Oxyfuel boiler design in a lignite-fired power plant

In the context of CO₂ capture and storage, the oxyfuel technology provides a promising option applicable in centralised power production schemes. This technology is based on combustion with pure oxygen instead of air and the flue gas mainly consists of CO₂ and H₂O. The work presented in this paper is focused in the application of the oxyfuel technology in a lignite-fired power plant. Significant design issues are the required extended flue gas recirculation in order to provide the ballasting effect of the absent N₂ and moderate the furnace temperatures. Therefore, a modified design of heat exchange surfaces of the oxyfuel steam boiler was formulated and was compared to a conventional air-fired boiler. A typical modern Greek air-fired power plant has been used as reference. The dominating factors that affect the dimensioning of the oxyfuel boiler are the higher radiative heat transfer - due to the high concentrations of CO₂ and H₂O in the flue gas - and the different flue gas mass flow, compared to a conventional air-fired boiler. For the determination of the thermodynamic cycle characteristics, simulations were made with the use of a thermodynamic cycle calculation software [Stamatelopoulos GN. Calculation and optimisation of power plant thermodynamic cycles, VDI-Regulations, Series 6, Nr. 340. Braunchweig, Mechanical Engineering Department; 1996 [in German]].     

Partial O2-fired coal power plant with post-combustion CO2 capture: A retrofitting option for CO2 capture ready plants

In the work presented in this paper, an alternative process concept that can be applied as retrofitting option in coal-fired power plants for CO₂ capture is examined. The proposed concept is based on the combination of two fundamental CO₂ capture technologies, the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. A 330 MW_el Greek lignite-fired power plant and a typical 600 MW_el hard coal plant have been examined for the process simulations. In a retrofit application of the ECO-Scrub technology, the existing power plant modifications are dominated by techno-economic restrictions regarding the boiler and the steam turbine islands. Heat integration from processes (air separation, CO₂ compression and purification and the flue gas treatment) can result in reduced energy and efficiency penalties. In the context of this work, heat integration options are illustrated and main results from thermodynamic simulations dealing with the most important features of the power plant with CO₂ capture are presented for both reference and retrofit case, providing a comparative view on the power plant net efficiency and energy consumptions for CO₂ capture. The operational characteristics as well as the main figures and diagrams of the plant’s heat balances are included.     

Factors affecting coal particle ignition under oxyfuel combustion atmospheres

A set of 13 coals of different rank has been tested for ignition propensity in a 20-L explosion chamber simulating oxyfuel combustion gas conditions. Their char residues were also analysed thermogravimetrically. The effects of coal type, coal concentration (from 100 to 600 g/m³), O₂ in CO₂ atmospheres (up to 40% v/v) and particle size were investigated.The higher rank coals were significantly more difficult to ignite and mostly required higher energy chemical igniters (1000 or 2500 J) whereas the lower rank coals could be ignited with a 500 J igniter even at low coal dust concentrations.The minimum explosibility limit/ignition concentration in air varied slightly around a value of 200 g/m³, a little higher for low volatile coals and a little lower for high volatile coals.The ignition limit changed significantly, however, with O₂ concentration in CO₂, where coals required more oxygen to ignite. Most coals failed to ignite at all in 21% v/v O₂ in CO₂, but an increase to 30 or 35% v/v O₂ gave ignition patterns similar to those in air. In addition, the minimum ignition concentration decreased with increase in O₂. However, a further increase to 40% v/v O₂ did not generally affect the minimum ignition concentration.Particle size had a non-linear effect on coal ignition. The fine particles (<53 μm) behaved almost identical to the whole coal. However, the larger size fraction (>53 μm) was generally more difficult to ignite and exhibited a much lower weight loss.     

