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Current status of biogas upgrading for direct biomethane use: A review
Anaerobic digestion produces biogas, a mixture of CH 4 and CO 2 , where CH 4 is a low cost, environmentally friendly, and renewable energy source. The application of biogas production is increasing rapidly as a means of reducing the pollution impact of organic biomasses. However, biogas contains unwanted elements such as hydrogen sulfide, carbon monoxide, siloxanes, and carbon dioxide. To remove these elements, several biogas upgrading technologies like water scrubbing, amine scrubbing, pressure swing adsorption, and membrane separation have been developed and are being used at various commercial scales. Problems with these methods are high energy consumption, the use of expensive chemicals, and high operating cost. Therefore, a major effort is currently underway to improve the design of existing methods as well as developing innovative new upgrading technologies such as cryogenic separation and biological upgrading. Here, this review intends to provide a comprehensive overview of the limitations with the existing upgrading technologies along with recent advances in physical, chemical, and biological biogas upgrading technologies (e.g., pressure swing adsorption, membrane separation, biochar adsorption and CO 2 conversion by biological organisms) and further into possible future solutions, such as hybrid systems. Comparative studies of process complexities and associated economic concerns are also provided, and future perspectives that may facilitate research into sustainable biogas upgrading technologies are discussed, focusing in particular on cryogenic separation, novel biological techniques, biochar based upgrading and hybrid technologies incorporating two or more different methods seamlessly integrated.
Front-End Engineering Design for Piperazine with the Advanced Stripper
This Department of Energy (DOE) funded project was executed with the goal of preparing a Front-End Engineering Design (FEED) for the capture and compression of 90% of the CO2 that would normally be emitted from an existing natural gas combined cycle (NGCC) plant. The FEED focused on the application of the piperazine advanced stripper (PZAS) process at Mustang Station of the Golden Spread Electric Cooperative (GSEC), which consists of two gas turbines with common heat recovery steam generator (HRSG). The University of Texas at Austin (UT) served as the prime contractor, and subcontracted AECOM Technical Services and Trimeric Corporation to support FEED development. This project team has worked together to advance PZAS for more than a decade. ExxonMobil, Chevron, and Total provided project co-funding. The objectives of this work included: 1. To advance engineering design such that a comprehensive estimate for the total installed cost of a full-scale PZAS CO2 Capture Plant with CO2 compression can be developed on an existing NGCC power plant. a. These detailed costs can also be used to qualify PZAS and other related second generation (2G) amine scrubbing processes for use on cogeneration facilities in refineries and chemical plants that use gas turbines with HRSGs to produce steam. b. These detailed costs will help qualify 2G amine scrubbing for use on NGCC power plants and establish a more accurate baseline cost to be used as a target by other capture technologies. 2. To provide cost details to be used in the economic optimization of the process features of PZAS and other 2G amine scrubbing processes. 3. To provide DOE with a more detailed understanding of carbon capture costs in a commercial application, enabling DOE to better design its R&D program to improve the economics for carbon capture. 4. To provide the host site and cost share partners with the information necessary to determine whether a commercial project to capture and use CO2 for enhanced oil recovery (EOR) or for sequestration can be justified (when accounting for the 45Q tax credit). A key component of the FEED is the estimated total installed cost, which provides a basis for the likely capital investment necessary to implement the PZAS carbon capture process at this location and scale. In combination with the included economic analysis, which accounts for potential revenue from the produced CO2, potential avenues to profitability are explored. The major findings of the FEED are as follows: The Mustang Station PZAS CO2 Capture Plant estimated total project cost of $698 MM of which $384 MM was direct costs. The annual operating costs were $32.6 MM. The total investment for a PZAS facility at Mustang Station is $725 MM. This estimate includes owner’s cost of $25 million and a contingency of $110 MM. • The study estimated the CO2 capture plant at Mustang Station would generate CO2 at $110/tonne for EOR, assuming a 12% IRR (internal rate of return) and an 85% capacity factor. For CO2 storage, the same case would achieve a 12% IRR at about $114/tonne. At a capacity factor of 52%, the storage and EOR cases would break even when carbon is priced ~$150/tonne. The economic analysis determined that the capacity factor and utility pricing, among other variable factors, had a significant effect on the economics and will need additional studied. • The energy penalty of the PZAS plant would be about 46 MW in connected power and 35 MW in operating load. The natural gas requirement (for the Gas Boiler package) would be about 354 MMBTU/hr. • The FEED revealed no major risks in process maturity. However, some areas were outlined for further engineering during detailed design, which included the Gas Boiler system, general arrangement and site layout, air coolers, schedule development, and optimization of the process for higher CO2 removal. • If PZAS were to be implemented at another host site, additional opportunities for cost reduction for would include cost reduction through use of cooling water and steam extraction.
