Journal of Environmental Protection and Ecology 11, No 1, 284–293 (2010) Clean technologies
Novel technology of coal biomass co-combustion with CO2 capture D. Cebruceana, I. Ionela*, T. Panaitb ‘Politehnica’ University of Timisoara, 1 M. Viteazu Blvd., 300 222 Timisoara, Romania b ‘Dunarea de Jos’ University of Galati, 47 Domneasca Street, 800 008 Galati, Romania E-mail:
[email protected];
[email protected] a
Abstract. Since the beginning of industrialisation, the concentration of CO2 in the atmosphere has significantly increased, over 30%. The major source of the emitted emissions of CO2 is the combustion of fossil fuels. Especially huge amounts of CO2 are generated from coal-fired power plants, more than 7 billion t of CO2 annually. One of the key approaches in reducing the further increase of CO2 emissions from coal-fired power plants consists of two options: first, simultaneous combustion of biomass with coal, and second, introduction of CO2 capture technologies. Using biomass for energy purposes leads to a number of social, economical and environmental benefits. Additionally, biomass is considered a CO2 neutral, with low sulphur and nitrogen contents. In this study the absorption of CO2 into an aqueous solution of monoethanolamine was experimentally studied. Aqueous monoethanolamine has been selected for removing CO2 from the combustion gases (35 wt. % MEA). Co-firing process of biomass with coal in fluidised bed is briefly introduced. Flue gas desulphurisation is achieved in a wet scrubber column. The SO2 scrubbing liquid was an aqueous solution of sodium hydroxide of 1 and 2 wt. %. Keywords: biomass co-cofiring, fluidised bed, CO2 separation, monoethanolamine, flue gas cleaning.
Aims and background Carbon dioxide is probably the most important of the greenhouse gases as it accounts for the largest proportion of the trace gases and is currently responsible for 61% of the enhanced greenhouse effect1–3. More than 27 billion t of carbon dioxide are annually emitted from existing fossil fuel sources worldwide. Today fossil fuels account more than 80% of energy demand: coal (25%), oil (35%), natural gas (21%), nuclear (6.3%), hydro (2.2%), and biomass and waste (10%). Only 0.5% of global energy demand is met by geothermal, solar and wind1. The International Energy Agency in its World Energy Outlook Reports indicates that fossil fuels will be the dominant source of energy until 2030 and very likely for some time beyond then. As a consequence of the *
For correspondence.
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growing world primary energy demand (i.e. 16.5 Gtoe by 2030), the emissions of CO2 will reach 38.2 Gt (Ref. 2). More than one-third of the increase will come from the power generation sector (Fig. 1).
Fig. 1. World CO2 emissions from different sectors according to Reference Scenario projections2
Among the types of fossil fuel used, coal has the highest carbon content, resulting in coal-fired power plants having the highest output rate of CO2 per kW/h produced. Table 1 shows the amount of CO2 emitted by different power plants. It is obvious that coal-based technologies are currently the biggest sources of anthropogenic CO2 emissions to the atmosphere. Whereas, natural gas-fired power plants have the lowest CO2 emissions, this is mainly because of the low carbon content of natural gas and the high efficiency of the plants themselves. Table 1. Power plants CO2 emissions2
Power generation technology Conventional coal Supercritical Ultra supercritical Pressurised fluidised bed combustion Integrated gasification combined cycle Combined cycle gas turbine
CO2 emissions (g/kW/h) 900–950 790–820 750–790 790–850 740–790 350–380
There are a number of options to reduce the CO2 emissions from fossil-fuelled power plants. Probably, one of the key approaches in reducing the further increase of CO2 would be the use of carbon-free energy sources, or switching to lower CO2emitting fuels. Biomass integrates perfectly to this category. It is a renewable energy source and is considered as CO2-neutral. Moreover, most biomass fuels contain little sulphur and thus the emissions of SO2 are low. Biomass co-combustion with coal will subsequently decrease the emissions of carbon dioxide, sulphur dioxide and in some cases nitrogen oxides4–7. 285
In this study: the absorption of CO2 into an aqueous solution of monoethanolamine was experimentally studied. Chemical absorption process is theoretically described. Aqueous monoethanolamine has been selected for removing CO2 from the combustion gases (35 wt.% MEA). Co-firing process of biomass with coal in fluidised bed is briefly introduced. Additionally, a flue gas desulphurisation method is presented and studied. The SO2 scrubbing liquid was an aqueous solution of sodium hydroxide of 1 and 2 wt.%. Utilisation of biomass in small quantities may not affect the combustion process, concluding that up to 10 mass.% of biomass can be easily added to conventional systems without major investments. A block diagram of the experimental scheme for studying the process of co-firing biomass with coal in a fluidised bed combustor, and flue gas cleaning is shown in Fig. 2.