Combustion characteristics of lignite-fired oxy-fuel flames

This experimental work describes the combustion characteristics of lignite-fired oxy-fuel flames, in terms of temperature distribution, gas composition (O₂, CO₂, CO, total hydrocarbon concentration and NO) and ignition behaviour. The aim is to evaluate the flame structure of three oxy-fuel cases (obtained by changing the flue gas recycle rate) including a comparison with an air-fired reference case. Measurements were performed in Chalmers 100 kW test unit, which facilitates oxy-fuel combustion under flue gas recycling conditions. Temperature, O₂ and CO concentration profiles and images of the flames indicate that earlier ignition and more intense combustion with higher peak temperatures follow from reduction of the recycle rate during oxy-fuel operation. This is mostly due to higher O₂ concentration in the feed gas, reduced cooling from the recycled flue gas, and change in flow patterns between the cases. The air case and the oxy-fuel case with the highest recycle rate were most sensitive to changes in overall stoichiometry. Despite significant differences in local CO concentration between the cases, the stack concentrations of CO are comparable. Hence, limiting CO emissions from oxy-fuel combustion is not more challenging than during air-firing. The NO emission, as shown previously, was significantly reduced by flue gas recycling.     

An overview on oxyfuel coal combustion—State of the art research and technology development

Oxyfuel combustion is seen as one of the major options for CO₂ capture for future clean coal technologies. The paper provides an overview on research activities and technology development through a fundamental research underpinning the Australia/Japan Oxyfuel Feasibility Project. Studies on oxyfuel combustion on a pilot-scale furnace and a laboratory scale drop tube furnace are presented and compared with computational fluid dynamics (CFD) predictions. The research has made several contributions to current knowledge, including; comprehensive assessment on oxyfuel combustion in a pilot-scale oxyfuel furnace, modifying the design criterion for an oxy retrofit by matching heat transfer, a new 4-grey gas model which accurately predicts emissivity of the gases in oxy-fired furnaces has been developed for furnace modelling, the first measurements of coal reactivity comparisons in air and oxyfuel at laboratory and pilot-scale; and predictions of observed delays in flame ignition in oxy-firing.     

Competitiveness of CO2 capture from an industrial solid oxide fuel cell combined heat and power system in the early stage of market introduction

In this article, it was investigated whether potentially low-cost CO₂ capture from SOFC systems could enhance the penetration of SOFC in the energy market in a highly carbon-constrained society in the mid-term future (up to year 2025). The application of 5 MWe SOFC systems for industrial combined heat and power (CHP) generation was considered. For CO₂ capture, oxyfuel combustion of anode off-gas using commercially available technologies was selected. Gas turbine (GT-) CHP plant was considered to be the reference case.Technical results showed that despite the energy penalties due to CO₂ capture and compression, net electrical and heat efficiencies were nearly identical with or without CO₂ capture. This was due to higher heat recovery efficiency by separating SOFC off-gas streams for CO₂ capture. However, CO₂ capture significantly increased the required SOFC and heat exchanger areas.Economic results showed that for above 40-50 $ t⁻¹ CO₂ price, SOFC-CHP systems were more economical when equipped with CO₂ capture. CO₂ capture also enabled SOFC-CHP to compete with GT-CHP at higher cell stack production costs. At zero CO₂ price, cell stack production cost had to be as low as 140 kW⁻¹ for SOFC-CHP to outperform GT-CHP. At 100 $ t⁻¹ CO₂ price, the cell stack production cost requirement raised to 350 $ kW⁻¹. With CO₂ capture, SOFC-CHP still outperformed GT-CHP at a significantly higher cell stack production cost above 900 $ kW⁻¹.     

Initial evaluation of the impact of post-combustion capture of carbon dioxide on supercritical pulverised coal power plant part load performance

Pulverised coal-fired plants often play an important role in electricity grids as mid-merit plants that can operate flexibly in response to changes in supply and demand. As a consequence, these plants are required to operate over a wide output range. This paper presents an initial evaluation of some potential impacts of adding post-combustion CO₂ capture on the part load performance of pulverised coal-fired plants. Preliminary results for ideal cases analysed using a simple high-level model indicate that post-combustion CO₂ capture could increase the options available to power plant operators. In particular, solvent storage could allow higher effective plant load factors to be achieved to assist with capital recovery while still permitting flexible operation for grid support. A number of areas for more detailed analysis are identified.     

