Solvents For Post-combustion Capture Research Articles

Repowering Options for Complying with Canadian CO2 Emission Intensity Limits on Existing Coal Plants

The Canadian federal government has introduced carbon dioxide emission intensity limits of no greater than 420 kg/MWh net for new coal plants and existing coal plants more than 50 years of age. Many operating coal plants in Canada will be impacted by this legislation in the near future, requiring operators to plan a compliance strategy. The Canadian Clean Power Coalition (CCPC) investigated the performance and economics of a number of options for existing plants that could deliver compliant solutions. These options included strategies in which natural gas is available and some in which only coal firing is feasible due to cost or logistical issues.Repowering and post-combustion capture (PCC) options were studied using an eastern Canadian power plant firing bituminous coal. The base-case (BC) option was a new combined-cycle gas turbine (CCGT) plant, against which all other options were compared. The following cases were investigated:1.PCC using:a.Monoethanolamine MEA solvent with crossover steam regenerationb.Commercial advanced solvent with crossover steam regenerationc.Commercial advanced solvent with a small gas turbine (GT) and a low-pressure steam generatord.Commercial advanced solvent with a GT, triple-pressure heat recovery steam generator (HRSG) and a back pressure steam turbinee.Commercial advanced solvent with a natural gas boiler and a back pressure steam turbine2.Repowering of existing steam turbines with new a GT and HRSG3.Repowering of existing steam turbines with fuel cellsa.New solid oxide fuel cell (SOFC) topping unitb.New molten carbonate fuel cell (MCFC) topping unit4.Expanded PCC approach with:a.Third unit with full LP steam turbine bypass supplying steam to PCCb.Circulating fluidized bed (CFB) boiler and back pressure steam turbineOne of the issues with incorporating PCC in an existing facility is delivering the thermal regeneration energy to the PCC reboilers in an efficient and cost-effective manner. This can involve significant integration with the low-pressure stages of the steam turbine, a duty for which the turbine was not designed. Because turbine modifications (to deliver partially expanded steam to the PCC plant) can be costly and would require significant down time, alternative strategies were investigated in which the PCC facility would effectively be a “standalone” facility, with the main plant interfaces being the flue gas to be treated and some shared services.The costing analysis was carried out on the following basis: 30-year plant design life (with life-extension costs included for existing plant), 90% capacity factor for the first year cost of electricity (COE), and a coal cost of $4.73/GJ and a natural gas cost of $10.00/GJ (based on 2013 forecasted costs). Case 2 (repowering existing steam turbines with new natural gas combined-cycle plant) without any additional CO2 abatement, delivered both the lowest capital costs and cost of electricity. If the existing coal boiler plant remains operational, the lowest costs were achieved by installing a molten carbonate fuel cell (Case 3b) followed closely with an advanced solvent PCC unit with solvent regeneration thermal energy being delivered by an efficient, small, dedicated gas turbine with a triple pressure HRSG (Case 1d). Where there is no existing infrastructure to deliver natural gas, the traditional methodology of extracting crossover steam from the unit for PCC solvent regeneration proved to be the lowest-cost option.

Costs and Potential of Carbon Capture and Storage at an Integrated Steel Mill

In this study different possibilities and the feasibility of applying carbon capture at an integrated steel mill based on blast furnace process, in order to reduce carbon dioxide emissions were studied. Technologies considered for capturing of CO2 are post-combustion carbon capture (PCC) and oxygen blast furnace route (OBF). Post-combustion capture for the integrated steel mill was evaluated in an earlier study by Arasto et Al. and Tsupari et Al. [1,2]. Implications of different capture amounts, different solvents for post-combustion capture and process integration levels to the greenhouse gas balance and operation economics are compared to the steel production base case with varying costs of CO2 emission allowances. Furthermore the effect of reducing the carbon intensity of steel production on the final steel production cost is evaluated.Iron and steel industry is responsible of around 5% of the overall global CO2 emissions [3]. Steel production based on the blast furnace and basic oxygen furnace-based route is the main technology corresponding to the growth in global steel production [4] and this technology route is also the main source of CO2 emissions in the iron and steel industry.The assessment of potential and cost for carbon capture and storage in the iron and steel industry is based on a case study on Ruukki Metals Oy's steel mill in Raahe. The mill is situated on the northeastern coast of the Gulf of Bothnia. It is the largest integrated steel mill in the Nordic countries producing hot rolled steel plates and coils. It is also the largest CO2 point source in Finland emitting approximately 4 Mton of CO2/year. Raahe steel mill produces district heat for use in the town nearby as well as for use onsite for heating of the premises. The power plant is connected to the national electricity grid, and thus it is possible to buy and sell electricity across system boundary.In contrast to power plant applications of CCS, CO2 emission sources at an integrated steel mill are scattered around the industrial site and the flue gases are led to several stacks. Due to this, the capture process evaluation is much more complex and requires system level optimization. Carbon capture processes and process integration options were modeled using Aspen Plus process modeling software and the results were used to estimate CO2 emission reduction possibilities and carbon abatement costs at the integrated steel mill from an investor's point of view. Different heat integration options and heat utilization scenarios were investigated and optimized with a custom-built CC-Skynet™ economics toolkit. Heat available for solvent regeneration varies between these heat utilization scenarios and thus different capture amount are investigated depending on the heat available for solvent regeneration in different case studies. Also different technologies related to oxygen blast furnace were considered, both for oxygen production and for top gas treatment. The application of oxygen blast furnace effects directly e.g. to the coke consumption of process and power production on site, and thus a new design considering new heat and process gas integration opportunities is essential.With a whole chain approach, including CO2 capture, processing, transport and storage, results show significant reduction potential at an integrated steel mill with carbon capture technologies. Ship transportation of CO2 is considered due to the location of the installation. Results show also the cost structure and feasibility of the studied technologies. Cost breakeven points for carbon capture at an integrated steel mill, for the plant owner and costs for globally avoided emissions are calculated. The study also reveals some major technical restrictions of the application. Finally the pros and cons of the technologies are compared and the role and potential of CCS as a carbon abatement tool in the European steel industry is considered.

