxidation in long-term operations. The species and their respective quantities adsorbed by the activated carbon were tested in a bench-scale device. The carbon was then tested in the High Temperature Oxidation Reactor (HTOR), where the solvent oxidizes at a reasonably fast rate. Pilot plant campaigns were also performed at the UT Austin SRP and the National Carbon Capture Center (NCCC) and the effects were verified. When dissolved Fe is removed by carbon treating or other methods, available soluble Fe in the system dissolves and replaces the dissolved Fe. Therefore, all available Fe and ligands need to be removed for the mitigation to be effective. The sources of soluble Fe include fly ash and the corrosion of stainless steel, and the ligands are degradation products. 8 All PZ degraded solvents have two absorbance peaks at 320 nm and 538 nm. The 320 nm peak is caused by dissolved metals, especially Fe, complexed by degradation products. The 320 nm peak is related to the amine degradation level and can be used as a simple and efficient method to estimate the amine degradation rate. The pilot plant data suggest that NO2 can oxidize PZ significantly, possibly through radical reactions. 0.01 mmol/kg-hr absorption of NO2 increased the PZ oxidation rate from 1.2 mmol/kg-hr to 2.5 mmol/kg-hr.

Yuying, Wu↗
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

Targeted electrochemical reduction of carcinogenic N -nitrosamines from emission control systems within CO 2 capture plants

N-Nitrosamines are one of the environmentally significant byproducts from aqueous amine-based post-combustion carbon capture systems (CCS) due to their potential risk to human health. Safely mitigating nitrosamines before they are emitted from these CO 2 capture systems is therefore a key concern before widescale deployment of CCS can be used to address worldwide decarbonization goals. Electrochemical decomposition is one viable route to neutralize these harmful compounds. The circulating emission control waterwash system, commonly installed at the end of the flue gas treatment trains to minimize amine solvent emissions, plays an important role to capture N-nitrosamines and control their emission into the environment. The waterwash solution is the last point where these compounds can be properly neutralized before becoming an environmental hazard. In this study, the decomposition mechanisms of N-nitrosamines in a simulated CCS waterwash with residual alkanolamines was investigated using several laboratory-scale electrolyzers utilizing carbon xerogel (CX) electrodes. Hcell experiments revealed that N-nitrosamines were decomposed through a reduction reaction and are converted into their corresponding secondary amines thereby neutralizing their environmental impact. Batch-cell experiments statistically examined the kinetic models of N-nitrosamine removal by a combined adsorption and decomposition processes. The cathodic reduction of the N-nitrosamines statistically obeyed the first-order reaction model. Finally, a prototype flow-through reactor using an authentic waterwash was used to successfully target and decompose N-nitrosamines to below the detectable level without degrading the amine solvent compounds allowing them to be return to the CCS and lower the system operating costs. Furthermore, the developed electrolyzer was able to efficiently remove greater than 98% of N-nitrosamines from the waterwash solution without producing any additional environmentally harmful compounds and offers an effective and safe route to mitigate these compounds from CO 2 capture systems.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2024

Techno-economic assessment of emissions mitigation technologies for post-combustion CO2 capture using AMP/PZ

Minimizing the environmental impacts of amine-based post-combustion carbon capture technologies is essential for meeting environmental permitting regulations and ensuring public acceptance. Experimental test campaigns at the CO₂ capture pilot plant in Niederaussem using CESAR1 demonstrated that integrating available emission abatement technologies can significantly reduce the concentration of amines and degradation products in CO₂-depleted flue gas to below the detection limit of an infrared spectrometer. The study confirmed that proprietary dry bed technology (OEASE Aerozone™) or a second water wash can lower AMP and PZ emissions to below 1 mg/Nm³. However, to achieve very low NH₃ emissions below 2 mg/Nm³, an acid or other chemically active wash downstream of the water wash is required. A configuration with a dry bed or a double water wash results in a carbon capture cost (CCC) of 44 €/tCO₂, and a CO₂ avoided cost (CAC) of 86 €/tCO₂. A configuration with an acid wash increases the CCC to 47 €/tCO₂ and the CAC to 90 €/tCO₂ due to the amine losses in the acid waste and its treatment.

