Oxy-coal combustion for retrofit: challenges and opportunities

This paper is concerned with Oxy-Fuel Combustion, a process for the control of carbon dioxide from a range of solid fuel combustion processes. The focus is on the applicability of this technology for retrofit and hence on entrained flow combustors rather than on circulating fluidized bed systems. First, the importance of retrofit technology for CO2 control from coal fired units in the US is outlined. The current state of the technology (applied mainly to pulverized coal combustors), and critical research needs are identified. There are three over-arching issues that must be resolved in order for oxy-coal retrofit to be attractive: the first is related to the O2 supply energy penalty since current cryogenic technology can consume 15-20% of energy produced; the second is related to the purity of CO2 in the flue gas for sequestration; and the third is related to air ingress through leaks that are present in most existing systems. Resolution of these over-arching issues requires efforts by industrial gas engineers, politicians, and combustion engineers, respectively. One objective of current research in oxy-coal combustion for retrofit is to create enabling technology to be used for: 1) extrapolation of boiler performance from conventional air firing to oxygen firing with sufficiently large amounts of flue gas recycle to match heat transfer to existing heat exchange surfaces. 2) extrapolation to substantially modified existing units that "still look like boilers" but that optimize and reduce the amount of flue gas to be recycled and therefore may require some relocation of heat transfer surfaces. This enabling technology will be comprised of simulations employing validated heat transfer sub-models (radiant and convection zones), and validated chemistry sub-models (coal jet ignition, chemistry, char burnout, ash partitioning, trace metals, and combustion by-products - NOx, SOx, Hg), where validation must be under oxy-fuel combustion conditions, with varying amounts and compositions of flue gas recycle streams. Recent research results in each of these areas are presented

INTERNATIONAL FLAME RESEARCH FOUNDATION 16th IFRF Members' Conference, Boston, MA, June 8th -10th, 2009 OXY-COAL COMBUSTION FOR RETROFIT: CHALLENGES AND OPPORTUNITIES Jost O. L. Wendt Department o f Chemical Engineering and Institute for Clean and Secure Energy, University o f Utah, Salt Lake City, Utah, USA ABSTRACT This paper is concerned with Oxy-Fuel Combustion, a process for the control of carbon dioxide from a range of solid fuel combustion processes. The focus is on the applicability of this technology for retrofit and hence on entrained flow combustors rather than on circulating fluidized bed systems. First, the importance of retrofit technology for CO2 control from coal fired units in the US is outlined. The current state of the technology (applied mainly to pulverized coal combustors), and critical research needs are identified. There are three over-arching issues that must be resolved in order for oxy-coal retrofit to be attractive: the first is related to the O2 supply energy penalty since current cryogenic technology can consume 15-20% of energy produced; the second is related to the purity of CO2 in the flue gas for sequestration; and the third is related to air ingress through leaks that are present in most existing systems. Resolution of these over-arching issues requires efforts by industrial gas engineers, politicians, and combustion engineers, respectively. One objective of current research in oxy-coal combustion for retrofit is to create enabling technology to be used for: 1) extrapolation of boiler performance from conventional air firing to oxygen firing with sufficiently large amounts of flue gas recycle to match heat transfer to existing heat exchange surfaces. 2) extrapolation to substantially modified existing units that "still look like boilers" but that optimize and reduce the amount of flue gas to be recycled and therefore may require some relocation of heat transfer surfaces. This enabling technology will be comprised of simulations employing validated heat transfer sub-models (radiant and convection zones), and validated chemistry sub-models (coal jet ignition, chemistry, char burnout, ash partitioning, trace metals, and combustion by-products - NOx, SOx, Hg), where validation must be under oxy-fuel combustion conditions, with varying amounts and compositions of flue gas recycle streams. Recent research results in each of these areas are presented 1. in t r o d u c t io n 1.1 The Problem Implementation of carbon capture and sequestration (CCS) technologies is motivated by the fact that in a typical year large amounts of carbon are taken from below the earth, and brought to its surface, where approximately one half contributes to an increase of CO2 in the atmosphere and the remainder is split between sinks in the ocean and on land. A preponderance of peer reviewed scientific opinion suggests that the consequences of this transfer of carbon will have profound effects on global climate change. The US and China are major emitters of CO2 and coal combustion is a major source of carbon