Post-combustion capture of CO2 at an integrated steel mill – Part I: Technical concept analysis

In this study different possibilities for applying post-combustion capture at an integrated steel mill in order to reduce carbon dioxide emissions were studied. Implications of different amounts of CO2 captured, different solvents for post-combustion capture and different heat supply options for solvent regeneration to the energy balance and greenhouse gas emissions of the steel mill are compared to that of the base case for the steel mill.The case study is based on Ruukki Metals Ltd.’s Raahe steel mill that is situated on the coast of the Gulf of Bothnia. It is the largest integrated steel mill in the Nordic countries producing hot rolled steel plates and coils. It is also the largest CO2 point source in Finland emitting approximately 4Mt/year.Carbon capture processes were modelled using Aspen Plus process modelling software and results were used to estimate the potential for reducing CO2 emissions at an integrated steel mill from a plant operator's point of view. Different heat integration options and heat utilization scenarios were investigated. The heat available for solvent regeneration varied between these heat utilization scenarios and thus partial capture of CO2 was investigated with the CO2 amount captured depending on the heat available for solvent regeneration in the different case studies.The results of the study show a significant CO2 reduction potential using CCS. Approximately 50–75% of the emissions from the site could be captured using post-combustion capture. Capturing a larger amount of emissions would be technically less feasible due to the large number of small stacks around the large, integrated steel mill site.

Tandem Mass Spectrometry Measurement of the Collision Products of Carbamate Anions Derived from CO2 Capture Sorbents: Paving the Way for Accurate Quantitation

The reaction between CO2 and aqueous amines to produce a charged carbamate product plays a crucial role in post-combustion capture chemistry when primary and secondary amines are used. In this paper, we report the low energy negative-ion CID results for several anionic carbamates derived from primary and secondary amines commonly used as post-combustion capture solvents. The study was performed using the modern equivalent of a triple quadrupole instrument equipped with a T-wave collision cell. Deuterium labeling of 2-aminoethanol (1,1,2,2,-d4-2-aminoethanol) and computations at the M06-2X/6-311++G(d,p) level were used to confirm the identity of the fragmentation products for 2-hydroxyethylcarbamate (derived from 2-aminoethanol), in particular the ions CN−, NCO− and facile neutral losses of CO2 and water; there is precedent for the latter in condensed phase isocyanate chemistry. The fragmentations of 2-hydroxyethylcarbamate were generalized for carbamate anions derived from other capture amines, including ethylenediamine, diethanolamine, and piperazine. We also report unequivocal evidence for the existence of carbamate anions derived from sterically hindered amines (Tris(2-hydroxymethyl)aminomethane and 2-methyl-2-aminopropanol). For the suite of carbamates investigated, diagnostic losses include the decarboxylation product (−CO2, 44 mass units), loss of 46 mass units and the fragments NCO− (m/z 42) and CN− (m/z 26). We also report low energy CID results for the dicarbamate dianion (−O2CNHC2H4NHCO2−) commonly encountered in CO2 capture solution utilizing ethylenediamine. Finally, we demonstrate a promising ion chromatography-MS based procedure for the separation and quantitation of aqueous anionic carbamates, which is based on the reported CID findings. The availability of accurate quantitation methods for ionic CO2 capture products could lead to dynamic operational tuning of CO2 capture-plants and, thus, cost-savings via real-time manipulation of solvent regeneration energies.Electronic supplementary materialThe online version of this article (doi:10.1007/s13361-011-0161-5) contains supplementary material, which is available to authorized users.