CO2 capture↗
DOE OSTI2025

Techno-economic evaluation of emission control configurations for AMP/PZ-based post-combustion CO 2 capture

Minimizing the environmental impacts of amine-based post-combustion carbon capture technologies is essential for regulatory compliance and public acceptance. Experimental campaigns at RWE's CO 2 capture pilot plant in Niederaussem using CESAR1 demonstrated that combining existing emission abatement technologies can substantially reduce the concentration of amines and degradation products in the CO 2 -depleted flue gas to below the detection limit of an infrared spectrometer. The campaign confirmed that a proprietary dry bed technology (OEASE aerozone™) or a second water wash can reduce AMP and PZ emissions to below 1 mg/Nm 3 . However, an acid or chemically active wash downstream of the water wash is necessary to reduce NH 3 emissions to very low levels (<2 mg/Nm 3 ). Combining a dry bed with an acid wash significantly reduces both the required acid solution and the resulting acid waste. The techno-economic analysis indicates that implementing emission mitigation technologies provides substantial environmental benefits for the CESAR1 process, with only a marginal increase (<1 €/tCO 2 ) in both the carbon capture cost (CCC) and CO 2 avoidance cost (CAC). The additional capital cost associated with extra column packing is offset by operational cost savings from reduced solvent losses. For stringent emission permits targeting NH 3 , a configuration combining a dry bed upstream of the water wash followed by an acid wash achieves the best balance between emission control and cost efficiency. This configuration results in a Levelized Cost of Electricity (LCOE) of 143 €/MWh, a CCC of 45.4 €/tCO 2 , and a CAC of 88.4 €/tCO 2 .

AMP↗
DOE OSTI2021

Structural analysis and biochemical properties of laccase enzymes from two Pediococcus species

Prokaryotic laccases are emergent biocatalysts. However, they have not been broadly found and characterized in bacterial organisms, especially in lactic acid bacteria. Recently, a prokaryotic laccase from the lactic acid bacterium Pediococcus acidilactici 5930, which can degrade biogenic amines, was discovered. Thus, our study aimed to shed light on laccases from lactic acid bacteria focusing on two Pediococcus laccases, P. acidilactici 5930 and Pediococcus pentosaceus 4816, which have provided valuable information on their biochemical activities on redox mediators and biogenic amines. Both laccases are able to oxidize canonical substrates as ABTS, ferrocyanide and 2,6-DMP, and non-conventional substrates as biogenic amines. With ABTS as a substrate, they prefer an acidic environment and show sigmoidal kinetic activity, and are rather thermostable. Moreover, this study has provided the first structural view of two lactic acid bacteria laccases, revealing new structural features not seen before in other well-studied laccases, but which seem characteristic for this group of bacteria. We believe that understanding the role of laccases in lactic acid bacteria will have an impact on their biotechnological applications and provide a framework for the development of engineered lactic acid bacteria with enhanced properties.

36 MATERIALS SCIENCE↗
DOE OSTI2021

Topical Report – Findings on Subtask 2.7 – Wet ESP and Aerosol Testing at Coal Creek Station

