CCUS Innovation 2.0 competition: UNICORN - Efficient MOF based pilot unit for CO2 filtration

UNICORN - Efficient MOF based pilot unit for CO2 filtration Project lead: University of Sheffield (Translational Energy Research Centre - TERC ) This project investigated the potential of biomass energy with carbon capture and storage ( BECCS ) for wide-spread deployment, using a novel approach of a molten carbonate fuel cell ( MCFC ) system for the post combustion capture of the flue gases. A MCFC system generates power (and heat) from a second fuel source, at the same time as it separates the carbon dioxide and removes nitrogen oxides from the flue gases with option of producing hydrogen if required. October 2023 Optimised Solvent Plant Configurations CCUS Innovation 2.0 Key Knowledge Deliverable 3.1 Key Knowledge Deliverable Cover Sheet This Key Knowledge Deliverable (KKD) has been produced by the Translational Energy Research Centre at the University of Sheffield as part of the Department for Energy Security and Net Zero £1bn Net Zero Innovation Portfolio (NZIP) - CCUS Innovation 2.0 programme. The document is reflective of the status of the project at the time of writing. The material presented could be subject to change as the project matures. These documents should not be considered a full representation of the final project. UK BECCS-MCFC: Next Generation CCUS Technology for Net-Zero 2050 Baseline Test Work: Optimisation - Reporting Optimised solvent/plant configurations. Kirsty Lindley Head of Research Grant Operations © Crown copyright 2026 This publication is licensed under the terms of the Open Government Licence v3.0 except where otherwise stated. To view this licence, visit nationalarchives.gov.uk/doc/open- government-licence/version/3. Where we have identified any third-party copyright information you will need to obtain permission from the copyright holders concerned. 4 Contents Optimised solvent plant configurations for comparison with BECCS MCFC options ________ 5 MCFC BECCS configurations ________________________________________________ 6 MCFC fuelled by natural gas and producing electricity integrated with a biomass combustion steam plant ___________________________________________________ 6 MCFC fuelled by natural gas and producing as little electricity and as much hydrogen as possible integrated with a biomass combustion steam plant _______________________ 7 Solvent BECCS configurations _______________________________________________ 8 Amine PCC integrated with a biomass steam plant ______________________________ 8 Amine PCC combined with a biomass steam plant and a CCGT+PCC _______________ 9 Amine PCC integrated with a biomass steam plant and a separate natural gas reformer 10 Feed-through into the TEA __________________________________________________ 11 Optimised solvent plant configurations 5 Optimised solvent plant configurations for comparison with BECCS MCFC options The purpose of this report is to describe the plant configurations using conventional amine post-combustion capture and other conventional technologies that best match the proposed novel molten carbonate fuel cell (MCFC) BECCS configurations. Novel MCFC technology is being proposed for biomass energy with carbon capture and storage (BECCS) applications in the UK. To assess its technical and economic viability, as part of this project test work on a pilot scale MCFC will be used to underpin techno-economic analysis (TEA) of future commercial plants. This TEA will be contrasted with comparable values for the conventional amine post-combustion capture options described in this report. Two possible MCFC BECCS configurations are described first, then their nearest conventional plant analogues. It is assumed that the reader is familiar with the basic features of the following types of plant, some example reference sources are also indicated in the footnotes: MCFC1, biomass steam boiler and combined cycle gas turbine power plants with CCS2 and methane reformers3 for hydrogen production. Both sets of BECCS options (MCFC and conventional) are based on biomass combustion only, since large-scale biomass gasifiers capable of producing either a syngas for conventional hydrogen production or a fuel gas for MCFC are not commercially proven. Because different plant configurations contain common elements and individual sections want to be readable as stand-alone items, there is some repetition of text on the same issues. 1 https://www.gov.uk/government/publications/review-of-next-generation-carbon-capture-technology-for-industrial- waste-and-power-sectors 2 https://ukccsrc.ac.uk/wp-content/uploads/2023/01/BAT-for-PCC_v2_EfW_web-1.pdf 3 https://www.gov.uk/government/publications/review-of-emerging-techniques-for-hydrogen-production-from- methane-and-refinery-fuel-gas-with-carbon-capture Optimised solvent plant configurations 6 MCFC BECCS configurations MCFC fuelled by natural gas and producing electricity integrated with a biomass combustion steam plant MCFC fuelled by natural gas and producing electricity integrated with a biomass combustion steam plant This configuration is based on a conventional biomass combustion power plant that burns biomass to generate steam that is then used in a steam turbine to generate electricity. A range of plant sizes and boiler types might be used, but all have the same basic inputs/outputs. The flue gas is then cleaned to the high standard required and passed to a MCFC (possibly several MCFC units, via a manifold system) for CO2 capture. To make the MCFC work, natural gas fuel is supplied directly to it and, in this case, the MCFC converts as much as possible of the energy in the fuel to electricity. The overall capture rate expected for the carbon dioxide from natural gas is up to 100%4. The overall capture rate expected for the CO2 in the flue gas from the biomass plant is up to ~95%. Note that the transfer system for flue gas to the MCFC may also involve an open stack, to avoid the potential for over-pressurisation if the induced draft fan on the boiler plant and the forced draft fan on the MCFC plant fail to match flows exactly. In this case any leakage out from the open stack will obviously also adversely affect the biomass flue gas capture rate. The electricity produced by this configuration will vary in value in future UK electricity generation mixes dominated by variable renewable electricity (VRE) sources, principally wind and solar. In particular, at times when VRE generation exceeds demand, especially demand that is already net of peak electricity balancing uses such as charging storage, generating electrolytic hydrogen etc., the electricity production from both the biomass power plant and the MCFC may be valueless. 4 https://www.sciencedirect.com/science/article/pii/S0306261922000393?via%3Dihub T. A. Barckholtz, K. M. Taylor, S. Narayanan, S. Jolly and H. Ghezel-Ayagh, “Molten carbonate fuel cells for simultaneous CO2 capture, power generation, and H2 generation,” Applied Energy, vol. 313, 2022. Optimised solvent plant configurations 7 MCFC fuelled by natural gas and producing as little electricity and as much hydrogen as possible integrated with a biomass combustion steam plant MCFC fuelled by natural gas and producing as much hydrogen as possible electricity integrated with a biomass combustion steam plant This configuration is similar to the previous one, but the MCFC is operated to minimise electricity production and maximise hydrogen production from conversion of the natural gas feed. It is possible that there is always a demand for the hydrogen because it can be stored if not required at the time. It is also possible, however, that factors such as the demand for hydrogen in the UK being seasonal, the variability in electrolytic hydrogen production from VRE and limitations on hydrogen storage capacity make this assumption invalid. As before, the overall capture rate expected for the carbon dioxide from natural gas is up to 100% and from the biomass flue gas is expected to be up to ~95%, subject to any leakage during the flue gas transfer. Optimised solvent plant configurations 8 Solvent BECCS configurations Amine PCC integrated with a biomass steam plant Best Available Technology amine PCC integrated with a biomass steam plant