Examining the Reactions of Ethanolamine’s Thermal Degradation Compounds in Carbon Capture through 1 H NMR and 13 C NMR
In amine scrubbing carbon capture, concerns about amine solvent degradation include whether it can affect the ability of the solvent to capture CO 2 . This study examines the interactions between the three most reported monoethanolamine (MEA) thermal degradation compounds namely, oxazolidine-2-one (OZD), N-(2-hydroxyethyl)-ethylenediamine (HEEDA), and N-(2- hydroxyethyl)-imidazoline-2-one (HEIA) with CO 2 in the presence and absence of MEA. We compared 1 H NMR, 13 C NMR, and heteronuclear single-quantum coherence (HSQC) NMR for neat OZD, HEEDA, and HEIA samples with CO 2 -loaded samples to observe changes in protonation and unique carbamate species formation. We found that OZD and HEIA did not directly react with CO 2 or undergo proton shifting based on our comparison of the neat OZD and HEIA samples with CO 2 -loaded spectra. However, we observed that the OZD can protonate when sparged with CO 2 in the presence of MEA, which suggests that the OZD acts as an intermediate. The NMR spectra for HEEDA indicated that HEEDA directly reacts with CO 2 at both amino groups and can protonate. In the presence of MEA, HEEDA and MEA can act like a solvent blend, resulting in multiple carbamates forming within the solvent. The neat HEIA spectrum, compared with CO 2 -loaded HEIA spectra, revealed similar results as OZD, where it does not react with CO 2 or protonate directly. However, HEIA does not protonate in the presence of MEA. These degradation compound reactions can increase the number of general equilibrium reactions during carbon capture and impact the model MEA solvent. This work helps provide a more complete picture of the reactions as the solvent degrades. Although this study examines CO 2 effects on thermal degradation products for MEA, other amines such as piperazine or 1- amino-3-propanol will degrade, and the degradation may speciate similarly with CO 2 . Furthermore, this study can impact and improve process models by assessing the degradation compounds’ reactions with CO 2 and potentially incorporating them into the model based on a neat solvent.
Cost details from front-end engineering design of piperazine with the advanced stripper
This Front-End Engineering Design (FEED) was funded by the U.S. Department of Energy (DOE) to estimate the cost to capture and compress 90% of the CO 2 from an existing natural gas combined cycle (NGCC) in Denver City, Texas, USA. The FEED used the PZAS (Piperazine with the Advanced Stripper) 2G amine scrubbing technology developed and modeled by The University of Texas at Austin. This FEED is unique in providing more public cost details than other FEEDs funded by DOE. The primary objective of the FEED was to provide a comprehensive estimate for the total installed cost of the capture plant. The estimated capital cost of NGCC at the Mustang Station is $\$727$ million for a capacity of 460 MW and 1.6 million tonnes CO 2 /yr. This includes a contingency of $\$104.6$ million and a contractor’s profit of $\$60.1$ million. The total direct field cost is $\$384.1$ million. With an optimistic fuel value of $\$3$/MMBtu, the estimated cost of capture varies from $\$85$/t at 4% IRR/85% load to $\$170$/t at 10% IRR/52% load. Air cooling is technically feasible but expensive. The air cooling systems for the water wash and pump-around intercooling account for 23.4% of the direct cost. The gas-fired boilers represent only 4% of the direct costs, but steam extraction would reduce energy cost, free up cooling water, and reduce the direct costs of processing additional flue gas and CO 2 from the boilers. The absorbers represent 9.6% of the direct cost in this FEED with no direct contact cooler and only 7.6 m of packing. Furthermore, the solvent cross exchangers are less expensive than expected (2.5% of direct costs). Doubling the number of these exchangers could reduce the heat duty from 3.0 to 2.5 GJ/t CO 2 .