Fig. 2. Biomass co-firing with coal in fluidised bed combustion and flue gas treatment processes, including ash removal, denitrification and desulphurisation, and carbon dioxide capture
Experimental Fuel mix. The fuels that were used during the co-firing tests included a sort of lignite from the Motru coal field and waste biomass. The characteristics of coal and experimented woody biomass are given in Table 2. Beech sawdust was mostly used and also the present results are mainly accomplished with this quality of waste biomass. Table 2. Coal and woody biomass characteristics
Characteristics
Coal*
Volatile matter (mass.%) Moisture (mass.%) Ash (mass.%) Carbon (mass.%) Hydrogen (mass.%) Sulphur (mass. %) Oxygen + nitrogen (mass.%, by difference) Higher heating value (MJ/kg) in reference to air dried sample Lower heating value (MJ/kg) in reference to air dried sample * Co-fired fuels and subject of the present paper.
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26.4 24.3 32.0 24.8 2.45 0.54 15.9 10.8
beech* 72.5 19.2 1.6 28.7 4.94 0.17 44.6 16.2
Biomass fir 75.1 9.5 0.1 45.1 5.65 0.16 39.5 17.8
oak 74.1 8.8 3.2 43.2 5.8 0.1 39.0 17.4
9.7
14.6
16.3
15.9
Prior to combustion, the coal was crushed and minced to a particle size of 2 mm (and less). The sawdust was passed trough a sieve in order to retain pieces larger than 4 mm in size. Experimental setup and procedure. Biomass-coal co-firing tests were carried out on an experimental lab facility for co-firing solid fuels in fluidised bed. The combustor has a cylindrical shape (lower combustor 205 mm in diameter and upper combustor is 255 mm) having an overall height of 900 mm. Its exterior was well isolated with ceramic fibres. The furnace was pre-heated with natural gas, when the temperature of the bed reached around 300ºC the feeding of the fuel mix was started. Fuel mix was supplied to a height of 100 mm above the air distribution plate. The temperature in the combustion zone was maintained relatively constant in the range 700–900ºC. At these temperatures no atmospheric nitrogen is converted to NOx and only a small percentage of the fuel mix nitrogen is converted. Hot combustion gases were passed through a counter-current heat exchanger, decreasing the flue gas temperature to ~300ºC. Then gases enter tangentially the cyclone, where particles of fine ash (fly ash, dust) are being separated and the treated flue gas was sent to another heat exchanger, desorber. During operation the bottom coarse ash from the furnace and heat exchanger as well as the fine particles of ash from the cyclone were collected for further verification. Separation of sulphur dioxide and carbon dioxide from the flue gas was carried out in vertical, cylindrical columns of 800 mm height and an inner diameter of 200 mm (scrubber and absorber). A process flow diagram for the removal of CO2 and SO2 is presented in Fig. 3. Both columns were randomly packed with the ceramic Raschig rings (26.0 × 26.0 × 5.0 mm), giving a packing with a height of ~150 mm. The packed bed was found to have an 0.661 average void. The CO2 absorber was designed to operate at approximately atmospheric pressure and temperature up to 70ºC. The concentration of MEA was chosen to be 35 wt.% (pH = 10.7). For SO2 scrubbing was used an aqueous solution of sodium hydroxide of two concentrations 1 and 2 wt. % (pH – 13 and 13.3, respectively). The temperatures were measured in the combustor and along the flue gas route. Moreover, there were taken the inlet–outlet temperatures of the scrubbing solvents (i.e. MEA and NaOH) and cooling water. The gases were sampled after the cyclone and at the exits of scrubber and absorber. The main operating data of the system are shown in Table 3.