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 carbon 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. 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 unique components present in lignite flue gas present a challenge for large-scale PCCC at North Dakota power plants by contributing to aerosol formation. Aerosols can negatively impact the long-term performance of amine-based solvents for CO 2 capture. Amine-based solvents are volatile, and flue gas particulate provides nucleation sites where amine vapors can condense as aerosols. 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, particulate 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 fully characterize aerosol behavior with various control technologies installed to better optimize aerosol mitigation technology for CO 2 capture. To meet the goal of this project, the following objectives were identified: Determine the effectiveness of a wet electrostatic precipitator (WESP) on mitigating formation of problematic aerosols at Great River Energy’s Coal Creek Station, upstream of the PCCC system. Determine the effectiveness of the Mitsubishi Heavy Industries (MHI) proprietary amine emission reduction unit (AERU) as a postcapture solvent recovery system for reducing aerosol emissions and extending solvent life downstream of the PCCC system. Determine the impact of aerosols on the efficiency and degradation products of both commercial and advanced solvents within the PCCC system. Work was conducted at Coal Creek Station Unit 1 using a slipstream of flue gas from the outlet of the plant’s flue gas desulfurization (FGD) unit. 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 optionally routed through a WESP before passing to the CO 2 absorber columns. The MHI 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 . Flue gas exiting the absorber column was routed to MHI’s proprietary AERU to recover entrained solvent. 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. Particulate was measured, collected, and analyzed from multiple locations throughout the pilot-scale system. Unlike the performance observed in prior work, the inlet FGD and DCC did not remove significant particulate matter from the flue gas. This appears to be due to a difference in the nature of the particulate. The DCC seemed to increase particulate size and count, most likely owing to water condensing onto the surfaces of fly ash particles. When the WESP was operated, it achieved >95% particulate capture. Very little particulate matter or indications of solvent were detected at the AERU outlet. When operating with advanced KS 21 solvent, the particulate material at the AERU outlet was even further decreased. Solvent analysis showed that some species derived from flue gas and ash were slowly concentrating in the solvent over the duration of the test. The levels observed were reported to be within expected ranges and were not of concern to MHI. A high-level techno-economic assessment of installing CO 2 capture at Coal Creek Station suggested that, when using a standard monoethanolamine (MEA)-based solution with simple heat integration, the energy penalty to net generation would be 34%. The bulk of this was due to steam losses for regenerating solvent, followed by parasitic electrical demand for CO 2 compression and then by increased parasitic load for pushing flue gas through the absorber column. These demands could be decreased with a more advanced solvent that exhibits lower heat of regeneration and lower pressure drop than does a simple MEA solution. Further energy could be saved with more thorough heat integration to recover useful energy from the steam used for solvent regeneration. Installing a WESP was predicted to increase the cost of electricity by nearly $5/MWh. This would become cost-effective if solvent losses were roughly 10 times the baseline estimate when not using a WESP but could be returned to baseline by installing the WESP. Piping CO 2 for storage in more favorable geology could help with carbon capture and storage economics. Although storing off-site would necessitate construction of a CO 2 transport pipeline, the cost of this pipeline might be more than offset by reducing the number of wells required, the depths of the wells required, and the electrical demand for the CO 2 compressor. Additional factors that favor off-site storage costs include smaller expected CO 2 plume sizes, which translates to less monitoring and fewer landowner agreements. More detailed assessment of the specific geology in the region under and around Coal Creek Station would be needed to accurately assess the costs and benefits of different storage site options. This subtask was cofunded through the Energy & Environmental Research Center–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.

Strege, Joshua↗
DOE OSTI2023

Amine-Thiol/Selenol Chemistry for Efficient and Stable Perovskite Solar Cells

Controlling the crystallization of perovskites is imperative to reduce defect densities in perovskite thin films and extend device lifetimes. In this work, combinations of amine and chalcogenide ligands were introduced in the sequential deposition method to fabricate highly crystalline and orientated formamidinium lead iodide thin films with reduced defect densities and increased charge carrier lifetimes. The dual additives can tune the perovskite intermediate state and control the crystallization leading to devices with improved efficiencies and stabilities. While thiophenol failed to prevent the amine ligand from degrading the perovskite precursors, benzene selenol combinations with amine-ligands drastically changed the solution chemistry to increase the PbI 2 conversion to highly crystalline and orientated α-FAPbI 3 films with lower defect densities. X-ray photoelectron spectroscopy studies reveal benzene selenol evaporates from the thin film leaving behind a modified surface, which is associated with the amine additive. These results indicate the amine selection can be used to tune the surface properties. Lastly, we propose a highly tunable I 2 reduction strategy using chalcogenide chemistry to help enable the realization of perovskite solar cells with high performance and stability.