Techno-economic evaluation of a PVAm CO2-selective membrane in an IGCC power plant with CO2 capture

Published data for an operating power plant, the ELCOGAS 315 MWe Puertollano plant, has been used as a basis for the simulation of an integrated gasification combined cycle process with CO₂ capture. This incorporated a fixed site carrier polyvinylamine membrane to separate the CO₂ from a CO-shifted syngas stream. It appears that the modified process, using a sour shift catalyst prior to sulphur removal, could achieve greater than 85% CO₂ recovery at 95 vol% purity. The efficiency penalty for such a process would be approximately 10% points, including CO₂ compression. A modified plant with CO₂ capture and compression was calculated to cost €2320/kW, producing electricity at a cost of 7.6 € cents/kWh and a CO₂ avoidance cost of about €40/tonne CO₂.     

Impact of liquid absorption process development on the costs of post-combustion capture in Australian coal-fired power stations

Australian power generators produce approximately 170 TWh per annum of electricity using black and brown coals that accounts for 170 Mtonne of CO₂ emissions per annum or over 40% of anthropogenic CO₂ emissions in Australia. This paper describes the results of a techno-economic evaluation of liquid absorption based post-combustion capture (PCC) processes for both existing and new pulverised coal-fired power stations in Australia. The overall process designs incorporate both the case with continuous capture and the case with the flexibility to switch a CO₂ capture plant on or off depending upon the demand and market price for electricity, and addresses the impact of the presently limited emission controls on the process cost. The techno-economic evaluation includes both air and water cooled power and CO₂ capture plants, resulting in cost of power generation for the situations without and with PCC. Whilst existing power plants in Australia are all water cooled sub-critical designs, the new power plants are deemed to range from supercritical single reheat to ultra-supercritical double reheat designs, with a preference for air-cooling. The process evaluation also includes a detailed sensitivity analysis of the thermodynamic properties of liquid absorbent for CO₂ on the overall costs. The results show that for a meaningful decrease in the efficiency and cost penalties associated with the post combustion CO₂ capture, a novel liquid sorbent will need to have heat of absorption/desorption, sensible heat and heat of vaporisation around 50% less in comparison with 30% (w/w) aqueous MEA solvent. It also shows that the impact of the capital costs of PCC processes is quite large on the added cost of generation. The results can be used to prioritise PCC research in an Australian context.     

Comparative assessment of sub-critical versus advanced super-critical oxyfuel fired PF boilers with CO2 sequestration facilities

This work focuses on the techno-economic assessment of bituminous coal fired sub- and super-critical pulverised fuel boilers from an oxyfuel based CO₂ capture point of view. At the initial stage, two conventional power plants with a nominal power output of above 600 MWe based on the above steam cycles are designed, simulated and optimised. Built upon these technologies, CO₂ capture facilities are incorporated within the base plants resulting in a nominal power output of 500 MWe. In this manner, some sensible heat generated in the air separation unit and the CO₂ capture train can be redirected to the steam cycle resulting in a higher plant efficiency. The simulation results of conventional sub- and super-critical plants are compared with their CO₂ capture counterparts to disclose the effect of sequestration on the overall system performance attributes. This systematic approach allows the investigation of the effects of the CO₂ capture on both cycles. In the literature, super-critical plants are often considered for a CO₂ capture option. These, however, are not based on a systematic evaluation of these technologies and concentrate mainly on one or two key features. In this work several techno-economic plant attributes such as the fuel consumptions, the utility usages, the plant performance parameters as well as the specific CO₂ generation and capture rates are calculated and weighed against each other. Finally, an economic evaluation of the system is conducted along with sensitivity analyses in connection with some key features such as discounted cash flow rates, capital investments and plant efficiencies as well as fuel and operating costs.     

