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All sourcesNASA NTRSDOE OSTI
DOE OSTI2021

Rate-Based Absorption Modeling for Postcombustion CO 2 Capture with Additively Manufactured Structured Packing

Carbon capture using amine-based solvents in an absorption process is a leading candidate for reducing greenhouse gas emissions in industrial flue gas streams. To reduce operating costs and associated parasitic energy of these processes, process intensification utilizing additively manufactured structured packing has emerged as a new technology to manage exothermic reactions during absorption while improving CO 2 capture. A rate-based model framework has been developed for these novel packings that incorporates the mass and heat transfer phenomena for amine-based absorption of CO 2 . The rate-based model framework is first benchmarked using available solubility data and pilot plant data for aqueous monoethanolamine. The model validation shows accurate prediction of both CO 2 equilibrium partial pressures and ion speciation for solubility data as well as CO 2 capture, temperature profile, and solvent composition for pilot plant data in the absorption column. The model framework is then applied toward predicting the CO 2 capture performance of additively manufactured structured packing. Simulations agree with experimental data in predicting the CO 2 capture and the capture performance increase due to cooling within the structured packing device. Finally, advantages of this rate-based model framework are the utilization of correlations that may predict mass transfer and heat transfer coefficients of the packing based on the geometric properties of the device and the implementation of the model framework in open-source programming.

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

Evaluation of a Third Generation Single-Component Water-Lean Diamine Solvent for Post-Combustion CO 2 Capture

Here this study describes a comprehensive evaluation of a recently developed water-lean diamine solvent, N1-(2-ethoxyethyl)-N2, N2-diisopropylethane-1,2-diamine (2-EEDIPEDA), to probe its potential post-combustion CO 2 capture performance. This evaluation includes (1) fundamental sorption characterization such as vapor-liquid equilibria, sorption kinetics and viscosity impacts; (2) continuous capture characterization using laboratory scale flow system using flue gas simulant; as well as (3) technoeconomic analysis of the capture process at industrial scale with projections for critical capture performance metrics. Using this evaluation, we compare the performance of 2-EEDIPEDA to our current leading water-lean amine-based solvent, 2-EEMPA, using the same baseline process plant configuration/pricing. From this comparison, we observe lower total cost of capture as low as $46.8/tonne CO 2 with 2-EEDIPEDA (20% cheaper than CANSOLV), as a direct result of solvent chemistry tuning leading to notable cost savings.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2025

ROTA-CAP™: An Intensified Carbon Capture System Using Rotating Packed Beds (Final Scientific/Technical Report)

GTI Energy and Carbon Clean Solutions Limited successfully designed, constructed, and operated an integrated ROTA-CAP carbon capture skid. ROTA-CAP™ is a process intensification technology, applied for post-combustion carbon capture, which utilizes the centrifugal forces generated from rotation of rotating packed beds as well as advanced solvents to achieve increased mass transfer rates 1-2 orders of magnitude higher than conventional columns while substantially decreasing footprint. The test skid, which consisted of a dual stage RPB absorber with external interstage cooling and a single stage RPB regenerator, was operated at capacities up to 0.5 tonne/day of CO 2 capture with flue gas concentrations ranging from 4% to 22% CO 2 by vol. CO 2 removal rates greater than 95% were achieved, with CO 2 product purity also exceeding 95% by vol. Over 1,600 hours of operation were accumulated throughout the project, including over 1,000 hours of operation of the with real flue gas containing at least 9.8% CO 2 by vol. The skid was operated continuously for 24 hours per day and 7 days per week over the course of 7 long-term test campaigns, with the campaigns ranging from approximately 2-4 weeks per campaign. A techno-economic analysis was performed, and a cost of capture of $\$$41.18/tonne CO 2 was calculated for the ROTA-CAP process, compared to $\$$45.75/tonne for a Cansolv-based process. These results show a cost reduction of approximately 10% compared to the Cansolv-based process. Although this still exceeds the target cost of capture of $\$$30/tonne specified for this project, GTI expects that the cost of capture can be further reduced through further optimization of the design and technology. GTI also performed an engineering design review to determine the scale-up potential of the technology, with the results of the preliminary assessment indicating that it appears to be feasible to scale up the RPB technology to 4,000 TPD. It was also determined that both horizontal and vertical rotor orientations are feasible, though there are mechanical advantages to the vertical orientation.