Modeling pilot plant results for CO2 capture by aqueous piperazine

Abstract Concentrated aqueous piperazine has been proposed as a possible evolutionary step from monoethanolamine (MEA) as a solvent for post-combustion capture. High concentration piperazine (>5 m) has volatility similar to MEA but provides CO 2 absorption rate and capacity that is almost double that of 7 m MEA. It is also more resistant to oxidative and thermal degradation and can be used up to 150 °C. In order demonstrate these benefits a one month pilot plant campaign was conducted in November 2008 at The University of Texas at Austin with 5 m, 8 m and 9 m PZ. An absorber model for concentrated PZ was developed in Aspen Plus ® RateSep™. The model was validated with the pilot plant results and served to assess the quality of the pilot plant data using the reconciliation tool in Aspen Plus ® . The model simulates the temperature profile of the absorber. Loadings are matched within 0.03 and the deviation of the removal fraction is no more than 0.03. The absorber model was used to study intercooling and determine optimum conditions for its implementation. Based on pilot plant data and model results 90% CO 2 removal can be achieved with 8 m piperazine, 9 meters of packing, and intercooling with a loading shift from 0.32 (lean) to 0.39 (rich) mol CO 2 /mol alkalinity and steam heat rate in the stripper of 148 kJ/mol CO 2 and an equivalent work of 33.6 kJ/mol CO 2

Demonstration and verification of post combustion capture using solvent scrubbing

This paper will present Doosan Power Systems’ Post Combustion Capture (PCC) development, testing and verification activities. Preliminary results from the Boundary Dam TKOTM process, RSTM solvent trial and the results from the ERTF test facility will be discussed. Doosan Power Systems is developing competitive PCC technologies to capture carbon dioxide (CO2) from coal and natural gas fired power plants for commercialization by 2020. Doosan Power Systems has licensed solvent scrubbing technology from HTC Purenergy Inc., which is based in Regina, Saskatchewan, Canada. HTC have developed an optimised Post Combustion Capture (PCC) process known as the Thermal Kinetics OptimizationTM (TKO) process which is designed to substantially reduce the energy requirements of the PCC process for the capture of CO2 from coal and natural gas fired power plants. Doosan Power Systems is currently undertaking FEED studies and preparing commercial bids for full-scale solvent scrubbing plants, comprising all equipment from flue gas desulphurisation (FGD) plant outlet to CO2 compression plant inlet. Among these are the CCPILOT100+ and Basin Electric PCC demonstration projects. The TKO process is currently under a formal technology verification programme at the upgraded Boundary Dam demonstration pilot plant capturing approximately 4 tonnes/day of CO2. Long term performance of HTC’s proprietary RSTM solvent is currently being assessed for CO2 removal effectiveness and the long term performance of the solvent. Solvents are also tested for degradation, heat stable salt formation and propensity for corrosion within the various system components. Doosan Power Systems has installed a PCC solvent scrubbing pilot plant on the 160 kWt Emissions Reduction Test Facility (ERTF), located at its R&D centre in Renfrew, Scotland, to capture approximately 1 tonne/day of CO2 and to permit further development and optimization of the process. The ERTF is capable of firing a wide range of world traded coals and produces flue gases representative of full scale plant. The ERTF solvent scrubbing plant will be used to carry out performance testing on a range of solvents, packings and suitability of a range of materials. The testing and verification programmes at both Boundary Dam and the ERTF will be used to substantiate the scalability of HTC’s technology under real-world operating conditions. Of paramount importance during the verification programmes are the actual rate of solvent degradation under industrial conditions, solvent make-up requirements, steam consumption and other auxiliary power requirements which add to power plant parasitic losses, such as that for fans to overcome the pressure drop created by column internals and associated pipework.

A Carbon-13 NMR Study of Carbon Dioxide Absorption and Desorption with Aqueous Amine Solutions

Abstract Quantitative 13C NMR spectroscopy was used to study the reaction of CO2 with aqueous amines. A number of structurally different amines were studied using this method to investigate their CO2 absorption and desorption under different reaction conditions. The results demonstrate that this method is easily applicable to both CO2 absorption and desorption with aqueous amines solutions. The study showed that this technique can be used to investigate the reaction mechanism of amine solvents with CO2, and also give their absorption and desorption capacities. The easy application of this method to monitor speciation of the amine- H2O–CO2 reaction system makes it a useful tool in the development of new amine solvents for post combustion capture (PCC).