Experimental programme in CIUDEN's CO2 capture technology development plant for power generation

Energy projections made by the World Energy Council, the International Energy Agency (IEA) and the US Energy Information Administration give similar pictures of the dominant role of fossil fuel in the future primary energy global demand and the necessity of incorporating CCS Technologies as part of the portfolio of solutions to reach the target world emission reduction in the coming years. Without CCS, CO₂ emission levels by 2050 are expected to increase by 70%.One of the most relevant initiatives for the deployment of CCS technologies is promoted by the Spanish Government through the institution Fundacion Ciudad de la Energia (CIUDEN). CIUDEN is developing a complete programme focusing on the development of CCT and CCS technologies in Europe.CIUDEN's CO₂ capture programme includes the construction and operation of a Technology Development Plant (TDP) in NW Spain (El Bierzo). The construction of the installation started in November 2008 and incorporates the following technologies: fuel preparation system, pulverised coal boiler (20 MWth), circulating fluidized bed boiler (30 MWth), biomass gasifier (3 MWth), flue gas cleaning train for NO_x, dust and SO_x, and CO₂ processing unit.This paper describes CIUDEN's TDP for CO₂ capture, focusing on the particularities of the installation and design, and especially on the PC unit and equipment required for its operation. The experimental programme currently under way is also described.Results are expected to be an extraordinary advance in the development and strengthening of CCT and CCS technologies, particularly oxycombustion.     

A NGCC power plant with a CO2 post-combustion capture option. Optimal economics for different generation/capture goals

Fossil fuel power plants are one of the major sources of electricity generation, although invariably release greenhouse gases. Due to international treaties and countries regulations, CO₂ emissions reduction is increasingly becoming key in the generators’ economics. NGCC power plants constitute a widely used generation technology, from which CO₂ capture through a post-combustion and MEA absorption option constitutes a technological challenge due to the low concentration of pollutants in the flue gas and the high energy requirements of the sequestration process.     

Results from trialling aqueous NH3 based post-combustion capture in a pilot plant at Munmorah power station: Absorption

Australia's Commonwealth Scientific and Industrial Research Organization (CSIRO) and Delta Electricity have developed, commissioned and operated an A$7 million aqueous NH₃ based post-combustion capture (PCC) pilot plant at the Munmorah black coal fired power station in Australia. The results from the pilot plant trials will be used to address the gap in know-how on application of aqueous NH₃ for post-combustion capture of CO₂ and other pollutants in the flue gas and explore the potential of the NH₃ process for application in the Australia power sector. This paper is one of a series of publications to report and discuss the experimental results obtained from the pilot plant trials and primarily focuses on the absorption section.The pilot plant trials have confirmed the technical feasibility of the NH₃ based capture process. CO₂ removal efficiency of more than 85% can be achieved even with low NH₃ content of up to 6 wt%. The NH₃ process is effective for SO₂ but not for NO in the flue gas. More than 95% of SO₂ in the flue gas is removed in the pre-treatment column using NH₃. The mass transfer coefficients for CO₂ in the absorber as functions of CO₂ loading and NH₃ concentration have been obtained based on pilot plant data.     

An economic feasibility study of O2/CO2 recycle combustion technology based on existing coal-fired power plants in China

In order to reduce the CO₂ emission from the coal-fired power plants, O₂/CO₂ recycle combustion (Oxy-combustion) technique has been proposed through combining a conventional combustion process with a cryogenic air separation process. The technique is capable of enriching CO₂ concentration and then allowing CO₂ sequestration in an efficient and energy-saving way. Taking into account the CO₂ taxation and CO₂ sale, the paper evaluates the economic feasibility of Oxy-combustion plants retrofitted from two typical existing conventional coal-fired power plants (with capacities of 2 × 300 MW and 2 × 600 MW, respectively) with Chinese data. The cost of electricity (COE) and the CO₂ avoidance cost (CAC) are also considered in the evaluation. The COE of the retrofitted Oxy-combustion plant is nearly the same as that of the corresponding conventional plant if the unit price of CO₂ sale reaches 17-22 $/t (different cases). The CAC of the retrofitted 2 × 300 MW Oxy-combustion plant is 1-3 $/t bigger than that of the retrofitted 2 × 600 MW Oxy-combustion plant. Supercritical plants are more economical and appropriate for Oxy-combustion retrofit. The result indicates that Oxy-combustion technique is not only feasible for CO₂ emission control based on existing power plants but is also cost-effective.     