20 FOSSIL-FUELED POWER PLANTS↗
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 OSTI2025

Control of Permanent Porosity in Type 3 Porous Liquids via Solvent Clustering

Porous liquids (PLs) are an exciting new class of materials for carbon capture due to their high gas adsorption capacity and ease of industrial implementation. They are composed of sorbent particles suspended in a nonadsorbed solvent, forming a liquid with permanent porosity. While PLs have a vast number of potential compositions based on the number of solvents and sorbent materials available, most of the research has been focused on the selection of the sorbent rather than the solvent. Therefore, PL design criteria on the supramolecular structures of the solvent are explored to create a fundamental understanding of how the solvent enables PL formation for rapid discovery of new PL compositions. Atomistic molecular dynamics simulation of eight solvents with a range of molecular sizes, shapes, and intramolecular bonding was performed, identifying that the shape and size of molecular clusters formed in the solvent are the driving predictor of PL formation rather than the size of the individual solvent molecule. The results demonstrate a significant departure from common approaches to PL formation based on the steric exclusion of solvent molecules from the sorbent via the size of the pore aperture. A modeling and experimental validation study further supports these findings. In conclusion, through this computational material design study, a previously unexplored mechanism in PL formation, solvent–solvent clustering, is identified as a critical factor for the accelerated discovery of liquid phase carbon capture materials.

Carbon capture↗
DOE OSTI2025

Electrocatalysis in CO 2 -Binding Organic Liquids with an Iron Porphyrin

Direct electrochemical upgrading of CO 2 in capture media is an attractive approach to carbon capture that can bypass the energy requirement for the thermal release of pure CO 2 . Here we investigate the electrocatalytic activity of iron(tetraphenylporphyrin) in the presence of organic solvents that convert into ionic liquids upon exposure to CO 2 . Four different solvent systems were tested, all of which capture CO 2 in the form of an alkyl carbonate (or carbamate) anion and an acidic ammonium cation. The electrocatalytic selectivity exhibited a strong dependence on the acidity of the capture medium, with the most basic solvent affording a high selectivity for production of CO instead of H 2 . Experimental and computational studies support a canonical mechanism in which the catalyst reacts with free CO 2 in solution, as opposed to a reaction with the alkyl carbonate that is present in high concentration. Kinetic analysis indicates that the rate-limiting step is changed from C–O protonolysis in traditional solvents to the binding of CO 2 in the capture media. Quantitative 13 C– 13 C EXSY revealed that the dissociation of the alkyl carbonate into free, solvated CO 2 is very rapid (~15 s –1 ) compared to the interconversion of HCO 3 – /CO 2 in aqueous solution. These results underscore the need to understand the mechanism and kinetics for both the release of captured CO 2 and its electrocatalytic conversion.

Carbon Dioxide↗
DOE OSTI2025

Examination of Factors Affecting the Cost and Performance of a Natural Gas Combined Cycle Equipped with Carbon Dioxide Capture

The purpose of this Technical Note is to report the findings of an examination of the effect of plausible deviations in select study assumptions on the reported cost and performance estimates for a power plant case drawn from NETL’s “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity” (known as the Fossil Energy Baseline). An F-Class NGCC power plant equipped with state-of-the-art, solvent-based, post-combustion carbon dioxide (CO2) capture (95 percent carbon capture rate)—designated as Case B31B.95—was selected for this work. This sensitivity analysis provides insight into the effects of parameter variations within and across selected categories—ambient conditions, construction cost, natural gas (NG) price, capacity factor, and finance—on the plant performance and capital and operating and maintenance (O&M) costs, and the subsequent impact on common figures of merit.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2025

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

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

Biomass Co-firing↗
DOE OSTI2026

In situ molecular imaging of ion clusters reveals the acid gas capture capacity and mechanism of water-lean ionic liquids