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Fig. 3. Flow diagram of chemical absorption of CO2 by aqueous MEA, and SO2 scrubbing with NaOH Table 3. Main operating conditions of the facility
Fuel mix flow rate (kg/h) Air flow rate (m3/h, fluidisation air) Average bed temperature (ºC) Scrubber average temperature (ºC) Absorber average temperature (ºC) Cooling water flow (l/h) Flow of aqueous NaOH (l/h) Flow of lean MEA (l/h) Flow of rich MEA (l/h)
10–15 40–60 810 150 60 200 2–4 5–15 30
SO2 removal. Emissions of sulphur dioxide from coal (or biomass) combustion are exclusively formed by oxidation of sulphur in the fuel. This pollutant is known to have harmful effects on human health and the environment being responsible for two-thirds of the acidity of atmospheric precipitation. Most biomass fuels contain little sulphur and thus the emissions of SO2 are low, whereas during the coal combustion large amounts of these pollutant emissions are produced. Biomass cofiring with coal will subsequently decrease the emissions of SO2. Currently, there are several ways to reduce SO2 emissions from coal fired power plants known as primary or secondary options4. 288
Test facility was equipped with a wet scrubber, in which an aqueous solution of sodium hydroxide was selected as scrubbing liquid (1 and 2 wt. %). Flue gas containing sulphur dioxide enters the bottom of the scrubber where it contacts aqueous sodium hydroxide flowing down through the packed bed. The reaction mechanism between sulphur dioxide and sodium hydroxide, which is a strongly alkaline solution, is quite complex. It depends on many factors such as pH of the solution, inlet flue gas SO2 concentration, temperature, concentrations of other gases. It may be described as follows: SO2 reacts with NaOH to form a compound of sodium sulphite (Na2SO3) and water. After that, sodium sulphite absorbs additionally sulphur dioxide resulting in a chemical compound of sodium hydrogen sulphite (NaHSO3). But in he presence of oxygen sodium sulphite oxidised to sodium sulphate (Na2SO4). The chemistry of the process is:
2NaOH + SO2 → Na2SO3 + H2O
(1)
Na2SO3 + H2O + SO2 → 2NaHSO3
(2)
Na2SO3 + 0.5O2 → Na2SO4
(3)
Furthermore, the solution of sodium hydroxide also reacts with carbon dioxide and hydrogen sulphide (H2S) yielding sodium carbonate (Na2CO3) and sodium sulphide (Na2S), respectively. CO2 absorption into monoethanolamine. Aqueous monoethanolamine, generally abbreviated as MEA, is the most widely employed solvent for CO2 absorption. MEA was developed over 70 years ago as a general non-selective solvent for removing acid gases, such as CO2 and H2S, from natural gas streams and refinery process streams. Though various new amines and amine blends have been developed, MEA is still the preferred absorbent for low pressure and low concentration CO2 absorption. A 35 wt. % MEA concentration solution was used during the tests. The following chemical reactions take place during the absorption (R is the radical HO–CH2–CH2–) (Ref. 8): RNH2 + CO2 + H2O ↔ RNH4CO3
(4)
2RNH2 + CO2 + H2O ↔ (RNH3)2CO3
(5)
(RNH3)2CO3 + CO2 + H2O ↔ 2RNH3HCO3
(6)
The absorption process is as follows: After SO2 removal, flue gases enter the CO2 absorption column (Fig. 3) and come into contact counter-currently with lean MEA, which chemically absorbs the CO2-gas. Absorption occurs at temperatures up to approximately 60ºC. The reaction between CO2 and MEA is exothermic and reversible by supplying heat to the system. Thus, at temperature levels of 50–60°C, the CO2 is retained by the chemical solvent. But, when rich MEA is heated up to 120°C, it releases the CO2-gas and the regeneration of the chemical solvent takes place. 289