High-pressure sorption isotherms and sorption kinetics of CH4 and CO2 on coals

Using a manometric experimental setup, high-pressure sorption measurements with CH₄ and CO₂ were performed on three Chinese coal samples of different rank (VR_r = 0.53%, 1.20%, and 3.86%). The experiments were conducted at 35, 45, and 55 °C with pressures up to 25 MPa on the 0.354-1 mm particle fraction in the dry state. The objective of this study was to explore the accuracy and reproducibility of the manometric method in the pressure and temperature range relevant for potential coalbed methane (CBM) and CO₂-enhanced CBM (CO₂-ECBM) activities (P > 8 MPa, T > 35 °C). Maximum experimental errors were estimated using the Gauss error propagation theorem, and reproducibility tests of the high-pressure sorption measurements for CH₄ and CO₂ were performed. Further, the experimental data presented here was used to explicitly study the CO₂ sorption behaviour of Chinese coal samples in the elevated pressure range (up to 25 MPa) and the effects of temperature on supercritical CO₂ sorption isotherms.The experiments provided characteristic excess sorption isotherms which, in the case of CO₂ exhibit a maximum around the critical pressure and then decline and level out towards a constant value. The results of these manometric tests are consistent with those of previous gravimetric sorption studies and corroborate a crossover of the 35, 45, and 55 °C CO₂ excess sorption isotherms in the high-pressure range. The measurement range could be extended, however, to significantly higher pressures. The excess sorption isotherms tend to converge, indicating that the temperature dependence of CO₂ excess sorption on coals at high-pressures (>20 MPa) becomes marginal. Further, all CO₂ high-pressure isotherms measured in this study were approximated by a three-parameter excess sorption function with special consideration of the density ratio of the “free” phase and the sorbed phase. This function provided a good representation of the experimental data.The maximum excess sorption capacity of the three coal samples for methane ranged from 0.8 to 1.6 mmol/g (dry, ash-free) and increased from medium volatile bituminous to subbituminous to anthracite. The medium volatile bituminous coal also exhibited the lowest overall excess sorption capacity for CO₂. However, the subbituminous coal was found to have the highest CO₂ sorption capacity of the three samples. The mass fraction of adsorbed substance as a function of time recorded during the first pressure step was used to analyze the kinetics of CH₄ and CO₂ sorption on the coal samples. CO₂ sorption proceeds more rapidly than CH₄ sorption on the anthracite and the medium volatile bituminous coal. For the subbituminous coal, methane sorption is initially faster, but during the final stage of the measurement CO₂ sorption approaches the equilibrium value more rapidly than methane.     

Dynamic modelling of CO2 absorption for post combustion capture in coal-fired power plants

Power generation from fossil fuel-fired power plants is the largest single source of CO₂ emissions. Post combustion capture via chemical absorption is viewed as the most mature CO₂ capture technique. This paper presents a study of the post combustion CO₂ capture with monoethanolamine (MEA) based on dynamic modelling of the process. The aims of the project were to compare two different approaches (the equilibrium-based approach versus the rate-based approach) in modelling the absorber dynamically and to understand the dynamic behaviour of the absorber during part load operation and with disturbances from the stripper. A powerful modelling and simulation tool gPROMS was chosen to implement the proposed work. The study indicates that the rate-based model gives a better prediction of the chemical absorption process than the equilibrium-based model. The dynamic simulation of the absorber indicates normal absorber column operation could be maintained during part load operation by maintaining the ratio of the flow rates of the lean solvent and flue gas to the absorber. Disturbances in the CO₂ loading of the lean solvent to the absorber significantly affect absorber performance. Further work will extend the dynamic modelling to the stripper for whole plant analysis.     