Water-lean solvents are a promising technology for capturing acid gases like carbon dioxide (CO 2 ). In situ liquid time-of-flight secondary ionization mass spectroscopy (ToF-SIMS) is used to study a representative solvent N-(2-ethoxyethyl)-3-morpholinopropan-1-amine (2-EEMPA) with different CO 2 loadings to reveal the complex solvent structure upon CO 2 capture. Characteristic peaks of 2-EEMPA, such as m/z – 215 C 11 H 23 N 2 O 2 – (deprotonated 2-EEMPA) and m/z + 217 C 11 H 25 N 2 O 2 + (protonated 2-EEMPA), are detected due to acid gas uptake. Also, solvent molecules and carboxylate ion pairs, such as m/z – 259 C 12 H 23 N 2 O 4 – [(deprotonated 2-EEMPA∙∙∙CO 2 )] and m/z + 261 C 12 H 25 N 2 O 4 + (protonated 2-EEMPA∙∙∙CO 2 ), are observed. Interestingly, more than one CO 2 molecule can be captured per each solvent molecule as evidenced in SIMS mass spectra, for example, m/z – 321 C 13 H 25 N 2 O 7 – [(deprotonated 2-EEMPA)∙∙∙2CO 2 ∙∙∙H 2 O], m/z + 305 C 13 H 25 N 2 O 4 + [(protonated 2-EEMPA)∙∙∙2CO 2 ], m/z – 389 C 17 H 29 N 2 O 8 – [(deprotonated 2-EEMPA)∙∙∙3CO 2 ∙∙∙3CH 2 ], and m/z + 373 C 16 H 25 N 2 O 8 + [(protonated 2-EEMPA)∙∙∙3CO 2 ∙∙∙2C]. However, the monomer of 2-EEMPA and CO 2 seems to be most prevalent. Furthermore, solvent clusters are detected in loaded solvents, for instance m/z + 433 C 22 H 49 N 4 O 4 + [(2-EEMPA)2∙∙∙H] and m/z + 646 [(2-EEMPA) 3 -2H], while capturing CO 2 at different amounts. Relative abundance of cluster ions provides a semi-qualitative venue to assess the free energies of gas capture energetics, indicating the relative stability trend within the same solvent system, previously impossible. These observed ion clusters are verified with molecular modeling, where dimer, trimer, and cluster ions are validated for their presence either due to weak molecular interactions or hydrogen bonds. In situ molecular imaging of ionic liquids and molecular modeling reveals that the acid gas capture mechanism by ionic liquids includes both physical adsorption and chemical bonding with multiple reaction pathways, engaging cluster formation and alteration of solvent structures.

Acid gas capture↗
DOE OSTI2024

Sequential Design of Experiments for Pilot Testing of Novel Solvent System

The CCSI2 program is supporting a six-month test campaign at the National Carbon Capture Center (NCCC) for evaluation of a novel water-lean solvent. This presentation describes CCSI2’s efforts in process modeling of the solvent system for both coal and natural gas-based flue gas sources and initial uncertainty quantification (UQ) work to estimate parametric uncertainty in key sub-models of interest (e.g., thermodynamics, mass transfer, reaction kinetics). Moreover, perspective is provided on how UQ and sequential design of experiments (SDoE) tools are used to assess the impact of model uncertainty on projected process performance, use this information to optimize data collection during the campaign, and refine process models through data collection. This framework is expected to reduce the overall model uncertainty, and thus risk associated with scale-up as the process moves towards commercialization.

Morgan, Joshua↗
DOE OSTI2024

Exploitation of Pore Structure for Increased CO 2 Selectivity in Type 3 Porous Liquids

CO 2 capture requires materials with high adsorption selectivity and an industrial ease of implementation. To address these needs, a new class of porous materials was recently developed that combines the fluidity of solvents with the porosity of solids. Type 3 porous liquids (PLs) composed of solvents and metal–organic frameworks (MOFs) offer a promising alternative to current liquid carbon capture methods due to the inherent tunability of the nanoporous MOFs. However, the effects of MOF structural features and solvent properties on CO 2 –MOF interactions within PLs are not well understood. Herein experimental and computational data of CO 2 gas adsorption isotherms were used to elucidate both solvent and pore structure influences on ZIF-based PLs. The roles of the pore structure including solvent size exclusion, structural environment, and MOF porosity on PL CO 2 uptake were examined. A comparison of the pore structure and pore aperture was performed using ZIF-8, ZIF-L, and amorphous-ZIF-8. Adsorption experiments here have verified our previously proposed solvent size design principle for ZIF-based PLs (1.8× ZIF pore aperture). Furthermore, the CO 2 adsorption isotherms of the ZIF-based PLs indicated that judicious selection of the pore environment allows for an increase in CO 2 selectivity greater than expected from the individual PL components or their combination. This nonlinear increase in the CO 2 selectivity is an emergent behavior resulting from the complex mixture of components specific to the ZIF-L + 2'-hydroxyacetophenone-based PL.