Amine Oxidation Catalyzed by NO 2
Amine oxidation is a major risk in the deployment of amine scrubbing for CO2 capture from post-combustion flue gas. Oxidation probably occurs by dissolved oxygen at elevated temperature, Fe(III)/Fe(II) shuttling between the absorber and the stripper, and by NO2 in the absorber. Amine selection, dissolved oxygen removal, and solvent reclaiming mitigate oxidation due to dissolved oxygen and iron shuttle mechanism, but not by NO2. This work examines piperazine (PZ) oxidation by NO2 in a bench-scale high gas flow reactor (HGF). PZ is an effective second-generation solvent with high CO2 capacity, fast capture rate, good thermal stability, and good resistance to oxidation. Flue gas typically contains 0.5–5 ppm NO2 and 10–100 ppm NO. NO2 at 1 ppm in the flue gas appears to cause significant amine oxidation in pilot plant testing. PZ solution can easily absorb NO2, and it is hypothesized that NO2 can catalytically oxidize PZ through free-radical propagation. The issue may not be solved by a NO2 pre-scrubber since the coexistence of NO and O2 in the flue gas will keep producing non-negligible amounts of NO2 in the ductwork and the absorber after the NO2 incoming with the flue gas has been scrubbed. In addition, NO2 may not only oxidize PZ but also the intermediate degradation products, and it is unknown if the existence of dissolved iron influences the oxidation by NO2. Previous workers have also shown that NO2 is the stoichiometric source of nitrosamine. A comprehensive analysis of NO2 oxidation is needed to address solvent management and its health/environmental impact. The new high gas flow (HGF) reactor focuses only on the absorber environment and is simpler to interpret because it does not include oxidation at high temperatures and by dissolved metal catalysts from corrosion. This paper presents the results of HGF experiments and shows evidence to support a hypothesis of amine oxidation catalyzed by NO2, presents the synergic effect of NO2 and iron on amine oxidation, points out the different effects of NO2 in clean and degraded solvents, and demonstrates that NO2 not only can oxidize amines but also their degradation products.
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.
In Silico Discovery of Covalent Organic Frameworks for Carbon Capture
We screen a database of more than 69 000 hypothetical covalent organic frameworks (COFs) for carbon capture using parasitic energy as a metric. To compute CO 2 –framework interactions in molecular simulations, we develop a genetic algorithm to tune the charge equilibration method and derive accurate framework partial charges. Nearly 400 COFs are identified with parasitic energy lower than that of an amine scrubbing process using monoethanolamine; more than 70 are better performers than the best experimental COFs and several perform similarly to Mg-MOF-74. We analyze the effect of pore topology on carbon capture performance to guide the development of improved carbon capture materials.