Changes in pore structure of anthracite coal associated with CO2 sequestration process

Pore structure changing of coal during the CO₂ geo-sequestration is one of the key issues that affect the sequestration process significantly. To address this problem, the CO₂ sequestration process in an anthracite coal was replicated using a supercritical CO₂ (ScCO₂) reactor. Different coal grain sizes were exposed to ScCO₂ and water at around 40 °C and 9.8 MPa for 72 h. Helium pycnometer and mercury porosimetry provide the density, pore size distribution and porosity of the coal before and after the ScCO₂ treatment. The results show that after exposure to the ScCO₂-H₂O reaction, part of the carbonate minerals were dissolved and flushed away by water which made the true density increased as well as total pore volume and porosity most importantly in the micro-pore range. Hysteresis between mercury intrusion and extrusion was observed. Ink bottle shaped pores can be either damaged or created compared with the ScCO₂ treated coal samples. This suggests that the ScCO₂ treatment most likely increase the volumes of pores in anthracite coal, which also contributed to the increase in porosity of the treated samples. Therefore the CO₂ sequestration into coal appears to have the potential to increase significantly the anthracite microporosity which is very advantageous for CO₂ storage.     

Morphology and chemistry of fine particles emitted from a Canadian coal-fired power plant

Particles emitted from coal-fired power plants burning subbituminous coal from Alberta, Canada were examined for total particulates (PM) and size fractions PM_>10, PM₁₀, and PM_2.5. The sampling was carried out following EPA Method 201A. Three tests were performed at each station. The emitted particles were examined using SEM/EDX and gravimetric method for the determination of their sizes. The elemental composition of particles was determined using INAA and ICP-MS.The particles emitted from the stack are classified based on their morphologies and chemistries to the following: unburnt carbon, feed-coal minerals such as quartz, and by-products of the dissociation, fractionation, and contamination by minerals in coal.The emitted particles are mostly spherical and their matrices are composed of aluminosilicate minerals containing calcium. The PM_>10 fraction contains small plerospheres, fragments of char, and angular quartz and feldspar particles. The PM₁₀ fraction contains solid spheres and cenospheres, gypsum needles, and particles of char. The PM_2.5 particle size fraction is mostly composed of solid spherical aluminosilicates with some surface enrichment of elements such as Ba, Ca, and Fe.The composition of emitted particles is ferrocalsialic. Most elements in the particle size fractions are Class I or II, such as Al, Ca, and Fe. Cd, Cu, Mo, and Ti were only detected in PM_2.5 fraction.     

Sorbent attrition in a carbonation/calcination pilot plant for capturing CO2 from flue gases

There is increasing interest in CO₂ looping cycles that involve the repeated calcination and carbonation of the sorbent as a way to capture CO₂ from flue gases during the carbonation step and the generation of a pure stream of CO₂ in the oxyfired calcination step. In particular, attrition of the material in these interconnected fluidized bed reactors is a problem of general concern. Attrition of limestone derived materials has been studied in fluidized bed systems by numerous authors. In this work, we have investigated the attrition of two limestones used in a system of two interconnected circulating fluidized bed reactors operating in continuous mode as carbonation and calciner reactors. We observed a rapid initial attrition of both limestones during the calcination step which was then followed by a highly stable period (up to 140 h of added circulation for one of the limestones) during which particle size changes were negligible. This is consistent with previous observations of attrition in other systems that employ these materials. However, a comparison of the attrition model constants with the data reported in the literature showed the two limestones to be particularly fragile during the initial calcination and the first few hours of circulation. Thus, a careful choice of limestone based on its attrition properties must be taken into account in designing future carbonate looping systems.     

电厂烟气氨法脱碳技术研究进展

随着“后京都时代”的到来,电厂烟气氨法脱碳技术成为近年来新兴的CO₂减排方法研究热点之一。本文对国内外有关氨法脱碳的机理、主要工艺和参数等的相关研究给予了详细的总结与分析,并对存在的问题和技术未来发展等方面进行了阐述。现有试验及系统模拟结果表明,氨法脱碳技术可实现90%以上的CO₂脱除效率,氨水溶液具有1.0 kg CO₂/kg NH₃以上的吸收能力;其中,CO₂脱除效率、吸收能力及速率等参数主要受氨水浓度、吸收反应温度、吸收剂再生条件等因素影响。经济性研究显示,氨法联合脱除技术有望将CO₂捕获带来的电价增长控制在20%以内。