Search

Tests were performed in simulated flue gas streams using two fly ash samples from the electrostatic precipitators of two full-scale utility boilers. One fly ash was derived from a Powder River Basin (PRB) coal, while the other was derived from Blacksville coal (Pittsburgh No. 8 seam). The tests were performed at temperatures of 120 and 180 C under different gas compositions. Elemental mercury (Hg) streams were injected into the simulated flue gas and passed over filters (housed in a convection oven) loaded with fly ash. The Ontario Hydro method was used to determine the total amount of Hg passing through the filter as well as the percentages of elemental and oxidized Hg collected. Results indicated that substantial amounts of Hg oxidation did not occur with either fly ash, regardless of the temperature used for testing. When oxidation was observed, the magnitude of the oxidation was comparable between the two fly ashes. These results suggest that the gas matrix may be more important than the ash components with respect to the distribution of Hg species observed in gaseous effluents at coal-fired power plants.

Energy and Environmental Research Corp. (EER) under a contract from the Department of Energy is pursuing the development and demonstration of an Advanced Steel Reheating Furnace. This paper reports the results of Phase 1, Research, which has evaluated an advanced furnace concept incorporating two proven and commercialized technologies previously applied to other high temperature combustion applications: EER`s gas reburn technology (GR) for post combustion NOx control; and Air Product`s oxy-fuel enrichment air (OEA) for improved flame heat transfer in the heating zones of the furnace. The combined technologies feature greater production throughput with associated furnace efficiency improvements; lowered NOx emissions; and better control over the furnace atmosphere, whether oxidizing or reducing, leading to better control over surface finish.

To evaluate differences in the reactivity of a series of cobalt containingperovskite type catalysts for the CO oxidation reaction, a “single path” preparation route is desirable. Two such routes were tested using three precursors of BaCoO 3 , LaCoO 3 and Ba 2 CoWO 6 : namely co-precipitation and sol-gel methods.

The exhaust gas of spark ignited engines contains a hydrocarbon mixture of complex composition ranging from C 1 to C 9 molecules including alkanes, olefins, diolefins, alkynes and aromatics. It has been evidenced that among the various unsaturated, hydrocarbons, alkynes show the largest inhibiting effect on all oxido-reduction reactions occuring on a PtRh catalyst, i.e. non-alkyne hydrocarbons, CO and NO are not converted until alkynes are eliminated. A scheme based on competitive adsorption has been proposed which accounts for the effect of the nature of the hydrocarbons on their own oxidation and on CO oxidation. It has also been shown that the inhibition effect exists even, for very low C 2 H 2 concentrations, representative of real exhausts gases. Furthermore, the addition of 15 ppm SO 2 slows down C 2 H 2 oxidation, which, increases the C 2 H 2 , inhibiting effect. From these results a laboratory test has been defined, enabling the simulation of engine bench tests.

The Santa Barbara County Air Pollution Control District (SBCAPCD) has arranged a consortium to develop ultra-low emissions combustor technology applicable to gas turbines. The goal of the program is to develop and demonstrate a safe, efficient, and cost-effective method to meet a 9 ppmv NO{sub x} emission limit for gas turbines. Currently this emission limit can only be met with the selective catalytic reduction (SCR) technology (a post combustion cleanup process that is capital intensive and maintenance intensive). In coordination with a comprehensive technical advisory committee, SBCAPCD has evaluated different potential low emissions technologies and decided upon a lean premix approach to retrofit existing turbines and to integrate with new engines. This technology will provide a low cost alternative to the expensive controls and will substantially reduce NO{sub x} emissions from gas turbines. The design, fabrication and testing of the ultra-low NO{sub x} combustor system is currently being performed by Allison Gas Turbine Division, General Motors Corporation. This project continues to be overseen by a technical advisory committee to ensure timely and cost-effective product delivery.