Corrosion of Stainless and Carbon Steel in Aqueous Piperazine for CO2 Capture
Current obstacles that prevent commercial implementation of amine-scrubbing CO2 capture are the high costs. Reducing capital costs by appropriate selection of construction materials, which requires knowledge of material corrosion performance for the process, will improve the economic feasibility of this technology. Corrosion was evaluated in three pilot plant campaigns using aqueous piperazine with the Advanced Stripper (PZAS). 316L stainless steel (SS) experienced higher corrosion than 304 SS and 2205 duplex SS, and the corrosion rate showed strong dependence on the temperature. 304 and 2205 performed well at all locations and should be good construction materials for PZAS. Degraded PZ exacerbated 316L corrosion, and removal of PZ degradation products using a carbon adsorption bed significantly reduced corrosion. Carbon steel (CS) corrosion showed a weak temperature effect because the corrosion was more dependent on the protective siderite film. The protectiveness of the films was related to fluid velocity. Ni-based alloys corroded in PZ, and the rate increased with temperature. Corrosion of C1010 CS and SS (304, 316L, 430) was measured at absorber and water wash conditions on the bench-scale. Corrosion rate decreases with increasing PZ. 8 With more than 0.003 m PZ in solution, CS has acceptable corrosion performance. Corrosion of CS increases with increasing partial pressure of CO2, suggesting loading is another dominant parameter for carbon steel corrosion. Temperature has a less significant effect than PZ concentration and loading. CS corrosion increases with increasing flow velocity at both absorber and water wash conditions. SS had little corrosion at this lower temperature. Performance of siderite (FeCO3) protective films on CS was studied at representative stripper conditions on the bench-scale. Siderite films can deposit on the surface of CS in CO2-loaded PZ solution at temperatures >100 °C and protect CS from corrosion. The protection may fail in degraded PZ. Ethylenediamine (EDA) is one of the major contributors for the loss of film protectiveness or can be the surrogate for the effect of PZ degradation on siderite film protection. A link between protectiveness and the apparent density of siderite films was discovered. The apparent density of siderite films decreases with increasing flow velocity and decreasing CO2 loading, resulting in higher corrosion of CS.
Carbon dioxide capture system and spectroscopic evaluation thereof
A chemical processing system for removing carbon dioxide from a gas mixture using a multicomponent amine-based scrubbing solution includes a spectroscopic evaluation system with a liquid contact probe for spectroscopic investigation, an energy source connected with the liquid contact probe to provide the spectroscopic stimulation energy to the probe, a spectrometer connected with the liquid contact probe to detect the spectroscopic response energy to the probe and to output spectral data corresponding to the spectroscopic response energy, and a machine learning spectral data analyzer connected to the spectrometer for evaluation of the spectral data to determine a concentration value for each of water, amine component and captured carbon dioxide in the scrubbing solution, the machine learning spectral data analyzer being trained for each such component over a corresponding trained concentration range, and optionally over a trained temperature range to provide a temperature-compensated concentration value.
Investigation of chemical stabilities and contact angle of 3D printed polymers with CO 2 capture solvents to enhance absorber performance
Increasing absorption rate in aqueous amine CCS systems is one avenue to decrease capital cost by reducing the overall size of the absorber column. One potential route is by replacing conventional steel packing with custom designed packing made from 3D printed polymers. 3D printing offers endless flexibility in packing designs to better enhance liquid/gas contact, increase CO 2 mass transfer and create compact absorber columns. Additionally, before exploring novel packing designs, it is necessary to identify polymer materials that can be 3D printed while also showing long-term physical and surface property stability upon exposure to corrosive amine solutions. Four polymers that are commonly used for 3D printing were evaluated using CO 2 -loaded amine solution at temperatures typically observed in the absorber column. Three polymers, high-density polystyrene (HDPS), acrylonitrile butadiene styrene (ABS) and nylon were found to be physically stable after 5000 hr of amine exposure at temperatures up to 60 °C. The contact angle (wetting) of water and CO 2 -loaded aqueous amine solution on the polymer surfaces were also stable after exposure to the CO2-loaded amine solution.
Heat Loss Characteristics and Energy Use of Piperazine with the Advanced Stripper (PZAS) at the UT-SRP Pilot Plant
Heat duty and heat loss were measured at the pilot plant at UT Austin. Heat loss was measured with energy balances using water. Heat loss was studied using surface temperature measurements over 68 different locations at the pilot plant. Surface temperature measurements indicated that bare metal surfaces were the primary source of heat loss from the pilot plant. Heat loss from bare metal surfaces was at least 50% controlled by natural convection and in many cases was as high as 75% natural convection controlled. Measured heat loss at the pilot plant was 20100 BTU/hr and overall heat loss did not show any dependence on the heat rate of the plant. Compared to PZAS™ at the National Carbon Capture Center, heat loss relative to heat rate was higher at 38%. The relative heat loss at the pilot plants was found to decrease by 20% per MW of added capacity. Measured net heat duty was found to be dependent on measured lean loading and cold rich bypass flow rate. Measured net heat duty was between 2.2 and 2.4 GJ/tonne at an optimum lean loading of 0.2–0.21 mol/mol. Data reconciliation by Aspen Plus® Data Fit™ underpredicted CO2 flow rate by 20% due to an overprediction of lean loading by 19%, indicating a necessary change in thermodynamic parameters in the model. This resulted in an over prediction of heat duty by 33% on average.