This configuration is based on a conventional biomass combustion power plant that burns biomass to generate steam that is then used in a steam turbine to generate electricity. A range of plant sizes and boiler types might be used, but all have the same basic inputs/outputs. The flue gas is then cleaned as necessary and passed to an amine post-combustion capture (PCC) plant. Steam and electricity for the PCC plant are provided from the biomass plant, reducing the amount of electricity available for export. Capture rates of 95% are the current expected standard for PCC on biomass power plants in UK guidance5 and even higher capture rates may be achieved in practice6. Note, though, that the transfer system for flue gas to the PCC plant may also involve an open stack, to avoid the potential for over-pressurisation if the induced draft fan on the boiler plant and the forced draft fan on the PCC plant fail to match flows exactly. In this case any leakage out from the open stack will obviously also adversely affect the biomass flue gas capture rate. The electricity produced by this configuration will vary in value in future UK electricity generation mixes dominated by variable renewable electricity (VRE) sources, principally wind and solar. In particular, at times when VRE generation exceeds demand, especially demand that is already net of peak electricity balancing uses such as charging storage, generating electrolytic hydrogen etc., additional electricity production from the biomass power plant may be valueless. To take advantage of this varying value for exported electricity rich and lean solvent storage tanks can be used so that at least some of the electricity output penalty can be taken during periods of low electricity value, with a consequent increase in net plant electricity output at times of high electricity value7. 5 https://www.gov.uk/guidance/post-combustion-carbon-dioxide-capture-best-available-techniques-bat 6 https://ukccsrc.ac.uk/wp-content/uploads/2023/01/BAT-for-PCC_v2_EfW_web-1.pdf 7 Chalmers, H., Gibbins, J. & Leach, M. (2012) Valuing power plant flexibility with CCS: the case of post- combustion capture retrofits, Mitigation and Adaptation Strategies for Global Change, vol. 17, no. 6, pp. 621-649. https://doi.org/10.1007/s11027-011-9327-5 Optimised solvent plant configurations 9 Amine PCC combined with a biomass steam plant and a CCGT+PCC Amine PCC integrated with a biomass steam plant and a CCGT+PCC If baseload, mainly gas fired, electricity output, as with the ‘MCFC fuelled by natural gas and producing electricity integrated with a biomass combustion steam plant’ configuration is, however, valuable then a gas-fired combine cycle gas turbine (CCGT) + PCC plant might be integrated with a biomass PCC plant. Various integration options are possible, in the one shown above steam is supplied for the biomass PCC unit from the CCGT heat recovery steam generator (HRSG) and surplus low grade heat (at temperatures below the low-pressure (LP) pinch in the HRSG) is also sent to the biomass steam plant. This approach gives the greatest possible output from the biomass steam plant and would therefore attract greater revenues if a premium price was paid for BECCS electricity – and measures were not in place to avoid some natural gas energy also being rewarded for appearing as output from the BECCS plant. More extreme integration, particularly with small size units, might theoretically see a shared absorber, more likely a shared stripper. Sequential combustion, where the GT flue gas is sent to the biomass boiler to recover heat and, in the context of PCC to raise the CO2 content, is also possible but not likely. If the natural gas CCGT+PCC plant was not integrated, and possibly even sited elsewhere, with the BECCS plant configured as in the previous case and providing its own steam and electricity for the PCC unit, then the confusion over electricity source would not occur. A slight reduction in aggregate electricity production might appear to result, due to the inability to use heat below the LP pinch in the HRSG but, for smaller BECCS applications, the separate CCGT could in effect be a part of a much larger conventionally-sized CCGT power plant, with very significant cost and efficiency improvements. Optimised solvent plant configurations 10 The greatest benefit of separate operation (and possibly siting) of the CCGT+PCC and BECCS plant is, however, the CCGT+PCC plant can be shut down at periods when its electricity was not required due to surplus VRE and would be essentially valueless, saving unnecessary natural gas consumption. As before, the overall capture rate expected for the carbon dioxide from natural gas and from the biomass flue gas is expected to be 95% or greater, subject to any leakage during the flue gas transfer. Amine PCC integrated with a biomass steam plant and a separate natural gas reformer Amine PCC integrated with a biomass steam plant and a separate natural gas reformer This combination minimises the amount of baseload electricity production and maximises the hydrogen production from natural gas with CCS, for comparison with the ‘MCFC fuelled by natural gas and producing as little electricity and as much hydrogen as possible’ case. It is possible that an electricity supply is also required for the natural gas reformer unit; this could be provided from the BECCS plant but this would not constitute a genuine baseload demand in most cases (i.e. unless grid connections were infeasible), since it could be more cheaply supplied from the grid at times when VRE generation is plentiful. A conventional biomass combustion power plant burns biomass to generate steam that is then used in a steam turbine to generate electricity. A range of plant sizes and boiler types might be used, but all have the same basic inputs/outputs. The flue gas is then cleaned as necessary and passed to an amine post-combustion capture (PCC) plant. Steam and electricity for the Optimised solvent plant configurations 11 PCC plant are provided from the biomass plant, reducing the amount of electricity available for export. Capture rates of 95% are the current expected standard for PCC on biomass power plants in UK guidance8 and even higher capture rates may be achieved in practice9, subject to any leakage during the flue gas transfer. For comparison with the high-hydrogen MCFC case, a natural gas reformer is assumed to be used to generate hydrogen. This reformer could be a range of types; all achieve similar conversion efficiencies from natural gas to hydrogen and can capture 95% or more of the CO2 produced10. Feed-through into the TEA The amine capture plant baseline TEA for this Work Package will always use the optimised full-integrated amine plant, optionally with solvent storage. The additional CCGT+PCC plant for power and a natural gas reformer for hydrogen production will be assumed to be independent from the amine BECCS plant, since this is likely to be the norm and so independent plants will be the electricity and hydrogen market price-setters. Estimated values for dispatchable gas-fired electricity and hydrogen production with CCS will then be produced based on published data for the characteristics of these plants plus the key variables being considered for the amine capture plant baseline, principally natural gas price and the fraction of time that available generation is in excess of demand. The amine capture plant will be assumed to be penalised by extra costs for the ‘lost’ electricity output at the value of alternative electricity sources. Similarly, the MCFC configurations can be assumed to be rewarded by revenues at the value of alternative electricity and hydrogen sources in the techno-economic analysis, to offset the additional cost for the natural gas fuel supply to the fuel cell. 8 https://www.gov.uk/guidance/post-combustion-carbon-dioxide-capture-best-available-techniques-bat 9 https://ukccsrc.ac.uk/wp-content/uploads/2023/01/BAT-for-PCC_v2_EfW_web-1.pdf 10 https://www.gov.uk/government/publications/review-of-emerging-techniques-for-hydrogen-production-from- methane-and-refinery-fuel-gas-with-carbon-capture 12 If you need a version of this document in a more accessible format, please email alt.formats@energysecurity.gov.uk. Please