Two representative metal–organic frameworks, Zn4O(BTB)2 (BTB3− = 1,3,5-benzenetribenzoate; MOF-177) and Mg2(dobdc) (dobdc4− = 1,4-dioxido-2,5-benzenedicarboxylate; Mg-MOF-74, CPO-27-Mg), are evaluated in detail for their potential use in post-combustion CO2 capture via temperature swing adsorption (TSA). Low-pressure single-component CO2 and N2 adsorption isotherms were measured every 10 °C from 20 to 200 °C, allowing the performance of each material to be analyzed precisely. In order to gain a more complete understanding of the separation phenomena and the thermodynamics of CO2 adsorption, the isotherms were analyzed using a variety of methods. With regard to the isosteric heat of CO2 adsorption, Mg2(dobdc) exhibits an abrupt drop at loadings approaching the saturation of the Mg2+ sites, which has significant implications for regeneration in different industrial applications. The CO2/N2 selectivities were calculated using ideal adsorbed solution theory (IAST) for MOF-177, Mg2(dobdc), and zeolite NaX, and working capacities were estimated using a simplified TSA model. Significantly, MOF-177 fails to exhibit a positive working capacity even at regeneration temperatures as high as 200 °C, while Mg2(dobdc) reaches a working capacity of 17.6 wt % at this temperature. Breakthrough simulations were also performed for the three materials, demonstrating the superior performance of Mg2(dobdc) over MOF-177 and zeolite NaX. These results show that the presence of strong CO2 adsorption sites is essential for a metal–organic framework to be of utility in post-combustion CO2 capture via a TSA process, and present a methodology for the evaluation of new metal–organic frameworks via analysis of single-component gas adsorption isotherms.

In all countries where secondary methods (applied after the formation of pollutants, i.e. post combustion control in the case of NOx) are used for the control of NOx emissions from stationary sources, processes of Selective Catalytic Reduction (SCR) play a significant role. Depending on the state of the gas to be treated by SCR, the NOx reduction is classified as a high or a low dust process. The NOx removal is called selective because the reduction chemicals should react exclusively with the pollutant. Ammonia is applied as a suitable reduction medium on a technical scale.

This paper is a review of stack gas treatment methods for the control of NOx emissions. Particular emphasis is placed on status of development and factors affecting the performance of the processes. Catalytic, noncatalytic, and scrubbing processes are compared on a uniform engineering basis. Most of the active process development work is taking place in Japan. The three leading stack gas treatment techniques for NOx control are catalytic reduction with ammonia, noncatalytic reduction with ammonia, and direct scrubbing of NO with simultaneous absorption of SO2. The wet processes are much less developed than the dry processes.

The production of halogenated aromatics has been investigated in the SAKAB hazardous waste incinerator, Norrtorp, Sweden. The measurement results show that there is a substantial net production of chlorinated aromatics in the boiler.

International audience

Substantial progress in the development of the UNO MK 3 process and it's cost reduction capabilities has been made since previously reported [1] . In particular, the recent results of two pilot plant trials of the process continue to demonstrate and confirm the major features of the UNO MK 3 process: Low overall cost (up to 50% less than the best amines) Multi-impurity capture and production of valuable by-products (no degradation products) Low energy of regeneration (less than 2.5 GJ/T CO 2 ) Low volatility and environmental impact (SOx and NOx converted to fertilizer products) A good fit with existing global potassium markets (no additional potassium required) These new results are groundbreaking in terms of advancing the process; with no major barriers evident for scaling up the process from the current pilot scale (TRL 5) to larger scale demonstration (TRL 6/7) over the next few years.

This paper discusses a methodology used to set, already at an early stage of technology development, the key performance requirements for carbon dioxide capture technologies necessary to meet a certain capture cost target. The methodology also illustrates how realistic or unrealistic cost targets can be. Although, applicable for capture technologies in general (pre-, post combustion and oxy fuel), the usefulness of the methodology is illustrated for one pre-combustion capture technology in particular i.e., Pd membranes for CO2 capture in a NGCC power plant.

A method for measuring the CO2 loading of post combustion capture solvents has been developed which first separates CO2 from the solvent by acidification of the solvent under vacuum conditions, then traps the CO2 via deposition, and finally quantifies the CO2 by pressure measurement in a calibrated volume. A preliminary comparative assessment shows that the measurement accuracy and precision of the method compares favorably to other methods currently used at post combustion capture research facilities and that there is potential for continuing development of the method for use in industrial field applications.

A quarter of the carbon dioxide emissions all over the world are exhausted from the thermal power plants. So we hav e been concentrated on the development of the low-cost CO2 capture technology. For the CO2 capture from the large amount of the flue gas, the chemical absorption method is suitable. We found an amine solvent had a good performance using thermodynamic simulation. The solvent exhibited that the CO2 recovery ratio and heat consumption for CO2 regeneration were 94% and 2.9 GJ/t-CO2 by the bench-scale test, respectively. Furthermore we will plan a 10 ton-CO2/day pilot plant using a real coal combustion gas.