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

Pilot Testing of a Highly Efficient Pre-combustion Sorbent-based Carbon Capture System

TDA developed and demonstrated a highly efficient pre-combustion carbon capture system. The overall objective of this work was to develop a new sorbent-based pre-combustion carbon capture technology for Integrated Gasification Combined Cycle (IGCC) power plants. In this project our goal was to demonstrate the techno-economic viability of the new technology by 1) demonstrating it in large-scale slipstream tests, and 2) carrying out a high fidelity engineering and cost analysis. TDA’s process used an advanced physical adsorbent that selectively removes CO 2 from coal-derived synthesis gas above the dew point of the gas at temperatures as high as 300°C. The sorbent consists of a mesoporous carbon whose surface was grafted with functional groups that remove CO 2 via a well-known acid-base interaction. As documented in bench-scale experiments and field tests with actual coal gas, the sorbent achieved a very high capacity for CO 2 at temperatures as high as 300°C. The sorbent bound CO 2 more strongly than common physical adsorbents, providing the chemical potential needed for the high temperature operation. However, because CO 2 does not form a true covalent bond with the surface sites (as is the case with chemical absorbents), the sorbent regeneration could be carried out with only a very small energy input. The heat input to regenerate our sorbent was only 4.9 kcal per mol of CO 2 , which is much lower than that for chemical absorbents (e.g., 29.9 kcal/mol CO 2 for sodium carbonate) and was similar to the requirements of physical solvents (e.g., 4 kcal/mol CO 2 for Selexol TM ). Because the sorbent operates above the dew point of the synthesis gas (unlike the Selexol TM process), a higher power cycle efficiency can be achieved. With previous DOE/NETL funding (Contract No. DE-FE-0000469), we demonstrated the techno-economic viability of the technology in bench-scale tests and slipstream demonstrations at the National Carbon Capture Center (NCCC), Wilsonville, Alabama and Wabash River IGCC plant in Terra Haute, Indiana. We demonstrated a stable working CO 2 capacity for over 11,650 cycles with simulated synthesis gas. We also evaluated its performance with actual synthesis gas in two test campaigns at the Wabash River IGCC Plant, Terre Haute, IN and the National Carbon Capture Center (NCCC), Wilsonville, AL. The slipstream tests clearly showed that the actual coal gas constituents and potential contaminants (e.g. trace metals, halides, tars) had no effect on the sorbent’s ability to remove CO 2 (the same sorbent beds were used in both field tests with no sign of deactivation for 2,000 cycles with over 26,750 SCF of gas treated). As expected, due to the high temperature CO 2 removal capability and low energy needed to regenerate the sorbent, the power cycle efficiency with our process was greater than 34% on a higher heating value (HHV) basis; in comparison, the same IGCC plant equipped with the Selexol TM solvent for carbon capture can only achieve 31.4% HHV efficiency. The capital cost for an IGCC system with TDA’s process is estimated as $2,417/kW e , which is 12% lower than that of the IGCC/ Selexol TM process. The levelized cost for electricity including the transport, storage and monitoring (TS&M) cost for CO 2 was calculated as $\$ $92.9/MWh (lowest reported to our knowledge), which is much better than the $105.2/MWh estimated for the IGCC/ Selexol TM process. In this project (DE-FE0013105), TDA Research, in collaboration with our partners Gas Technology Institute (GTI), Illinois Clean Coal Institute (ICCI), University of California, Irvine (UCI), University of Alberta (UOA), Siemens, NCCC and Sinopec advanced the technical maturity of the technology; scaling it up by a factor of 100. We optimized the reactor design using computational fluid dynamics (CFD); using adsorption modeling we improved the pressure swing adsorption (PSA) cycle sequence. We carried out two field test campaigns with a fully-equipped 0.1 MW e prototype unit (for a total of 844 hours) using actual synthesis gas to prove the viability of the new technology. A successful 30 day (707 hrs) evaluation was completed at NCCC under air blown gasification conditions. We demonstrated 97.3% carbon capture at 1,500 SLPM, 93% carbon capture at 1,800 SLPM, and 90% carbon capture at 2,100 SLPM in the NCCC tests. We also demonstrated the system for 137 hours at a Sinopec petrochemical plant under oxygen blown gasification, demonstrating 86% carbon capture at 2,660 SLPM. In collaboration with University of California, Irvine (UCI), we completed a techno-economic analysis (TEA) for TDA’s warm gas cleanup technology integrated to IGCC power plant. The net plant efficiencies (on a coal HHV basis) for the warm gas cleanup cases were estimated to be 34.0% for E-GasTM gasifier, 34.4% for GE gasifier, 33.4 for the Shell gasifier and 34.2 for the TRIG TM gasifier (Cases 2, 4, 6 and 8 in this study) with a catalytic combustor for CO 2 purification, which are significantly higher than those for the Cold Gas Case, or an increase of as much as 12% in the heat rate for Case 2, 6% for Case 4, 9% for Case 6, and 9% for Case 8. The 1st year cost of electricity with the transport, storage and monitoring (TS&M) costs for the CO 2 included was $\$ $129.2/MWh for the E-GasTM gasifier Warm Gas Cleanup Case, $\$ $131.9/MWh for the GE gasifier Warm Gas Cleanup Case, $\$ $146.8/MWh for the Shell Gasifier Warm Gas Cleanup Case, and $\$ $129.9/MWh for the TRIG TM gasifier Warm Gas Cleanup Case. For comparison, the costs for the baseline Cold Gas CO 2 removal with Selexol for the different gasifiers were: $\$ $146.6/MWh for the E-Gas TM gasifier, $\$ $142.2/MWh for the GE gasifier, $\$ $159.0/MWh for the Shell gasifier and $\$ $144.3/MWh for the TRIG TM gasifier. In summary, the costs for our system were 7 to 12% lower than the corresponding Cold Gas Cleanup cases. The results of this techno-economic analysis suggested that TDA’s high temperature PSA-based Warm Gas Clean-up Technology can make a substantial improvement in the IGCC plant thermal performance for achieving near zero CO 2 emissions for E-Gas TM , GE, Shell and TRIG TM gasifier based IGCC power plants. The capital expenses were estimated to be lower than that of Selexol’s™. Taken together, the higher net plant efficiency and lower capital and operating costs resulted in substantial reduction in the cost of carbon capture for the IGCC plant equipped with TDA’s high temperature PSA-based carbon capture system. Finally, in collaboration with Gas Technology Institute (GTI) we completed the environmental health and safety assessment for TDA’s warm gas carbon capture technology.