dioxide emissions, both in the US and especially in China. In June 2007, the annual CO2 emission rate (but not the integrated total over all time) from China exceeded that from the US. Ample supplies of coal are available for future energy use with 259 billion tons available in the US, 150 billion in Russia, 120 billion in China and almost 100 billion each in India and Australia. Furthermore carbon storage capacity (in saline aquifer and the like) is abundant, with over 6 times the capacity required to stabilize atmospheric CO2 values at 450 ppm [1]. Deutch and Moniz [2] concluded that CO2 capture and sequestration (CCS) is the critical enabling technology that would reduce CO2 significantly while also allowing coal to meet the world's pressing energy needs. Although many new coal-fueled power plants have recently been in the planning process (In the US, these represent over 250 MMTPY of coal use) only a fraction of these have been permitted to date. Offshore, China has been commissioning between 1 and 2 new 300MW coal fired power plants per week. 1 INTERNATIONAL FLAME RESEARCH FOUNDATION 16th IFRF Members' Conference, Boston, MA, June 8th -10th, 2009 steam turbine carbon dioxide compressor energy Figure 1. Oxy-coal combustion showing different flue gas recycle options. Implementation of CCS cannot wait for completely new electrical power generation technologies to be developed. Furthermore, a recent US Department of Energy estimate [3] suggests that by the Year 2030, coal fired steam boilers, originally designed for air combustion, will contribute to 79.4% of all US coal fired CO 2 emissions, and 91.9% of cumulative CO2 emissions from 2008 (307GW) to 2030 (402GW), unless CCS is applied to existing coal fired units. Therefore, in order to have an impact on coal CO2 emissions in the US, CCS technology must be applied to existing, air fired units. 1.2 Oxy-Coal Combustion. Figure 1 shows a schematic of a near term application of oxy-coal combustion to efficient conventional boilers. Recycle of flue gas is essential in order to accommodate existing heat transfer surfaces in an existing boiler. Recycle of flue gases can occur either before any pollution control device (R 1 ), or after particulate removal (R2) or after water condensation (R3) or after flue gas desulfurization (R4) Estimates for oxy-coal combustion technology costs vary, but the differences between the cost of electricity from coal fired power plants with CSS using oxycoal combustion and that from conventional coal combustion is less than the current difference between maximum and minimum costs of electricity currently being charged within the US (Kentucky - $46/MW-h, Island of Kauai, Hawaii - $220/MW-h). Some estimates show oxy-coal costs to be less than those for IGCC with CCS and also less that MEA absorption, while others show the converse. Possible advantages of oxy-coal combustion for retrofit are as follows: 1. It uses process components, air separation units (ASU's), CO 2 compression, with or without pre-separation, steam generation, and steam turbine units that consist of well developed, proven technologies. These components have been tested individually on a full scale and current work is in progress in Germany and Australia, where they are being tested together as a system. 2. The steam generator can be identical existing air fired steam generators, if flue gas is recycled, as shown on Figure 1. This can be a source of comfort to current workers in electric power generation plants. 2 INTERNATIONAL FLAME RESEARCH FOUNDATION 16th IFRF Members' Conference, Boston, MA, June 8th -10th, 2009 3. Oxy-coal combustion is consistent with a business model in which the O2 supply is available from a contracted industrial gas supplier, "outside the fence" around the steam generation plant. Likewise, the CO2 (or possibly even dirty compressed flue gas) can be sent "over the fence" to a disposal company. This allows the electric utility company to concentrate on its core business, namely the generation of electric power, and other entities, such as industrial gas companies, to concentrate on their core businesses, that of oxygen supply and gas separation. A major disadvantage of oxy-coal combustion is that it is not suitable for partial CO2 capture and sequestration by sequestering only a portion of the CO2 produced using a slipstream of the total exhaust gas. 1.3 Over-arching Issues The future of oxy-coal combustion for retrofit will be determined by the resolution of three over-arching issues: 1. The O 2 supply energy penalty. Currently available cryogenic technology can consume 15­ 20% of the energy produced, thus greatly lowering overall efficiency of the plant [4]. 2. The required purity of the CO2 to be delivered for sequestration. Is it a waste, or a resource with commercial value for tertiary oil recovery [5]. What are the regulatory issues? What are the technical limitations to the level of impurities in the CO2 stream, both for compression cost reasons and for pipeline corrosion considerations? 