tell us what format you need. It will help us if you say what assistive technology you use. November 2023 Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend CCUS Innovation 2.0 Key Knowledge Deliverable 3.2 & 3.3 Key Knowledge Deliverable Cover Sheet This Key Knowledge Deliverable (KKD) has been produced by the Translational Energy Research Centre at the University of Sheffield as part of the Department for Energy Security and Net Zero £1bn Net Zero Innovation Portfolio (NZIP) - CCUS Innovation 2.0 programme. The document is reflective of the status of the project at the time of writing. The material presented could be subject to change as the project matures. These documents should not be considered a full representation of the final project. UK BECCS-MCFC: Next Generation CCUS Technology for Net-Zero 2050 Baseline Test Work: Solvent Performance and Degradation - Reporting performance data for concentrated MEA and advanced amine blend, and concerning degradation and mitigation, technoeconomic data. Kirsty Lindley Head of Research Grant Operations © Crown copyright 2026 This publication is licensed under the terms of the Open Government Licence v3.0 except where otherwise stated. To view this licence, visit nationalarchives.gov.uk/doc/open- government-licence/version/3. Where we have identified any third-party copyright information you will need to obtain permission from the copyright holders concerned. 4 Contents Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend ________________________________________________________ 6 Glossary _________________________________________________________________ 7 Solvent descriptions and initial comparison _____________________________________ 10 Monoethanolamine ______________________________________________________ 10 CESAR1 – PZ and AMP blend _____________________________________________ 10 Initial comparison between MEA and CESAR1 components ______________________ 11 Biomass plant flue gas cleaning required for NOx, SOx and particulates ______________ 12 Expected Best Available Technology pollutant levels for biomass power plants _______ 12 NOx and SOx for MEA (excluding SO3 aerosols) _______________________________ 14 Oxides of nitrogen – NOx for CESAR1 and nitrosamine management ______________ 15 Particulates and aerosols _________________________________________________ 16 Conclusions on flue gas cleaning required for the use of MEA or CESAR1 for BECCS _ 17 Solvent Degradation: solvent reclaiming or cleaning ______________________________ 17 Thermal reclaiming of MEA and CESAR1 at TCM ______________________________ 18 Solvent reclaiming/cleaning conclusions for the use of MEA or CESAR1 ____________ 22 Solvent Degradation: acid wash for amine and degradation product emissions control ___ 23 General considerations ___________________________________________________ 23 MEA with acid wash _____________________________________________________ 23 CESAR1 with an acid wash _______________________________________________ 24 Acid Wash conclusions for the use of MEA or CESAR1 _________________________ 25 CO2 capture rate and regeneration energy requirements __________________________ 26 MEA capture rate and regeneration energy data sources ________________________ 26 CESAR1 capture rate and regeneration energy data sources _____________________ 27 Comparison of capture rate and regeneration energy data _______________________ 28 Capture rate and regeneration energy conclusions for the use of MEA or CESAR1 ____ 30 OVERALL CONCLUSIONS _________________________________________________ 31 Key characteristics for MEA and CESAR1 (or any solvent used for post-combustion capture) ______________________________________________________________ 31 Comparison of MEA and CESAR1 on showstopper issues _______________________ 32 Comparison of MEA and CESAR1 on marginal improvements (scope for cost reduction) 33 5 Comparison of MEA and CESAR1 on in-between issues ________________________ 34 Overall conclusions for subsequent techno-economic assessment _________________ 35 Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 6 Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend The purpose of this report is to discuss key performance characteristics, based on analysis of published information, for two potential solvents for use in a BECCS plant with amine post-combustion capture: a) MEA at 35% w/w concentration b) CESAR 1 – a mixture of 13 %w/w piperazine (PZ) and 27% w/w AMP The key performance characteristics are: i) Biomass plant flue gas cleaning required for NOx, SOx and particulates ii) Solvent Degradation: solvent reclaiming or cleaning iii) Solvent Degradation: acid wash for amine and degradation product emissions control iv) CO2 capture rate and energy requirements This report covers Deliverable 3.2 ‘Performance data and solvent management for concentrated MEA and advanced amine blend’ and Deliverable 3.3 ‘Solvent degradation’, with the two deliverables incorporated in the one report to allow the critical interactions between these two topics to be presented and discussed. Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 7 Glossary AMP Aminomethyl Propanol bara Bars Absolute (absolute pressure in bars, i.e. units of 105 Pa) barg Bars gauge, pressure in relation to atmospheric pressure BAT Best Available Technology BD3 Boundary Dam power plant, Unit 3; the first power plant fitted with PCC BECCS Biomass Energy with Carbon Capture and Storage BREF LCP The BAT Reference Document (BREF) for Large Combustion Plants (BREF LCP, 2017) CCGT Combined Cycle Gas Turbine power plant CCS Carbon (dioxide) Capture and Storage CCU Carbon (dioxide) Capture and Utilisation, not involving permanent storage of the CO2 CCUS Carbon (dioxide) Capture, Utilisation and Storage (overwhelmingly EOR at present) CDR Carbon Dioxide Removal from the air CFB Circulating Fluidised Bed boiler/steam power plant CHP Combined Heat and Power plant CO2 Carbon dioxide COPx The Coefficient Of Performance for (steam) extraction; ratio of heat supplied to a PCC plant by steam extracted from a steam cycle to the reduction in work (electricity) output from that steam cycle DCC Direct Contact Cooler; brings the flue gas into contact with water upstream of the absorber, possibly with added caustic to neutralise acid gases DESNZ Department for Energy Security & Net Zero, see https://www.gov.uk/government/organisations/department-for-energy-security-and- net-zero DPA Dispatchable Power Agreement, see https://www.gov.uk/government/publications/carbon-capture-usage-and-storage- ccus-business-models EAL Environmental Assessment Level EfW Energy from Waste ELV Emission Limit Value EOP Electricity Output Penalty ESP Electrostatic Precipitator FCC Fluid Catalytic Cracker FGD Flue Gas Desulphurisation plant FWH Feed Water Heater (in a steam boiler) GT Gas Turbine Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 8 HCl Hydrogen Chloride (Hydrochloric Acid when dissolved in water) HHV Higher Heating Value (also known as gross calorific value) HF Hydrogen Fluoride (Hyfluoric Acid when dissolved in water) HP High Pressure, the highest pressure cylinder in a steam turbine HRSG Heat Recovery Steam Generator (sometimes pronounced “hersig”) HSS Heat Stable Salts IP Intermediate Pressure, the intermediate pressure cylinder in a steam turbine IX Ion exchange reclaimer unit LC MS QQQ Liquid Chromatography with triple-Quadrapole Mass Spectrometry LHV Lower Heating Value (also known as net calorific value) LP Low Pressure, the lowest pressure cylinder in a steam turbine MEA Monoethanolamine MHI Mitsubishi Heavy Industries MSG Minimum Stable Generation NCCC National Carbon Capture Center https://www.nationalcarboncapturecenter.com/ NETL National Energy Technology Laboratory https://www.netl.doe.gov/ NGCC Natural Gas Combined Cycle NH3 Ammonia NOx Oxides of Nitrogen NPC National Petroleum Council https://www.npc.org/ O2 Oxygen OEM Original Equipment Manufacturer Pa Pascal, unit of pressure, 1N/m2 PAC Powdered Activated Carbon PCC Post-combustion (CO2) capture ppm parts per million ppmv, ppbv parts per million by volume; parts per billion by volume PTR-TOF-MS Proton-transfer-reaction time-of-flight mass-spectrometer. Used to measure VOCs. Similarly, QMS = quadrupole-mass-spectrometer