01 COAL, LIGNITE, AND PEAT↗
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 OSTI2025

Design of Experiments for Dynamic Test Runs in Solvent-Based CO 2 Capture Pilot Plants

Test runs in the pilot plants consume significant resources, and therefore, the learning from test runs should be maximized. Test runs conducted in the pilot plants are often steady state. It takes several hours for reaching steady-state in the pilot plants, and thus, the duration of the test runs needs to be long even for collecting few steady-state data points. On the other hand, a large number of measurements can be collected through dynamic test runs in a short span of time. This paper presents a systematic design of dynamic experiments (DoDEs) for identifiability of model parameters, which is achieved by persistently exciting the inputs signals. A pseudorandom binary sequence (PRBS) is designed as the input signal for DoDE due to its efficiency in obtaining sufficient spectral content. However, due to the long sequence size of the PRBS signal, a Schroeder-phase input signal, which is a multisine signal, is also designed. Tests for both types of signals are run in the Pilot Solvent Test Unit (PSTU) at the National Carbon Capture Center in Wilsonville, Alabama. The transient data are used to solve dynamic data reconciliation and parameter estimation problem. The estimated parameters are found to be not only superior to those estimated from using data collected from hundreds of steady-state test runs in a nonreactive (air–water) system, but the parameters could be estimated by using the dynamic data collected for about 24 h from the pilot plant for the MEA-H 2 O–CO 2 system.