3. The ingress of air through air leakage. This dilutes the exiting CO2 and can greatly increase compression costs. O2 Supply. Current technology governing the oxygen supply centers on a cryogenic air separation unit (ASU), which is a mature technology, not susceptible to significant energy improvements. Increased sophistication in ASU design might yield a maximum improvement of 15% for the energy required. Future breakthrough technologies involving oxygen transport membranes are not yet commercial. An O2 purity in excess of 97.5% requires are sudden increase in energy requirements because of the need to separate O2 and Argon [4]. CO2 Purity. Some impurities in the flue gas stream can be removed during simple compression. One point of view suggests that during compression NO is converted to NO2; NO 2 catalyzes the oxidation of SO2 to SO3, and ultimately forms nitric acid when all the sulfur is oxidized and removed as sulfuric acid. Trace metals, including Hg are then dissolved in the ensuing "soup". Clearly residence times, reactor configurations and design are important, some of which may be available in literature on the lead chamber process for sulfuric acid. The following questions arise: 1. Can oxy-coal combustion operate with no air pollution control technology required, since all impurities will be removed during the compression process? 2. Should high NOx be desirable as a means of accelerating the oxidation to NO 2 and the subsequent oxidation of SO2 to form SO3 and sulfuric acid. Air Leakage. Elimination of air leakage is an engineering problem. Regenerative air heaters are are known source of leakage in conventional plants, but that is less of an issue for oxy-coal where the fluid on the "air" side of the pre-heater is not air (to leak in) but a mixture of O2 and CO2. The largest sources of outside air must be identified. It is likely that they occur in the particulate control equipment downstream. Furthermore, most utility units are operated under a slightly negative (balanced) draft, primarily for safety reasons, since the boiler is usually contained in a building, and does not freely stand outside as do many industrial units that operate under forced draft. It might be useful to explore possibilities of operating existing boilers under slightly positive pressure, for the sole purpose to eliminate air leakage. 2. OXY-COAL COMBUSTION RESEARCH NEEDS 2.1 Oxy-coal combustion research outputs. One can divide research outputs for retrofit into two categories: 3 INTERNATIONAL FLAME RESEARCH FOUNDATION 16th IFRF Members' Conference, Boston, MA, June 8th -10th, 2009 1. 2. Enabling technology for retrofit in conventional, nearly air tight, air-fired units that have been proven for air firing. This output comprises the short term objective (application in 2020) of research on oxy-coal combustion, where heat transfer surfaces are left in place. Enabling technology for oxy-coal application to existing units that still look "somewhat like current boilers". This is for optimum or minimal CO 2 recycle ratios. The heat transfer surface surfaces may not be situated exactly as they were for the original air fired units. This output comprises an intermediate term (application in 2030) objective of research on oxy-coal combustion. Development of new technologies (such as chemical looping) that do not look at all like current boilers, is probably not applicable for retrofit, unless total replacement of everything on an original utility plant footprint were to be considered as retrofit. This would be long term research. 2.2 Short term research objectives. In order to retrofit existing boilers designed for air firing, flue gas must be recycled as shown on Fig 1 . In order to predict how an existing boiler will operate under oxy-fired conditions there is a need for simulations which allow: 1. Fiddle-free validation using comprehensive heat transfer, temperature profile, O2, CO2, and NOx profiles, ash deposition, and steam side property data from air-fired coal combustion units. 2. Validated sub-models for various oxy-coal combustion processes - heat transfer, ignition, carbon burnout, ash deposition etc. as shown below on Fig 2. 3. Extrapolation from air fired to oxy-combustion conditions. Fig.2 depicts research issues relating to sub-models required for the required simulations. W here should the recycled g a se s be taken from? After: ash removal? H2O removal? SO 2 removal? Can we predict heat transfer profile, fouling, slagging, ash partitioning and char burnout under oxycoal combustion conditions. ► To Slack FPilverize r Can we predict ignition/kinetic/aerodynamic interactions here at the burner? How much residual N2, NO, Hg, SO 2, trace metals etc. can be removed with the CO 2 to be sequestered? Figure 2: Retrofit for existing, but efficient air fired units. Specifically, one can identify the need for validated sub-models to extrapolate from air to O2. These sub­ models include: • Heat transfer sub-models for both radiant zone and convection zone. • Coal jet ignition sub-model, involving chemistry and burner near field aerodynamics. • Char burnout sub-model • Ash partitioning syb-model to predict deposition and trace metals. 