PZ Piperazine RAMO Reliability, Availability, Maintainability, Operability RFCC Residual Fluid Catalytic Cracker RH Reheat(er) (in a steam boiler) SCR Selective Catalytic Reduction (of NOx) SO2 Sulphur dioxide SO3 Sulphur trioxide (with water, forms sulphuric acid) SOx Oxides of Sulphur (unspecified mix of SO2 and SO3) SRD Specific Reboiler Duty Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 9 ST Steam Turbine STG Steam Turbine Generator T&S (CO2) Transport and Storage TCM Technology Centre Mongstad https://tcmda.com/ TEA Techno-Economic Analysis TERC Translational Energy Research Centre, University of Sheffield https://terc.ac.uk/ TONO Total nitrosamines tpd tonnes per day TPY Tonnes Per Year TRU Thermal Reclaimer Unit VLE Vapour Liquid Equilibrium VOC Volatile Organic Compounds WESP Wet ElectroStatic Precipitator XFHE The cross-Flow Heat Exchanger, transferring heat from the hot lean solvent leaving the stripper to the cooler rich solvent coming from the absorber Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 10 Solvent descriptions and initial comparison Monoethanolamine Chemical structure of Monoethanolamine (Wikimedia) Monoethanolamine is a primary amine with the structure shown above. It is typically used at concentrations of 30-35% w/w in water, occasionally up to 40% w/w. It has seen extensive long-term use for flue gas CO2 capture, mostly in smaller plants to date. CESAR1 – PZ and AMP blend Piperazine structure Aminomethyl propanol structure CESAR11 is a blend of 26.7 wt% (3.0 M) 2-amino-2-methylpropan-1-ol (AMP) and 12.9 wt% (1.5 M) piperazine (PZ)). AMP is the sterically hindered form of the primary amine MEA. Piperazine is a cyclic ethylene amine with two secondary amine groups. CESAR1 has been used in a number of research projects but has no commercial deployment examples. It is named after the original project that pioneered its use ‘CESAR: CO2 Enhanced Separation and Recovery’2. 1 https://gassnova.no/app/uploads/sites/5/2022/04/10-CESAR-1-Solvent.pdf 2 https://cordis.europa.eu/project/id/213569/reporting Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 11 Initial comparison between MEA and CESAR1 components NETL (2015)3 gives a summary of solvent properties relevant for commercial use based on the NETL test programme: Primary and secondary amines typically have higher rates of reaction with CO2 compared to tertiary amines. Among various primary amines, MEA has the highest reaction rate, and blends of MEA and other tertiary or hindered amines are typically used to exploit this feature while maintaining relatively-low reboiler loads. Primary/secondary (mono)amines with a 1:2 stoichiometry have lower CO2 carrying capacity compared to tertiary amines which bind 1:1 with CO2. Further, polyamines such as piperazine have a higher carrying capacity because they have two amine groups per molecule. Tertiary amines have higher CO2 capacities but the reaction kinetics with CO2 are significantly slower than primary and secondary amines. Because the CO2 carrying capacity is expressed in wt% CO2 in the solvent, or the quantity of solvent circulated to capture a unit quantity of CO2, the molecular weight and density of the solvent also play a role in determining its volumetric or weight-based CO2 carrying capacity. From a health and environmental safety perspective, MEA is highly biodegradable, and has no direct adverse effects on human health, animals, and vegetation. Other amine solvents such as AMP, MDEA and PZ are toxic and are not easily biodegraded compared with MEA. The reaction of amines with NOx in the flue gas leads to the formation of nitrosamines, which are carcinogenic. The reactivity with NOx varies with the amine structure. 3 NETL (2015) DOE/NETL Carbon Capture Program—Carbon Dioxide Capture Handbook, August 2015. https://www.netl.doe.gov/sites/default/files/netl-file/Carbon-Dioxide-Capture-Handbook-2015.pdf Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 12 Biomass plant flue gas cleaning required for NOx, SOx and particulates Expected Best Available Technology pollutant levels for biomass power plants BREF pollutant emissions from the ‘UK Interpretation Guidance and Permitting Advice on the Best Available Techniques (BAT) Conclusions for Large Combustion Plants (LCPs)’4 are as follows (original table numbers retained for ease of referencing by readers): Note approximate conversion factors as follows: SO2 mg/Nm3 to ppmv = x 0.35; NO mg/Nm3 to ppmv = x 0.75 4 https://consult.environment-agency.gov.uk/psc/permit-reviews-for-food-drink-milk- industries/supporting_documents/Large%20Combustion%20Plant%20OFFICIAL%20LCP%20BATC%20%20Inter pretational%20Guidance.pdf Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 13 129. See guidance point [number not stated in original] in the general considerations section above on how to address BAT requirements for the application of one, or more, of the techniques specified above. Bag filters are only generally used on biomass plants covered by Chapter IV of the IED due to the different abatement systems used on such plant (e.g. injection of lime and activated carbon that are used to reduce acid gas and heavy metal emissions.). Bag filters are not necessarily BAT for dust abatement for plants that are not covered by Chapter IV of the IED and/or that do not use relevant additional abatement systems. Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 14 NOx and SOx for MEA (excluding SO3 aerosols) NOx and SOx level recommendations for MEA in the open literature appear to be based on the following two papers, building on extensive experience by Fluor with their MEA-based Econamine solvent: a) a paper on the Fluor Econamine FG process (Chapel, 1999)5, b) a study by Fluor for IEAGHG (Fluor, 2004)6. These papers stated the following: Chapel (1999) on NOx for MEA: ‘Thus far, oxides of nitrogen have never created problems in Econamine FG units, however they have led to corrosion of steel and amine degradation in other plants. The Bridgeport CO2 recovery plant did not eliminate some corrosion problems until the NOx was reduced to less than 1 ppmv in the absorber feed. NOx is best controlled though control of the peak flame temperature in the boilers. Also, any boiler NOx reduction (SCR) equipment will benefit the absorption process. The chief culprit in NOX is NO2, which reacts to form nitric acid in the amine solvent and ultimately heat stable salts. However, typically only 10% of the NOx is NO2 and only a fraction of the NO2 gas is absorbed in the solvent. NOx can be a problem in the CO2 product if it is to be used in the food and beverage industry and steps must be taken in the liquefaction unit for its removal.’ Fluor (2004) on SOx for MEA and MHI and NO2: ‘The flue gas input to a solvent scrubbing unit has to have low concentrations of SOx and NO2, as these substances result in loss of solvent. The SOx limit is set at 10ppm(v) by Fluor and 1 ppm(v) by MHI. Such low concentrations can be achieved by current FGD technologies. The NO2 limit set by Fluor is 20 ppm(v) but the selective catalytic reduction (SCR) unit included in the coal fired plants in this study produces a flue gas with a NO2 concentration to 5 ppm(v).’ Chapel (1999) on SOx for MEA: ‘Flue gases can contain significant concentrations of SOx unless natural gas or very low sulfur fuels are being fired. SOx reacts irreversibly with MEA to produce non-reclaimable corrosive salts that are very detrimental to plant operation. For MEA- based processes, it is less expensive to install a SOx scrubber than to accept the solvent losses when the flue gas contains more than 10 ppmv SO2. Coal fired boilers produce the highest concentrations of SOx, often 300 to 5000 ppmv before flue gas desulfurization (FGD), but even oil firing can produce 100 ppmv SOx. The limestone or wet lime FGD systems in large power boilers today achieve SOx reductions in the 90-95% range. Therefore, even the flue gas from a low-sulfur liquid or solid fuel, or from a limestone FGD system needs further SO2 removal. The 10 ppmv SO2 requirement is met by using the active alkali metal neutralizing agents, caustic soda or soda ash, in a relatively inexpensive spray scrubber. Sulfur trioxide, SO3, presents additional problems. SO3, like SO2, leads to solvent losses due to the formation of non-reclaimable heat stable salts, but it also forms a corrosive H2SO4 5 Chapel, D.G., Mariz, C.L. and Ernest, J. (1999) Recovery of CO2 from Flue Gases: Commercial Trends, Presented at the Canadian Society of Chemical Engineers annual meeting, October 4-6, 1999, Saskatoon, Saskatchewan, Canada. http://citeseerx.ist.psu.edu/viewdoc/download?doi=10.1.1.204.8298&rep=rep1&type=pdf 6 Fluor (2004), Potential for improvement in power generation with post combustion capture of carbon dioxide, IEAGHG PH4/33, November 2004, https://ieaghg.org/docs/General_Docs/Reports/PH4- 33%20post%20combustion.pdf Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 15 aerosol in wet scrubbers. Furthermore, less than one-third of the SO3 may be removed by the SO2 scrubbing system unless a special mist eliminator is used. Therefore, most of the remaining SO3 will form heat stable salts in the absorber. The fraction of SOx which forms SO3 is a function of combustion, fuel composition, and flue gas processing factors, but SO3 typically accounts for a few percent of the total sulfur. Minimization of SO3 is a boiler design issue preferably handled upstream of the SO2 scrubber.’ Oxides of nitrogen – NOx for CESAR1 and nitrosamine management In CESAR1 testing at TCM7 on the sensitivity of CESAR1 to NO2 in the flue gas, which forms nitrosamines that are stable under normal PCC system operating conditions and causes other degradation products, total nitrosamine concentration of up to 4500 mg/kg (0.45% w/w) were observed. The impacts of NO2 appeared to be able to be reduced by NOx reduction in the power plant, as evidenced by testing for operation with, and the without, the SCR unit on the GT CHP plant at TCM operational. Specific measures to reduce NO2, a thiosulphate wash upstream of the PCC unit, were, however, found to have no significant impact in RWE tests on a brown coal plant (Moser, 2023)8. But at any level of NOx CESAR1 would require measures to remove or destroy nitrosamines. Moser (2023) noted that “four tests have been carried out to investigate the degradation rate of CESAR1 and the destruction of nitrosamines in the solvent at elevated desorber pressure of 2.4 bar(a) and corresponding reboiler temperature of 130oC (for 7 days after 337 day testing time, for further 5 days after 354 days, 7 days after 822 days, and for 12 days after 912 days during the campaign with NO2 removal).” Total nitrosamines could be maintained at fairly constant levels by these measures but the absolute amounts present were not stated, although detailed measurements were taken, see below: “The analyses regarding the nitrosamine concentrations in the solvent have been carried out by HENKEL using in-house analytical methods. The analysis error is estimated at +/-20%. The matrix of the aged solvent means a challenge for the accuracy of the analysis results. For the analysis of the concentration of N-nitrosodiethanolamine (NDELA) the sample preparation comprised the derivation with N-methyl-N-(trimethylsilyl)trifluoracetamide. The measurement is based on gas chromatography (GC) and a chemiluminescence detector after addition of an internal standard (N-nitrosodiisopropanolamine). Results of the double measurement were averaged. Also mononitrosopiperazine (MNPZ) was analysed with GC/chemiluminescence (the response factor was stoichiometrically derived and evaluated against an internal standard). The concentration of total N-nitrosamines comprised the dissociation of the NO group of all nitrosamines in the solvent and detection by chemiluminescence. To compensate 7 Benquet, C., Knarvik, A., Gjernes, E., Hvidsten, O., Romslo, K., and Akhter, S. (2021) First Process Results and Operational Experience with CESAR1 Solvent at TCM with High Capture Rates, (ALIGN-CCUS Project) (February 11, 2021). Proceedings of the 15th Greenhouse Gas Control Technologies Conference 15-18 March 2021. https://ssrn.com/abstract=3814712 ; http://dx.doi.org/10.2139/ssrn.3814712 8 Moser, P., Wiechers, G., Schmidt, S., Veronezi Figueiredo, R., Skylogianni, E., Garcia Moretz-Sohn Monteiro, J. (2023) Conclusions from 3 years of continuous capture plant operation without exchange of the AMP/PZ-based solvent at Niederaussem – insights into solvent degradation management, International Journal of Greenhouse Gas Control, Volume 126, 2023. https://doi.org/10.1016/j.ijggc.2023.103894 (https://www.sciencedirect.com/science/article/pii/S1750583623000646) Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 16 for matrix interferences the standard addition method was applied, using NDELA for spiking. As the individual nitrosamines in the solvent and their molecular weights are not known the molecular weight of the N–N– – O-group (44 g/mol) as structural element of all nitrosamines is used for the calculation of the mass-related content of total N-nitrosamines. Also here the results of the double measurement were averaged.” Particulates and aerosols9 Fine aerosols in flue gases going to amine capture units can lead to very high amine carryover. As flue gases going up the absorber pass the warmest point and start to get cooled by the incoming lean solvent at the top of the absorber they become super-saturated and any aerosol particles present will provide nuclei for small droplets to form. Very small droplets of water and amine are not easily stopped in a water or acid wash because they follow the streamlines of the gas and don’t contact any surfaces. So, if an amine ‘fog’ is produced, amine emissions from the absorber can be very high, perhaps several orders of magnitude, or more, higher than would be achieved with only amine vapour present and well-operated water and acid washes. There are a number of absorber exit countermeasures proposed for amine aerosols but discussing these, and their merits, is beyond the scope of this report. The alternative, which this report is concerned with because it closely matches existing, proven industrial practice, is stopping aerosols getting to the PCC plant in the first place in significant quantities. Technology Centre Mongstad (TCM) in Norway installed a Brownian filter10 that successfully removed aerosols after seeing problems with cat cracker flue gases, but this is a specialised unit with a relatively high pressure drop. The National Carbon Capture Centre (NCCC) in Alabama, US, did not use a specialised unit but found that their aerosol issues went away when a baghouse was added11 to Plant Gaston that supplies their coal flue gas slipstream. This led to the assumption in the field that ‘baghouses stop aerosols’. This simple link is, however, challenged by Toshiba’s recent experience with a large PCC pilot on the Mikawa biomass plant in Japan. Despite there being a baghouse in the flue gas path this PCC unit also needs to use, apparently successfully, significant additional absorber exit washing measures to remove an amine aerosol12. Obviously fuels are different from the NCCC coal application above and the aerosols may differ (e.g. they may include condensed biomass ash species) and full details of the baghouse and its operation are not published. 