A theoretical study of equilibrium constants of a series of amines and amino acids having a potential for being solvents in post combustion CO2 capture processes has been performed. Density Functional theoretical calculations at B3LYP/6-311++G (d, p) level of theory are used for studying solvation energies and gaseous phase energies. The PCM and SM8T continuum solvation models are used for studying reaction energies in solution. Potential amines and amino acids based on the qualitative comparisons are suggested for CO2 absorption in post combustion capture plants.

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.

Calcium looping (CaL) systems have been proposed as a lower-cost method of CO2 capture for power plants. This paper presents the results of a techno-economic assessment of a CaL system for post-combustion CO2 capture at a pulverized coal (PC) power plant. Comparisons are made with a conventional MEA-based CO2 capture process in terms of performance and cost. Considering the significant quantities of solid flows required for a CaL process, the applicability and operational feasibility of a CaL system for new or existing PC power plants also is studied. It was found that though the CaL system has better performance than the MEA-based CO2 capture process, the capital cost of the power plant and the cost of electricity is much higher than when the MEA-based system is used.

The paper describes experimental results obtained with CO 2 capture from a coal fired power plant in Wilhelmshaven. After giving some basic information on the power and the pilot-scale carbon capture unit, findings on stress corrosion cracking in the Reclaimer, impact of SO3 on solvent emission and energy efficiency, which can be improved by applying lean vapour recompression. The paper highlight the learnings achieved when moving from lab scale testing to pilot scale testing.

The current paper gives an overview of the complexity of solvent development for post combustion CO2 capture. Absorption rate, capacity and temperature dependence of equilibria determine energy performance in an optimized process. Degradability may sometimes prevent otherwise promising solvents from being utilized at the energetically optimal operating conditions. Cost and environmental impact are additional properties that must be fulfilled if a solvent shall be qualified for deployment at industrial scale. The paper describes the importance of a stepwise, holistic approach and the access to a range of resources, including experimental facilities, advanced analytical methods and pilot plants as important premises. The paper summarizes solvent properties in 14 criteria that must be addressed.

A metal-organic framework, UiO-66, has been evaluated as adsorbent in a post-combustion vacuum swing adsorption (VSA) process. Equilibrium isotherms of the most relevant gases (CO 2 and N 2 ) as well as breakthrough curves measured using synthetic flue gas containing 15 mol% CO 2 without and with 9 mol% water vapor are reported. Based on the breakthrough data, a six step one-column VSA cycle is designed and the effects of adsorption and CO 2 rinse times used on the CO 2 recovery and CO 2 purity are examined. With the chosen process configuration and cycle design CO 2 purities around 60% and CO 2 recoveries up to 70% are achieved. 50 cycle adsorption-desorption experiments show that the cyclic CO 2 capacity is reduced by approximately 25% in the presence of water vapor. No reduction in cyclic capacity is observed with increased cycle number; there is rather a slight increase in cyclic capacity with cycle number indicating that a cyclic steady state still not has been reached after 50 cycles.

CO2 capture using supported amine sorbents is a promising post-combustion capture technology. With regard to supported amine sorbents, the most important issues exist in the regeneration process. In this paper, various regeneration strategies including thermal regeneration in pure CO2 stream, vacuum regeneration, and steam-stripping regeneration are put forward and compared from the aspect of energy consumption. Besides, to ensure the long-term thermal and chemical stability and high working capacity, a kind of supported amine sorbent with the amine groups bonded to the support was tested and employed. As to the regeneration characteristics, the sorbent can be regenerated completely in pure CO2 and has perfect cyclic stability. Finally, one 200 kWth pilot plant was designed and constructed to demonstrate the process feasibility of continuous CO2 capture from flue gases with supported amine sorbents. The selection of the type of absorber and regenerator is discussed in detail. The pilot was evaluated for the air tightness and heat transfer issues.

With regard to the climate policy that has been adopted, the implementation of the carbon capture and storage and carbon capture and utilization technologies seems to be the unavoidable solution to reduce emissions from the energy sector. As most Polish energy is derived from coal, the government has taken steps to reduce CO2 emissions by initiating a strategic research program—“Advanced technologies for energy generation: Development of a technology for highly efficient zero-emission coal-fired power units integrated with CO2 capture.” This paper presents the results of an investigation of a process for continuous removal of CO2 from the gas stream on a laboratory unit. This study was conducted at the Institute for Chemical Processing of Coal in Zabrze, Poland. The purpose of the tests that were conducted was to establish the effect of the sorption column load on CO2 recovery and on the process regeneration heat duty. In the second part of the paper, a simple comparison of three amine solvents is presented as a part of the solvent selection process for further pilot plant tests.