CO2 capture↗
DOE OSTI2020

Environmental, Health and Safety Assessment Application of a Heat Integrated, Post-combustion CO2 Capture System Using Monoethanolamine and Hitachi H3-1 Solvent at the E.W. Brown Coal-fired Power Plant

An Environmental Health and Safety (EH&S) Assessment was completed for operation of a pilot scale carbon dioxide (CO2) capture system (CCS) at the Louisville Gas & Electric (LG&E) and Kentucky Utilities (KU) Energy, LLC (LG&E-KU) E. W. Brown Generating Station in Harrodsburg, Mercer County, Kentucky. The pilot system was evaluated using two CO2 capture solvents, monoethanolamine (MEA) and Hitachi’s H3-1 solvent. The purpose of the EH&S Assessment was to determine if there were any unacceptable environmental, health or safety concerns that may prevent operation or environmental permitting of a larger scale pilot scale plant. The assessment included review of process flow diagrams, input and output flow rates for primary materials, literature describing similar processes and chemicals used or created during the process, actual air emission and wastewater test data and air emission calculations. The evaluation included identification of risks related to hazardous chemicals, air emissions, wastewater discharges, solid wastes generated and employee hazards. Most potential EH&S issues that were identified are commonly found and successfully managed at large industrial facilities. No risks were identified that could not be successfully managed or would likely prevent implementation or environmental permitting of the pilot or larger scale plant. Potential exposures and resulting health risks from exposure to low concentrations of nitrosamines generated from degradation of the Hitachi H3-1 and possibly MEA solvents may be a health concern for site workers, but additional investigation is needed to accurately assess this risk. Applying the information gained from operating the pilot plant, performing air emission testing and used solvent testing to a large-scale facility at a commercial coal-fired electric generating plant suggests additional air emission control measures may be necessary to reduce potential site worker health risks and possibly community risks. Depending upon the location and regional air quality, considerable effort may be required to obtain the necessary air permit for construction and operation of a similarly configured large-scale PCCCS facility.

gas separation↗
DOE OSTI2020

Environmental, Health and Safety Assessment Application of a Heat Integrated, Post-combustion CO 2 Capture System Using Monoethanolamine and Hitachi H3-1 Solvent at the E.W. Brown Coal-Fired Power Plant

An Environmental Health and Safety (EH&S) Assessment was completed for operation of a pilot scale carbon dioxide (CO 2 ) capture system (CCS) at the Louisville Gas & Electric (LG&E) and Kentucky Utilities (KU) Energy, LLC (LG&E-KU) E. W. Brown Generating Station in Harrodsburg, Mercer County, Kentucky. The pilot system was evaluated using two CO 2 capture solvents, monoethanolamine (MEA) and Hitachi’s H3-1 solvent. The purpose of the EH&S Assessment was to determine if there were any unacceptable environmental, health or safety concerns that may prevent operation or environmental permitting of a larger scale pilot scale plant. The assessment included review of process flow diagrams, input and output flow rates for primary materials, literature describing similar processes and chemicals used or created during the process, actual air emission and wastewater test data and air emission calculations. The evaluation included identification of risks related to hazardous chemicals, air emissions, wastewater discharges, solid wastes generated and employee hazards. Most potential EH&S issues that were identified are commonly found and successfully managed at large industrial facilities. No risks were identified that could not be successfully managed or would likely prevent implementation or environmental permitting of the pilot or larger scale plant. Potential exposures and resulting health risks from exposure to low concentrations of nitrosamines generated from degradation of the Hitachi H3-1 and possibly MEA solvents may be a health concern for site workers, but additional investigation is needed to accurately assess this risk. Applying the information gained from operating the pilot plant, performing air emission testing and used solvent testing to a large-scale facility at a commercial coal-fired electric generating plant suggests additional air emission control measures may be necessary to reduce potential site worker health risks and possibly community risks. Depending upon the location and regional air quality, considerable effort may be required to obtain the necessary air permit for construction and operation of a similarly configured large-scale PCCCS facility.

gas separation↗
DOE OSTI2024

The performance of solvent-based direct air capture across geospatial and temporal climate regimes

Liquid-solvent direct air capture (DAC) is a prominent approach for carbon dioxide removal but knowing where to site these systems is challenging because it requires considering a multitude of interrelated geospatial factors. Two of the most pressing factors are: (1) how should DAC be powered to provide the greatest net removal of CO 2 and (2) how does weather impact its performance?. To investigate these questions, this study develops a process-level model of a liquid-solvent DAC system and couples it to a 20-year dataset of temperature and humidity conditions at a ~9km resolution across the contiguous US.

54 ENVIRONMENTAL SCIENCES↗