9 Because of its importance the data in is section was previously published as a LinkedIn article, Baghouses alone don’t automatically stop aerosols reaching amine capture plants 10 Lombardo, G., Shah, M., Fostås, B., Hvidsten, O., Faramarzi, L. de Cazenove, T., Lepaumier, H. and Rogiers, P. (2018) Results from Testing of a Brownian Diffusion Filter for Reducing the Aerosol Concentration in a Residue Fluidized Catalytic Cracker Flue Gas at the Technology Center Mongstad, Proc.14th Greenhouse Gas Control Technologies Conference, 21-26 October 2018 (GHGT-14). https://papers.ssrn.com/sol3/papers.cfm?abstract_id=3366032 11 Morton, F., Anthony, J., Carroll, J., Corser, M., Wu, T. Yongue, R. (2018) Status of Technology Development at the National Carbon Capture Center, Proc.14th Greenhouse Gas Control Technologies Conference 21-26 October 2018 (GHGT-14). https://ssrn.com/abstract=3366390 12 Kitamura, H., Iwasa, K., Fujita, K., Muraoka, D. (2022) CO2 Capture Project integrated with Mikawa Biomass Power Plant, Proc. 16th Greenhouse Gas Control Technologies Conference 23-24 Oct 2022 (GHGT-16). https://ssrn.com/abstract=4282099 Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 17 Nonetheless, at least circumstantial evidence is there that some combination of additional upstream interventions, possibly providing PAC or hydrated lime particles for SO3 to condense on as the flue gas goes through the acid dew point, and the nature of the filter cake in the baghouse, with PAC, lime and coal fly ash all present, may be what is required to remove aerosols successfully when using a baghouse in combination with an amine PCC unit. Hence the suggestion is that new biomass plants plan to install a baghouse rather than an ESP and, if not included already from the outset, provisions are made to add Powdered Activated Carbon (PAC) injection for mercury control and hydrated lime injection for SOx control in case they are found to be necessary to minimise aerosol carryover when the PCC plant is operated. Conclusions on flue gas cleaning required for the use of MEA or CESAR1 for BECCS It appears that SOx levels for BREF-compliant biomass plants will generally be below the 10 ppmv (~30 mg/NM3) recommended value for MEA, but that excursions above this value may occur. Whether or not to use alkali addition in the DCC or, if possible, in the reclaimer seems to be mainly an economic decision. SOx values are likely to be above the level required for CESAR1 and alkali addition to the DCC is likely to be required. This will also address any HCl and HF present. BREF-compliant NOx levels, 40-150 mg/Nm3 (30 – 113 ppmv) would not exceed the 20 ppmv NO2 guideline for MEA above at an assumed NO2 fraction of 10%, but they would exceed 1 ppmv of NO2 at even the lowest NOx value of 30 ppmv, notionally corresponding to 3 ppmv NO2, and reach levels where significant nitrosamine formation (3000 mg/kg in approximately 1 month with 2.35 ppmv NO2) has been observed in the TCM tests. It is not clear from public- domain evidence what level of nitrosamines could be maintained in the circulating CESAR1 by periodically using elevated temperatures (with 130oC reported in Moser, 2023) in the stripper, since absolute nitrosamine levels were not reported, just a graph showing that the level was held at some level between 50 and 100% of an unstated maximum concentration by using elevated temperatures in the reboiler for periods of 5-12 days. Because of the need to minimise the risk of aerosols in the flue gas going to any amine capture plant it is suggested that new biomass plants burning any fuel type install a baghouse rather than an ESP for particulate control and, if not included already from the outset, provisions are made to add Powdered Activated Carbon (PAC) injection and hydrated lime injection for SOx control in case they are found to be necessary to minimise aerosol carryover when the PCC plant is operated. Solvent Degradation: solvent reclaiming or cleaning In any commercial amine PCC plant the inflow and formation of impurities in the circulating solvent obviously has to be matched, in the long term, by their removal or destruction. Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 18 Absolute rates of addition and formation and the level at which techniques for solvent reclaiming or cleaning must be operated can only be determined by very long-term testing under fully-realistic conditions. But the ability of reclaiming or cleaning techniques to remove the types of impurities likely to be present is obviously extremely important and this ability is determined, to a very large extent, by the fundamental properties of the solvent amines, as will be illustrated in this section. Thermal reclaiming of MEA and CESAR1 at TCM Both MEA and CESAR1 have been thermally reclaimed at TCM, using the same equipment and similar methods. These tests constitute a major part of the realistic, public domain information on thermal reclaiming of these solvents and, even though they were not undertaken for solvents on biomass flue gases, the trends that can be inferred for relative behaviour of these two solvents are therefore valuable. General unsteady-state thermal reclaiming considerations TCM thermal reclaimer arrangement In these cases at TCM the reclaimer, arranged as shown above, is operated for a period of time while the PCC plant is running, but in such a way that the amounts of impurities in the circulating solvent are removed at a much faster rate than their rate of addition or formation (and so, to a first approximation, addition and formation during the reclaiming period can be neglected). The change of the amount of an impurity in the solvent inventory by reclaiming is then given by the formula: δC = -C/V.s. δR Where: Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 19 δC is the small amount of the impurity removed in a small solvent volume of δR flowing to the reclaimer V is the solvent inventory volume∫ s is the average selectivity for removal in the reclaimer, from 0 to 1 δR is a small solvent volume flowing to the reclaimer Expressing in integral form: ∫1/C.dC = - s/V. ∫dR And integrating: ln(C1/C2) = s.R/V or rearranging: s = ln(C1/C2) / (R/V) C2/C1 = e^(-s.R/V) Where: C1, C2 are the initial and final amounts of the impurity An alternative model is that some fraction of an impurity category has an s value of 1 (i.e. it is not returned to the PCC system, being much less volatile than the solvent constituents) and the remainder, denoted by a mass fraction x, an s value of zero (i.e. it is at least as volatile as the solvent constituents). In this case: C2 = C1.(1-x). e^(-R/V) + x.C1 Giving: x = [C2 – C1.e^(-R/V)] / [1- e^(-R/V)] Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 20 Comparison between reclaiming trends for MEA and CESAR1 at TCM and implications for thermal reclaiming effectiveness Unsteady-state thermal reclaiming with a running PCC plant have been undertaken at TCM for both MEA13 and CESAR114. The reported results and analyses for key processing variables are shown in the table below. As can be seen, in MEA reclaiming there is a high selectivity for removal of all the categories of impurities; clearly virtually none are returned to the PCC system with the vapour from the reclaimer. In CESAR1 reclaiming, however, on average ~60% of the ‘degradation products’ in the lean solvent feed to the reclaimer, about 40% of the metals and about 50% of the heat stable salts appear to be returned with the amine and water vapour each time a batch of the solvent is reclaimed. In fact, though, since none of these impurity classifications are a single species, but rather a very heterogeneous mixture, the behaviour may perhaps be better described as a combination of material with much higher (i.e. approaching 1) and much lower (approaching zero) removal selectivities, for different species. Assuming this latter model, unremovable fractions in the first TCM CESAR1 reclaiming run are 15.1% for degradation products, 3.9% for metals and 10% for HSS, rising for the first two categories to 17.1% and 6% respectively in the second reclaiming run, with unremovable HSS staying at 10%. Insufficient details are provided to confirm this hypothesis, but it might be expected that if certain species are not removed in reclaimed or subject to further degradation then would accumulate over time, as do the unremovable fractions of the degradation products and metals categories in the table below. 