defects↗
DOE OSTI2024

A simulation-based model studying monoethanolamine and aprotic heterocyclic anion ionic liquid (AHA-IL) mixtures for carbon capture

Capturing of waste CO 2 , particularly from large industrial point sources, is necessary for either permanent storage or CO 2 utilization. Amine solvents used for carbon capture have certain drawbacks, particularly the high energy required by the reboiler for solvent regeneration and degradation of the amine with absorption/regeneration cycling. These challenges may be overcome using ionic liquids (ILs) that can be tailored for operating under typical flue gas stream conditions (8–10% CO 2 , 18–20% H 2 O, 2–3% O 2 , and 67–72% N 2 ). ILs, however, oftentimes suffer from high viscosities, leading to diffusion limitations when compared to amine solvents. This work models the combinations of aprotic heterocyclic anion ILs (AHA-IL) with monoethanolamine (MEA) and studies the carbon capture effectiveness of these mixtures. Furthermore, this study found that all AHA-IL/MEA mixtures exhibited 32 % lower enthalpy of reaction (compared to MEA) and 64 % lower viscosity (compared to AHA-IL), which are desirable characteristics for CO 2 capture solvents.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2023

Particulate from Lignite Coal Combustion and Impact on Carbon Capture Aerosol Emissions

Conference presentation for 47th International Technical Conference on Clean Energy (Clearwater Clean Energy Conference), Clearwater, Florida, July 23–27, 2023. While aerosol formation is recognized as a leading cause of amine losses and degradation from postcombustion CO 2 capture systems, the factors that can lead to aerosol formation vary widely depending on fuel type, plant configuration, and operating conditions. All of these factors require measurement to fully characterize potential sources of aerosol-based amine losses and should be considered prior to implementing full-scale amine-based CO 2 capture.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2020

Effect of Extended Aging and Oxidation on Linear Poly(propylenimine)-Mesoporous Silica Composites for CO 2 Capture from Simulated Air and Flue Gas Streams

Physical aging or degradation of amine-containing polymers and supported amine adsorbents is a critical issue that could limit practical application of such materials for CO 2 capture. However, to date, there is a scarcity of studies that evaluate the long-term stability of amine-based sorbents without the exclusive use of accelerated aging tests. Here, we demonstrate that extended aging (~2 years) of linear poly(propylenimine) (LPPI) confined in mesoporous silica (SBA-15) supports does not drastically impact the CO 2 adsorption performance under simulated flue gas (10% CO 2 ) and direct air capture (DAC, 400 ppm CO 2 ) conditions, although the behavior of the aged sorbents and polymers in the two CO 2 concentration regimes differs. Sorbents made with aged LPPI had modestly decreased CO 2 uptake performance (<~20% lower) compared to the fresh polymers, with overall good CO 2 cycling performance. The data indicate that only slow degradation occurs under the deployed ambient storage conditions. Even after extended aging, the LPPI-based sorbents preserved their ability to display stable temperature-swing cycling performance. In parallel, the impact of blending LPPI polymers of different number-average molecular weights, M n , is evaluated, seeking to understand its impact on adsorbent performance. We find that the results demonstrate that blends of two M n aged LPPI give similar CO 2 adsorption performance to adsorbents made from a single M n LPPI, suggesting that molecular weight will not negatively impact adsorbent performance in the studied M n range. After an accelerated oxidation experiment, the aged LPPI sorbents retained a larger portion of the samples’ original performance when cycling under simulated flue gas conditions than under DAC conditions. However, in each case, the oxidized sorbents could be cycled repeatedly with consistent uptake performance. Overall, these first of their kind extended aging tests suggest that LPPI-based amine adsorbents offer promise for long term, stable use in carbon capture applications.