A thermodynamic and economic comparison of post-combustion CO2 capture processes using aqueous solutions of piperazine (PZ) promoted potassium carbonate (K2CO3) and monoethanolamine (MEA) based on fair boundary conditions and constant assumptions using rigorous thermodynamic models is described. In contrast to a first preliminary comparison, it is shown that under the stated assumptions and considered boundary conditions, a 7 m MEA solution performs better in both thermodynamic and economic terms than aqueous solutions of K2CO3 and PZ.

In this work we have evaluated the H2O and CO2 adsorption characteristics of Lewatit VP OC 1065 in view of the potential application of solid sorbents in post combustion CO2 capture. Here we present single component adsorption isotherms for H2O and CO2 as well as co-adsorption experiments. It was concluded that the sorbent material shows a high affinity in the adsorption of H2O. The adsorption of CO2 alone does not prevent the co- adsorption of large quantities of water and additional measures are necessary to prevent this from negatively affecting the energy demand of the process.

This work presents research and development progress to improve biocatalysts, solvents, and system integration to reduce the cost of CO2 capture from flue gas. Laboratory data and field demonstration illustrate the potential of biocatalyst-enhanced CO2 capture from coal generated flue gas using non-volatile alkali salt solutions. The first generation biocatalyst system (coated packing) demonstrated 6 to 7-fold enhancement in the volumetric average mass transfer coefficient at 40 °C with 3460 hours on coal flue gas with 80% CO2 capture on average. The first 2800 hours operated with an aqueous solution of 20% K2CO3, and the final 660 hours demonstrated a new higher capacity non-volatile alkaline salt solution (AKM24). Lessons learned from the first generation biocatalyst delivery system (coated packing) demonstration are summarized. A second generation biocatalyst delivery system (biocatalyst microparticles) is introduced that shows a greater potential for rate enhancement in laboratory tests. This new biocatalyst system also provides a lower cost method of biocatalyst addition and replacement on-stream. Preliminary modeling estimates show a total equivalent work less than 220 kWh/t CO2 (including CO2 compression to 150 bar) in two possible process configurations. Preliminary cost analysis demonstrates potential for more than 30% reduction in CO2 capture costs relative to NETL Case 12, version 2 (30% MEA with 75 psig cross over steam, bituminous coal power plant).

This document introduces a generic method to calculate the thermodynamic absolute minimum energy required for the regeneration of post-combustion capture solvents for a traditional line-up. The minimum energy requirements are shown to be most dependent of: 1. Heat of absorption solvent 2. Regeneration pressure 3. Fat solvent temperature 4. Vapor pressure of CO2 over the loaded solvent at absorber bottom temperature T1. This method allows the screening of new solvents and helps to focus the research and development efforts into solvents and line-ups for CO2 capture.

Three mass transfer properties: the effective area (ae), liquid film and gas film mass transfer coefficients (kL and kG) are measured consistently for eleven packings with different surface area and corrugation angle. The effective area and liquid film mass transfer coefficient increases with liquid velocity while gas film mass transfer coefficient increases with gas velocity. The fractional effective area decreases with surface area and barely changes with corrugation angle. kL and kG increase as surface area increases or corrugation angle decreases. A new concept-mixing point density is proposed to represent the packing geometry influence on kL and kG. Correlations for ae, kL, and kG are developed including effects of gas and liquid rates and packing geometry.

The new mixed-salt technology combines the well-known ammonia and potassium carbonate technologies with improved reaction kinetics and reduced emissions. This technology is capable of capturing CO2 at high cyclic loadings compared to amine-based processes. In addition, mixed-salt technology can strip CO2 at high pressure, reducing the CO2 compression costs, requires no solvent chilling as in aqueous ammonia based processes, and has a low reboiler duty for regeneration (< 1000 Btu/lb.). Mixed-salt technology provides unique opportunities for better energy management to reduce the burden on the power plant steam cycle and is suitable for capturing CO2 from post-combustion, pre-combustion and other industrial gas streams. The mixed-salt technology has already been tested successfully in two small bench-level systems and is currently being tested at a large bench-scale pilot level with the funding from the U.S. Department of Energy (DOE). The technology can easily be scaled up with use of conventional process equipment and can be demonstrated in full scale sooner than second-generation technologies that are currently in development.