13 Flø, N., Faramarzi, L., de Cazenove, T., Hvidsten, O., Morken, A., Hamborg, E., Vernstad, K., Watson, G., Pedersen, S., Cents, T., Fostås, B., Shah, M., Lombardo, G. and Gjernes E. (2017) Results from MEA Degradation and Reclaiming Processes at the CO2 Technology Centre Mongstad, Energy Procedia, Volume 114, Pages 1307-1324, http://www.sciencedirect.com/science/article/pii/S1876610217321021 14 Campbell, M., Akhter, S., Knarvik, A., Muhammad, Z., and Wakaa, A. (2022) CESAR1 Solvent Degradation and Thermal Reclaiming Results from TCM Testing, Proc. 16th Greenhouse Gas Control Technologies Conference (GHGT-16), 23-24 Oct 2022. https://ssrn.com/abstract=4286150 or http://dx.doi.org/10.2139/ssrn.4286150 Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 21 Reported TCM thermal reclaiming data and estimated selectivities for removal Degradation products Metals HSS MEA reclaiming, R/V 315 Expected reduction for s=1 96.02% Oct-15 reclaiming run after 1843 hrs operation – reduction from reclaiming ~95% >95% >95% Apparent selectivity for removal (for 95%) 0.9986 0.9986 0.9986 CESAR1 reclaiming, R/V 4.5 Expected reduction for s=1 98.98% Apr-20 reclaiming run after ~1600 hrs operation – reduction from reclaiming 84% 95% 89% Apparent selectivity for removal 0.4072 0.6657 0.4905 Unremovable fraction, x 15.1% 3.9% 10.0% Oct-20 reclaiming run after ~2200 hrs operation 82% 93% 89% Apparent selectivity for removal 0.3811 0.5909 0.4905 Unremovable fraction, x 17.1% 6.0% 10.0% These reclaiming tests are the main body of information available in the open literature, but they have a number of limitations for extrapolation to any commercial plant operation: • The flue gases, and hence impurity types and amounts, will obviously be specific to that plant • The operating regime will also be specific • Very seriously, the operating period for a commercial PCC plant will be ~8000 hrs/yr and the plant is likely to be running for at least a year between major planned outages and perhaps much longer, and for likely over a decade in total – the few thousands of hours running above, although typical of pilot testing, is far too short to give a reliable prediction of even the first year’s trends Nonetheless, it appears likely that all or most of the impurities likely to be found when using MEA as a post-combustion capture solvent can be almost entirely removed by simple thermal reclaiming, whereas some fraction of the impurities found when using CESAR1 cannot. More exact conclusions and, most importantly, the implications for plant operation, would need fully representative testing for a period of 12-24 months. 15 In (Flø, 2017) it was incorrectly stated that “A total accumulated amount of 46 000 kg solvent was fed to the reclaimer during the whole period of 3 days. This corresponds to about 110 % of the total solvent inventory.” But this is inconsistent with the average flow shown in Figure 6, which averages around 2000 kg/h over 3 days, so roughly 3 x 24 x 2000 = 144 000 kg. After correspondence on the matter TCM confirmed by email that “the solvent flow to the reclaimer over the 3 days was 143 570 kg. This is 3 times the inventory.” Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 22 Moser (2023) also found similar, but probably (impurity categories are different) slightly better, results for partial removal of impurities from CESAR1 by cleaning using ion exchange and was able to run for an extended period of 40 months: Reduction of the concentrations of contaminants in the CESAR1 solvent by the application of anion and cation exchange Concentrations Fe Ni chloride nitrate sulfate formate acetate glycolate oxalate propionate [mg/kg] [mg/kg] [mg/kg] [wt.%] [wt.%] [wt.%] [wt.%] [wt.%] [wt.%] [wt.%] Before cation/anion exchange 11 4 60 0.16 0.076 0.37 0.27 0.089 0.12 0.077 After cation/anion exchange 3 0 <5 0.023 0.0054 0.061 0.036 0.005 0.0076 0.005 Reduction [%] 73 100 92 86 93 84 87 94 94 94 The same pilot plant has also used ion exchange for MEA cleaning, with apparent success although the period for testing satisfactory operation after reclaiming (approximately 100 days) had been exceeded when running fresh solvent with no reclaiming (Weir, 2023)16. Solvent reclaiming/cleaning conclusions for the use of MEA or CESAR1 It appears that MEA can be thermally reclaimed with very high rejection of all impurities. In the public-domain example cited the reclaimer was operated intermittently but in commercial plants (e.g. Pentair17, Bechtel18) it is likely that MEA reclaiming will take place continuously. The reclaimer, or at least the first stage of reclaiming, may be vented into the stripper for full energy recovery, allowing reclaiming at very high rates (e.g. up one inventory volume per week) with limited penalties on plant output. Ion exchange cleaning has been used for MEA operation but, given the efficacy of thermal reclaiming for MEA, seems unlikely to be the preferred option. CESAR1 has been operated satisfactorily for limited periods (total 3800 hours reported) with thermal reclaiming, but of the order of 10% of impurities seem unable to be removed by this method and the build-up of these compounds over the longer term is therefore a possibility. Somewhat better levels of impurity removal, but still not complete, appear to be feasible with ion exchange cleaning and longer periods of satisfactory operation (>3 years), with appreciable levels of impurities present, have been demonstrated using this method (with also some level of solvent make-up). There is a caveat here, though, in that this is at a single plant (RWE 16 Weir, H., Sanchez-Fernandez, E., Charalambous, C., Ros, J., Garcia Moretz-Sohn Monteiro, J., Skylogianni, E., Wiechers, G., Moser, P., van der Spek, M., Garcia, S. (2023) Impact of high capture rates and solvent and emission management strategies on the costs of full-scale post-combustion CO2 capture plants using long-term pilot plant data, International Journal of Greenhouse Gas Control, Volume 126. https://doi.org/10.1016/j.ijggc.2023.103914, https://www.sciencedirect.com/science/article/pii/S1750583623000841 (see also for open-access https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4144048 ) 17 https://carboncapture.pentair.com/en/solutions/cc-product-low-purity-advanced-amine-capture-plants 18 https://ukccsrc.ac.uk/open-access-sherman-feed/ Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 23 Niederaussem) and the fly ash at this plant has been demonstrated to have beneficial effects with respect to amine solvent degradation19. Solvent Degradation: acid wash for amine and degradation product emissions control General considerations As shown in the figure above, many interacting factors affect atmospheric emissions. But to prevent amine and ammonia emissions an acid wash at the absorber exit is the only tested option that will ensure very low emissions, although other measures may reduce the load on the acid wash and have some effect on exit emission levels. Acid wash test results for both MEA and CESAR1 are available, although unfortunately not on the same plant for direct comparison. Details are summarised below. MEA with acid wash For an example of an acid wash on a PCC pilot plant, for which data is available, see (Khakaria, 2014)20. TNO’s 6 tCO2/day /0.65 m diameter capture plant then in place at Maasvlakte had an acid wash column added using 1.26 m of Sulzer Mellapak 250 structured 19 Buvik, V., Vevelstad, S., Moser, P., Wiechers, G., Wanderley, R., Garcia Moretz-Sohn Monteiro, J., Knuutila, H. (2023) Degradation behaviour of fresh and pre-used ethanolamine, Carbon Capture Science & Technology, Volume 7. https://doi.org/10.1016/j.ccst.2023.100110 ; https://www.sciencedirect.com/science/article/pii/S2772656823000143 20 Khakharia, P., Huizinga, A., Lopez, C., Sanchez, C., Mercader, F., Vlugt, T. & Goetheer, E. (2014) Acid Wash Scrubbing as a Countermeasure for Ammonia Emissions from a Postcombustion CO2 Capture Plant, Ind. Eng. Chem. Res. 53, 13195−13204. https://pubs.acs.org/doi/pdf/10.1021/ie502045c Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 24 packing with a liquid distributor followed by a demister (KnitMesh - Sulzer Chemtech) to prevent carryover of droplets. The demister was capable of removing droplets of 2 μm with 96.4% efficiency, and above 10 μm with 100% efficiency. Overall increase in column height required for the acid wash was estimated to be 4.7 m for a full-size column design. Typical NH3 emissions at the water wash outlet were in the range of 15−20 mg/Nm3 under normal operation with MEA, but additional ammonia (up to 150 mg/Nm3) was added for test purposes. Experimental results showed ammonia emissions below 5 mg/Nm3 at a pH of 6 for both normal and added NH3 conditions. MEA emissions after the acid wash were in the range 1−3 mg/Nm3, mostly below 1 mg/Nm3, from water wash outlet values of 1.2−26.8 mg/Nm3 (but generally below 10 mg/Nm3). CESAR1 with an acid wash CESAR1 test data with an acid wash comes from trials at TCM21,22, using a gas turbine exhaust gas (TCM CHP flue gas). The results were compared with MEA testing that, significantly for the comparisons, did not use an acid wash. ‘Formaldehyde, acetaldehyde, and acetone concentrations were determined by extractive sampling. The data for the flue gas after the absorber are shown in the table below.’ Depleted flue gas aldehyde/ketone concentrations # Formaldehyde, mg/Sm3 Acetaldehyde, mg/Sm3 Acetone, mg/Sm3 3 0.0635 0.0931 1.14 7 0.0406 0.0596 1.42 11 0.0546 0.0801 2.85 15 0.0190 0.0279 1.13 It was noted that “Acetone levels measured during the MEA tests were sufficiently low at or below the detection limit of 1 mg/Sm3, while with CESAR-1 they were measurable at between 1–3 mg/Sm3 even though the upper water wash was configured as an acid wash for these tests and not in the MEA campaign“. 21 https://gassnova.no/app/uploads/sites/5/2022/04/10-CESAR-1-Solvent.pdf 22 Hume, S., Shah, M., Lombardo, G. and Kleppe, E. (2021) Results from CESAR-1 testing with combined heat and power (CHP) flue gas at the CO2 Technology Centre Mongstad, TCCS-11 - Trondheim Conference on CO2 Capture, Transport and Storage, Trondheim, Norway - June 21–23, 2021. https://sintef.brage.unit.no/sintef- xmlui/bitstream/handle/11250/2786512/Results%20from%20Cesar- 1%20Testing%20with%20Combined%20Heat%20and%20Power%20%28CHP%29%20Flue%20Gas%20at%20th e%20CO2%20Technology%20Centre%20Mongstad.pdf Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 25 As a partial comparison, acetaldehyde levels of about 0.3 ppmv (~0.6 mg/Sm3) were observed in operation with MEA at TCM23 when capturing from RFCC flue gas and prior to the solvent becoming heavily degraded. TCM also measured final flue gas concentrations of solvent components (AMP and PZ) along with ammonia during the CESAR1 testing, as shown below. Depleted flue gas stream ammonia and solvent component concentrations # AMP, mg/Sm3 PZ, mg/Sm3 Ammonia, mg/Sm3 4 0.06 0.01 0.04 5 0.04 <0.007 0.03 9 0.03 <0.007 0.02 13 0.03 <0.007 0.03 Comments on these results were, “The solvent components of CESAR-1 appear to show higher vapor pressure than is associated with MEA solvent, which was previously measured by an external contractor at 0.006 mg/Sm3 during testing on CHP flue gas. PZ was barely detected, only showing up in Test 4, which shows that perhaps a longer extraction sample period would help to improve determination of this species at the ppb level. It was also noted that ,”Ammonia levels are far lower than the previous MEA CHP tests results, measured at 13 mg/Sm3, suggesting that ammonia does not represent a significant degradation product of CESAR-1.” but since the MEA tests were without the acid wash this comparison is not fully evidenced. Acid Wash conclusions for the use of MEA or CESAR1 An acid wash can be used effectively with both MEA and CESAR1 and will generally reduce alkaline species, principally amines and ammonia, down to less than 1 mg/m3. Slight differences between the solvents may remain: • AMP emissions from CESAR1 may be higher than MEA or PZ emissions • NH3 emissions from MEA may be higher than from CESAR1, although typically less than 1 mg/m3 after an acid wash • Acetone, which will not react with the acid, is likely to be emitted at higher levels from CESAR1 • Acetaldehyde emissions are likely to be higher from MEA 23 Morken, A.K., Pedersen, S., Kleppe, E.R., Wisthaler, A., Vernstad, K., Ullestad, Ø., Flø, N.E., Faramarzi, L. and Hamborg, E. (2017) Degradation and Emission Results of Amine Plant Operations from MEA Testing at the CO2 Technology Centre Mongstad, Energy Procedia, Volume 114, 2017, Pages 1245-1262, https://doi.org/10.1016/j.egypro.2017.03.1379 ; http://www.sciencedirect.com/science/article/pii/S1876610217315643 Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 26 A more representative comparison between emissions from the two solvents with an acid wash would require back-to-back long term tests on the relevant flue gas that also include commercially-relevant reclaiming for each solvent. Such test data does not appear to be available in the public domain (and such tests may not have been conducted). CO2 capture rate and regeneration energy requirements Public domain capture rate and regeneration energy data for comparison between MEA and CESAR1 is taken from the following sources. These were selected because they were from experienced and well established pilot facilities, test data in the same equipment and under similar conditions was available for the other solvent, and an extensive body of data was available rather than isolated results. These TCM and RWE facilities had also intended these tests to allow a comparison between these two solvents. MEA capture rate and regeneration energy data sources A. Technology Centre Mongstad Shah, M., Lombardo, G., Fostås, B.,Benquet, C., Morken, A. and de Cazenove, T. (2018) CO2 Capture from RFCC Flue Gas with 30w% MEA at Technology Centre Mongstad, Process Optimization and Performance Comparison. 14th Greenhouse Gas Control Technologies Conference Melbourne October 21-26, 2018 (GHGT-14). https://ssrn.com/abstract=3366149 ; http://dx.doi.org/10.2139/ssrn.3366149 Shah, M., Silva, E., Gjernes, E. and Åsen, K. (2021) Cost Reduction Study for MEA based CCGT Post-Combustion CO2 Capture at Technology Center Mongstad, Proceedings of the 15th Greenhouse Gas Control Technologies Conference 15-18 March 2021. https://ssrn.com/abstract=3821061 ; http://dx.doi.org/10.2139/ssrn.3821061 B. RWE Niederaussem Pilot Plant Weir, H., Sanchez-Fernandez, E., Charalambous, C., Ros, J., Garcia Moretz-Sohn Monteiro, J., Skylogianni, E., Wiechers, G., Moser, P., van der Spek, M., Garcia, S. (2023) Impact of high capture rates and solvent and emission management strategies on the costs of full-scale post- combustion CO2 capture plants using long-term pilot plant data, International Journal of Greenhouse Gas Control, Volume 126. https://doi.org/10.1016/j.ijggc.2023.103914, https://www.sciencedirect.com/science/article/pii/S1750583623000841 (see also for open- access https://papers.ssrn.com/sol3/papers.cfm?abstract_id=4144048 ) C. National Carbon Capture Center pilot plant Morgan, R. (2017) Physical Property Modeling of Solvent-Based Carbon Capture Processes with Uncertainty Quantification and Validation with Pilot Plant Data, PhD thesis, West Virinia University. https://researchrepository.wvu.edu/etd/6262/ Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 27 CESAR1 capture rate and regeneration energy data sources A. Technology Centre Mongstad Benquet, C., Knarvik, A., Gjernes, E., Hvidsten, O., Romslo, K., and Akhter, S. (2021) First Process Results and Operational Experience with CESAR1 Solvent at TCM with High Capture Rates, (ALIGN-CCUS Project) (February 11, 2021). Proceedings of the 15th Greenhouse Gas Control Technologies Conference 15-18 March 2021. https://ssrn.com/abstract=3814712 ; http://dx.doi.org/10.2139/ssrn.3814712 Hume, S., Shah, M., Lombardo, G. and Kleppe, E. (2021) Results from CESAR-1 testing with combined heat and power (CHP) flue gas at the CO2 Technology Centre Mongstad, TCCS-11 - Trondheim Conference on CO2 Capture, Transport and Storage, Trondheim, Norway - June 21–23, 2021. https://sintef.brage.unit.no/sintef- xmlui/bitstream/handle/11250/2786512/Results%20from%20Cesar- 1%20Testing%20with%20Combined%20Heat%20and%20Power%20%28CHP%29%20Flue% 20Gas%20at%20the%20CO2%20Technology%20Centre%20Mongstad.pdf Hume, S., McMaster, B., Drageset, A., Shah, M., Kleppe, E. and Campbell, M. (2022) Results from CESAR1 Testing at the CO2 Technology Centre Mongstad. Verification of Residual Fluid Catalytic Cracker (RFCC) Baseline Results, Proceedings of the 16th Greenhouse Gas Control Technologies Conference (GHGT-16) 23-24 Oct 2022. https://ssrn.com/abstract=4280571 ; http://dx.doi.org/10.2139/ssrn.4280571 B. RWE Niederaussem Pilot Plant Weir (2023), as above for MEA Performance data and solvent degradation and management for concentrated MEA and an advanced amine blend 28 Comparison of capture rate and regeneration energy data A. Tests on TCM CHP flue gas, ~3.5-3.7% v/v CO2 The minimum flue gas temperature was 40°C with CESAR1 solvent because of precipitation at lower temperature in the absorber, while it was 30°C in MEA case. It was easy to reverse the precipitation by flushing the absorber with hot solvent at high flow rate, but this might be not optimal for a full-scale plant. The flue gas temperature strongly influences the