From the bottom of the column, rich MEA, which contains the chemically bound CO2, is passed through a cooling phase. After that, it is pumped to the desorption tower where, it is heated counter-currently by the flue gas stream up to 120°C in order to release almost pure CO2. The pressure in the desorber is not very much higher than atmospheric pressure. During regeneration, the reaction proceeds from right to left, the CO2-gas evolves from the amine and is separated. The CO2, having been liberated from the MEA, leaves through the top of the separation unit. It should be then compressed and stored. The lean solution of monoethanolamine, containing far less CO2 is cooled down to 40°C, in a cooler, and recycled back to the absorber for additional CO2 capture. Results Temperature behaviours inside the combustor are shown in Fig. 4. During operation the highest temperature received was 980°C (for few seconds expecting higher NOx). No other major operational difficulties were observed during temperature variation. The decrease of the gas temperature was caused by the fuel feeding interruption.
Fig. 4. Temperature profile inside the combustor
Fig. 5. SO2 concentration profiles (TR1: 1 wt.% NaOH, pH=13; 2 wt.% NaOH, pH –13.3)
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Figure 5 shows the concentration of SO2 in the flue gas before and after the scrubber, using a strong alkaline solution of 1 and 2 wt.% NaOH. After leaving the scrubber the concentration of SO2 was in the range of 50–75 ppm. CO2 absorption into 35 wt.% MEA was relatively good with an overall absorption efficiency of 66%. It should be taken into account that the acceptable concentrations of SO2 and NOx in the flue gas before the absorber are recommended to be in the range from 10 to 50 ppm (Refs 3 and 9). Using a 2 wt.% NaOH concentrated solution it was possible to achieve 50 ppm of SO2. But in case if NOx are not controlled, the ability of the MEA solvent to capture more CO2 decreases. During operation we measured high NOx, 280–340 ppm. Figure 6 shows CO2 emission profiles and Fig. 7 presents the removal efficiency during test runs.
Fig. 6. CO2 concentration profiles (TR3: 35 wt.% MEA, pH –10.7)
Fig. 7. SO2 and CO2 removal efficiency (TR1: 86% and 1 wt.% NaOH; TR2: 91% and 2 wt.% NaOH; TR3: 66% and 35 wt.% MEA)
Conclusions The study presented is concerning the carbon dioxide capture and separation from the flue gas by means of aqueous solution of monoethanolamine as well as the SO2 removal procedure using sodium hydroxide. The main conclusions of the study are summarised as follows. 291
The higher the concentration of CO2 in the flue gas, the faster its absorbed by MEA. There are several compounds, typically present in flue gas, to which MEA absorption is particularly sensitive (e.g., SO2, H2S, NOx, etc.). Careful attention must also be paid to the fly ash and soot present in the flue gas, as they might plug the absorber if contaminants levels are too high. To a lesser or greater extent, the abundance of these molecules in the flue gas depends upon the composition of the fuel mixture between coal and biomass. The target was to reduce as much as possible their concentration in the flue gas, since they can inhibit the ability of the solvent to absorb CO2. Of all experiments performed, gaseous emissions of SO2 and NOx were reduced, as expected when using biomass with low sulphur and nitrogen content. Also, depending on the firing conditions NOx emissions were found to decrease or remain at the same level. Using a wet scrubber is one of the options for removing sulphur dioxide, and the technique should be applied before flue gases enter the CO2 absorber. Using sodium hydroxide, one achieved a reduction of SO2 by 90% and greater. Carbon dioxide concentration in the flue gas has been decreased by 60%, representing an average of all data mapped. However, the low content of sulphur, of oxides of nitrogen and some particles of ash and dust, which were in the flue gas before the CO2 absorber, has determined the degradation of MEA. No major operational difficulties were observed adding