In a comparative approach, a life cycle assessment for the production phases of two different CO 2 -capture facilities was made. Amine wash facilities are currently the most discussed way to capture CO 2 in the post-combustion technology route. An equally promising competing technology uses polymeric membranes to extract CO 2 from the flue gas. Additionally to the examination of the different production processes, the results were comparatively placed into an approximate life cycle analysis. The results for the membrane facility scenarios vary broadly. All of the investigated factors (e.g. laboratory/large scale membrane production; steel usage and membrane area demand) have a significant effect on the emissions. The best case scenario with low membrane area and steel demand presents a competitive capacity to the reference amine wash case.

The Doosan Babcock, SSE and Vattenfall consortium successfully completed the two year test programme on the CCPilot100+ post combustion carbon capture (PCC) pilot plant at SSE's Ferrybridge Power Station in December 2013. The 100 tonne CO 2 /day (15MW t , 5MW e equivalent) CCPilot100+ PCC pilot plant, using Doosan Babcock's PCC technology, was the first of its size to be integrated into a live power plant in the UK. It was designed to demonstrate scale-up of the PCC process and provides a stepping stone from process characterisation on Doosan Babcock's 1 tonne CO 2 /day (160kWt) Emissions Reduction Test Facility (ERTF) to commercial-scale (150MWe plus) plant. Benchmark performance on 30% w/w monoethanolamine (MEA) solvent was first established, followed by extensive parametric and long-term performance testing using the RS-2 TM solvent. The paper presents an overview of the CCPilot100+. It describes the test programme, measurements made, test results, operating experience gained and some of the key lessons learned.

An important environmental issue for amine-based post-combustion CO 2 capture is the generation of reclaimer sludge containing degradation products and impurities that must be disposed. This paper evaluated the environmental fate of reclaimer wastes generated from three amine-based solvents (monoethanolamine, piperazine, and a methyldiethanolamine/piperazine blend) used for CO 2 capture at a pulverized coal and a natural-gas combined cycle power plant (900 and 810 MWe, respectively) with typical flue gas compositions. The solvent loss and impurities and degradation accumulation in the CO 2 capture units were modeled. A techno-economic analysis of different reclaiming technologies was conducted. The reclaimer sludge was classified based on US and EU regulations for hazardous waste, and alternative options for reclaimer sludge disposal were evaluated.

Doosan Power Systems are developing competitive Post Combustion CO 2 Capture (PCC) technologies for application on coal- and natural gas-fired power plants for commercialisation by 2020. The paper presents an overview of the UK's largest post combustion CO 2 capture plant on a coal fired power station, the CCPilot100+, giving an insight into the design and construction processes, operating experience gained during commissioning and a presentation of preliminary results from the first period of testing. Doosan Power Systems completed commissioning the CCPilot100+ plant at SSE's Ferrybridge Power Station in West Yorkshire in March 2012. The 100 t CO 2 /day (15MWt, 5MWe equivalent) CCPilot100+ PCC pilot plant is the first of its size to be integrated into a live power plant in the UK and uses Doosan Power Systems’ technology. It is designed to demonstrate scale-up of the PCC process and provides a stepping stone from process characterisation on Doosan Power Systems’ 1 t CO 2 /day (160kWt) Emissions Reduction Test Facility (ERTF) to commercial-scale (150MWe plus) plant. The experience gained during the development and operation of the ERTF PCC pilot plant has been used in both the CCPilot100+ plant design and test programme development. The project is co-funded by the project partners: SSE, Vattenfall AB, the Technology Strategy Board (TSB), the Department of Energy and Climate Change (DECC), The Northern Way and Doosan Power Systems, who were also responsible for the design and EPC project. In addition to the partners, four universities are undertaking associated research as part of the project and there is a training programme for future CCS engineers on a ‘live’ plant, creating a valuable resource for future developments. A two year test programme started in the first quarter of 2012. The test programme and long-term operation of the CCPilot100+ aim to optimise the PCC process and provide the data to develop and validate performance models. The test programme will demonstrate the capability of the process over the range of operating conditions that exist in power plant resulting from modern day electrical demand. The test programme will also assess and optimise, where possible, the performance of solvents for regeneration steam consumption, solvent degradation and materials compatibility. Auxiliary power requirements, which add to power plant parasitic losses, will be assessed and, by working with the supply chain, more efficient methods of operation can be considered and developed. Benchmark performance on 30% w/w monoethanolamine (MEA) solvent is being established first and will be followed by extensive parametric and long-term performance testing using the RS2 TM designer solvent. Optimisation and long-term testing of a next generation advanced solvent will also be conducted following the RS2 TM testing phase. The testing and verification programmes at both the CCPilot100+ and the ERTF will be used to substantiate the scalability of Doosan Power Systems’ PCC technology under real operating conditions.