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

The Effect of TiDG, DCiTG (Lix ® reg;79), and Other Suppressors on the Compatibility of NGS with SWPF Polymers

This document provides a screening calculation of the potential miscibility of specific polymers proposed for use in the SWPF, notably polyether-etherketone (PEEK), ultra-high molecular weight polyethylene (UHMWPE), polyvinylidene fluoride (PVDF), Viton ® B fluoroelastomer, and Tefzel ® ethylenetetrafluoroethylene (ETFE) copolymer in different suppressors including trisisodecyl guanidine (TiDG), dicyclohexane-isotrisdecyl guanidine (DCiTG), and two other dicyclohexane guanidine related suppressors. The evaluation suggests that Tefzel ® ETFE may mildly interact with the Next Generation Solvent (NGS) regardless of the suppressor used. Based on this approach (calculations), the other listed polymers appear compatible with the NGS containing the four different suppressors. There is evidence of chemical affinity between Tefzel ® ETFE, Viton ® B with aliphatic amines (which are degradation by-products from the TiDG). In addition, the calculation suggests that drawing miscibility conclusions from exposing polymers to a single pure component may give misleading or incorrect results due to the potential for synergistic effects or other interactions.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2021

Measurement of Volatile Compounds for Real-Time Analysis of Soil Microbial Metabolic Response to Simulated Snowmelt

Snowmelt dynamics are a significant determinant of microbial metabolism in soil and regulate global biogeochemical cycles of carbon and nutrients by creating seasonal variations in soil redox and nutrient pools. With an increasing concern that climate change accelerates both snowmelt timing and rate, obtaining an accurate characterization of microbial response to snowmelt is important for understanding biogeochemical cycles intertwined with soil. However, observing microbial metabolism and its dynamics non-destructively remains a major challenge for systems such as soil. Microbial volatile compounds (mVCs) emitted from soil represent information-dense signatures and when assayed non-destructively using state-of-the-art instrumentation such as Proton Transfer Reaction-Time of Flight-Mass Spectrometry (PTR-TOF-MS) provide time resolved insights into the metabolism of active microbiomes. In this study, we used PTR-TOF-MS to investigate the metabolic trajectory of microbiomes from a subalpine forest soil, and their response to a simulated wet-up event akin to snowmelt. Using an information theory approach based on the partitioning of mutual information, we identified mVC metabolite pairs with robust interactions, including those that were non-linear and with time lags. The biological context for these mVC interactions was evaluated by projecting the connections onto the Kyoto Encyclopedia of Genes and Genomes (KEGG) network of known metabolic pathways. Simulated snowmelt resulted in a rapid increase in the production of trimethylamine (TMA) suggesting that anaerobic degradation of quaternary amine osmo/cryoprotectants, such as glycine betaine, may be important contributors to this resource pulse. Unique and synergistic connections between intermediates of methylotrophic pathways such as dimethylamine, formaldehyde and methanol were observed upon wet-up and indicate that the initial pulse of TMA was likely transformed into these intermediates by methylotrophs. Increases in ammonia oxidation signatures (transformation of hydroxylamine to nitrite) were observed in parallel, and while the relative role of nitrifiers or methylotrophs cannot be confirmed, the inferred connection to TMA oxidation suggests either a direct or indirect coupling between these processes. Overall, it appears that such mVC time-series from PTR-TOF-MS combined with causal inference represents an attractive approach to non-destructively observe soil microbial metabolism and its response to environmental perturbation.

59 BASIC BIOLOGICAL SCIENCES↗
DOE OSTI2021

Low cost immobilized amine regenerable solid sorbents

A method of modifying a chemical interaction between a functional group of an immobilized amine in a solid sorbent composition and a compound that chemically interacts with the functional group to reduce the heat required to desorb the compound from the solid sorbent. A method of inhibiting degradation of an immobilized amine in an immobilized amine solid sorbent. Compositions and methods of use of a low-cost regenerable immobilized amine solid sorbent resistant to degradation.

Chuang, Steven S. C.↗
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↗