Purification of Degraded Aqueous Piperazine by Ion Exchange and Carbon Treating
Amine purification by ion exchange and carbon treating has been performed for decades to maintain low solvent impurity levels in amines used in natural gas sweetening. The use of these purification methods to remove dissolved metal catalysts and other impurities from amines used in post-combustion carbon capture is less well known. This report presents batch experiments testing the equilibrium adsorption of impurities from degraded piperazine (PZ) onto activated carbon and various ion exchange resins. Compared to cationic exchange, anionic exchange was found to better remove catalytic Fe and UV active species, making it a better candidate for large-scale PZ purification. Carbon treating greatly outperforms anion exchange in the removal of UV active species, but the adsorbents’ difference is less pronounced for the removal of other impurities. Equilibrium adsorption was determined by the UV absorption of the PZ solution at 320 nm, and the results will show this may not be an accurate way to determine equilibrium. Further bench-scale experiments comparing ion exchange and carbon treating are necessary before advancing to larger-scale testing.
ELECTROCHEMICALLY-MEDIATED AMINE REGE NERATION IN CO2 SCRUBBING PROCESSES
Final Scientific/Technical Report
Corrosion Prevention of Additively Manufactured Aluminum Packing Devices Developed for Process Intensification of CO 2 Capture by Aqueous Amines
Corrosion of additively manufactured (i.e., 3D printed) aluminum packing devices, developed to enhance heat and mass transfer in CO 2 absorption columns using amine-CO 2 scrubbing solutions, is investigated in this paper. The aluminum structures printed by selective laser melting with Al-10Si-0.3Mg feed powder are susceptible to corrosion in aqueous monoethanolamine, both fresh and used CO 2 -saturated solutions. The efficacy of corrosion-protective surface layers of aqueous polyether–ketone–ketone (PEKK) dip coating to provide amine corrosion resistance to the 3D printed aluminum structure is also evaluated. PEKK nanothick layers were coated on the corrugated surface of a 3D printed structure, identical to that of the intensified device, yielding 27 times higher corrosion resistance than the uncoated Al alloy surface. Finally, a systematic long-term electrochemical corrosion analysis revealed that a multilayer PEKK dip coating protocol enables protection of the 3D printed Al alloy surface in various CO 2 –monoethanolamine solutions.
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.
Process intensification of CO 2 capture by low-aqueous solvent
Low-energy solvent-based CO 2 absorption processes have drawn attention as a next-generation post-combustion CO 2 capture technology to reduce CO2 emissions from fossil fuel– or biomass-fired power generation and industrial flue gas streams. A low-aqueous (or water-lean) solvent process may substantially reduce the thermal energy consumption for solvent regeneration. Low-aqueous solvent–based processes are thermally sensitive, requiring a delicate temperature control within the absorber because of the fast exothermic amine-CO 2 reaction and low heat capacity organic diluent. This reaction may result in heat accumulation in a packed absorption column and undesirable CO 2 desorption occurring as the solvent moves through the column, reducing the solvent’s CO 2 capture efficiency if its temperature is not controlled. Using a 3D printed intensified packing device, enhanced heat and mass transfer were demonstrated in an amine-CO 2 scrubbing process using low-aqueous solvent. The multifunctional intensified device facilitates contact of the reactive solvent and gas phases in a single stage and heat removal by a cooling fluid flowing through channels in the interior of the corrugated plates of the device. These functionalities led to effective thermal management along the column via intrastage cooling and significant improvement in CO 2 uptake under a wide range of operating conditions. Intrastage cooling effectively reduced the solvent average temperature along the column by ~10 °C and, as a result, the solvent’s capture efficiency improved by up to 25%.
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.