biomass to the combustion process, concluding that small quantities of biomass, up to 10% by heat input, can be easily added to conventional systems based on fossil solid fuel (coal), without major investments. Since biomass fuels are more volatile, the furnace volume must be large enough to accomplish complete combustion of the gases, as a requirement. Large quantities of heat are required by the desorption unit to regenerate the MEA solvent. Deciding where this heat is to come from is a fundamental part of the design of an MEA absorption plant. One approach is to extract the required heat from the flue gas that leaves combustor, as it was shown. As a consequence, the power plant is more difficult to design, more costly during the function and the power output of the station decreases. For instance, power plants with CO2 capture lose about 10% in efficiency, in comparison with those without CO2 capture. This means that the consumption of fossil fuels will increase dramatically, the cost of energy production will increase, too. One has still to optimise the global process, and there is only matter of time to succeed. Nevertheless the first developments in Europe demonstrated the technical possibilities for CO2 retention, in order to its sequestration. Also major plans are drawn for the next future, in international co-operation. Key targets of CASTOR10 is a major reduction in post-combustion capture costs, from 50–60 down to 20–30 € per t of CO2 and the validation of the new processes in a capture pilot plant installed in a coal-fired power station in 292
Denmark, to advance general acceptance of the overall concept in terms of storage performance (such as capacity, CO2 residence time, etc.), storage security and environmental acceptability and to start the development of an integrated strategy connecting capture, transport and storage options for Europe11. Intense research, development and demonstration efforts have to be directed towards the development of the new energy technologies, and improve existing ones. The proposed technology of co-firing biomass with coal is a viable option that promises reduction in the emissions of CO2, SO2 and NOx, allowing in addition to the clean combustion, also the CO2 capturing. The novelty consists also of the co-combustion process of a fossil fuel with a renewable, CO2 neutral energy resource, such as biomass waste. Globally the CO2 reduction might become more attractive as price, taking into account the positive involvement of the CO2 credits that are achieved, by that way, and that are adding financial input to the economy of the technology, in its whole. References 1. iea: Key World Energy Statistics 2007. OECD/IEA, Paris, France, 2007. 2. iea: World Energy Outlook 2004. OECD/IEA, Paris, France, 2004. 3. IPCC: Special Report on Carbon Dioxide Capture and Storage (Eds B. Metz, O. Davidson, H. Coninck, M. Loos, L. Meyer). Cambridge University Press, Cambridge, UK, 2005. 4. i. ionel, P. D. Oprisa-Stanescu, Cl. Gruescu, Al. Savu, C. Ungureanu: Environmental Protection by Coupling a Waste Incinerator to a Steam Boiler Using Coal Combustion. Revista de Chimie, 57 (12), 1306 (2006). 5. D. PETROVA, P. KOSTADINOVA, E. SOKOLOVSKI, I. DOMBALOV: Greenhouse Gases and Environment. J. of Environ. Protection and Ecology, 3, 679 (2006). 6. r. Beising: Climate Change and the Power Industry. VGB Power Technology, March, 2007. 7. A. S. CALINOIU: Utilization of Biomass for Energy Purposes in Romania. J. of Environ. Protection and Ecology, 2, 430 (2006). 8. C. stratula: Gas Purification. Bucharest, Romania, 1984. 9. K. Thambimuthu, J. Davison, M. Grupta: CO2 Capture and Reuse. In: Proc. of IPCC Workshop on CCS, Regina, November 2002, 31–52. 10. http://www.cachetco2.eu/c2ws/projects.html 11. http://www.encapco2.org/ Received 24 June 2008 Revised 15 August 2008
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