4 INTERNATIONAL FLAME RESEARCH FOUNDATION 16th IFRF Members' Conference, Boston, MA, June 8th -10th, 2009 • • Combustion by-products, such as NOx, Sox, and Hg Integrated furnace model Heat transfer sub-model: radiant zone. The high proportions of CO2 and H2O in the furnace gases result in higher heat capacities and higher gas emissivities [6,7]. In general, if we match adiabatic flame temperature 70% of the flue gas must be recycled (R=0.7) to yield an average inlet O2 concentration of 30% (as opposed to 21% O2 for air combustion). Rpraxair, the ratio of recycled flue gas to inlet oxygen is 2.33 [8 ]. However, detailed CFD modeling to predict wall heat flux shows that matching adiabatic flame temperature does not lead to similar wall heat fluxes for oxy-coal and air combustion. Adjusting the recycle ratio to yield match wall heat fluxes leads to a predicted recycle ratio of 74% (R=0.74) or an average inlet O2 concentration of 26% O2 and Rpraxair = 2.85. Clearly one requires accurate models for emissivities of flue gases with very concentrations of CO2, H2O and other flue gas species [7]. Heat transfer sub-model: convection zone. Oxy-coal flue gas properties are different from those in the airfired case. At R=.0.7, 30% inlet O2, the convective heat transfer coefficient ration hoxy/hair equals 1.15 [9]. This assumes no ash deposits to hinder convective heat transfer. However, deposition of ash on heat transfer surfaces might be controlling, and this requires a validated ash partitioning model, and a validated ash deposition model. Coal jet ignition sub-model. Fig. 3 shows a picture of a Type 0 axial turbulent diffusion flame, similar to S t a n d o ff ig n itio n d is ta n c e . S m a lle r p a rtic le s p re fe re n tia lly m ig ra te to th e je t e d g e . P y ro ly s is b e h a v io r P a r t i c l e ig n itio n Figure 3. Coal jet ignition sub-model attributes. those in tangentially fired boilers or cement kilns. The stand off distance depends on primary jet velocities , and PO2 in the primary fuel jet, which becomes an independent variable under oxy-coal combustion. A sub­ model should capture the observations shown on Fig 3, and the migration of small coal particles to the outside of the jet has implications for important coal jet ignition mechanisms. The effect of the CO 2 on particle ignition and pyrolysis is largely to delay oxygen diffusion to the particle, and thus to delay ignition and subsequent particle heat up [ 1 0 ]. Char burnout sub-models. There are contradictory results in the literature on effects of oxy-coal combustion, with CO 2 recycle, on char burnout times. Increased burnout times, decreased burnout times and no changes in burnout times have been reported. Clearly, many effects come into play, and one must untangle the conflicting effects of changes in residence time, surface reactions, particle transport rates, coal composition and rank, and temperature profiles [11]. There is a need for well defined, systematic, experimentation to validate existing char burnout models, and identify the need for new ones. The following specific mechanisms must be considered: 1. The effect of CO2 on film diffusion of O2 to the char surface is to degrease that rate by 20% 2. The effect of the heat capacity of CO 2 on the peak gas temperature of the surrounding boundary layer, and on heat transfer back to the particle. 3. Competition by CO2 for available reaction sites for O2. 5 INTERNATIONAL FLAME RESEARCH FOUNDATION 16th IFRF Members' Conference, Boston, MA, June 8th -10th, 2009 Conventional coal combustion D ecreased to one-seventh (>,/( (),coal combustion with heat recirculation Case I Case 2 Case 3 Case 4 Taken from Okazaki, K. Plenary lecture, 13th intl. Heat Transfer Conf., Sydney, August 2006 Figure 4. Effect of flue gas recycle on coal nitrogen conversion to NO 4. Direct gasification of char by CO2. Shaddix and Molina [11] showed that at 12% O2 and higher, although the char particle temperature is lower by 50 -100K in CO2 and hence combustion rates are lower, at a given particle temperature, the burning rate is unchanged. Hence Postulate 1 above is the main cause that CO 2 appears to increase burnout times. Gasification reactions do not play a role for O2 concentrations >12%. Ash partitioning and deposition sub-model. Little information is available on effects of oxy-coal combustion on the size segregated ash aerosol composition. One might expect significant effects of the high concentrations on CO2, SO2, and SO3 . Also the role of increased concentrations of sub-micron particles (which are difficult to separate) should not be neglected. Although equilibrium analyses are available, little is known about these effects. Ash partitioning mechanisms under oxy-coal combustion conditions are important for heat transfer simulations, and the lack of knowledge in this area comprises a critical gap. Combustion by-products sub-model: NOx, SO - and Hg. The Okazaki group at Tokyo Institute of Technology [12, 13] has shown that NOx (in terms of fuel N conversion) from oxy-coal combustion can be decreased by one seventh, due reburning of the recycled flue gases. His results are shown on Fig 4, and indicate a potential decrease to 1/7 of the NO from air firing is possible. Okazaki [14] also showed that because of very much higher levels of SO3, sulfation of calcium is 4-6 times higher than under air fired conditions. This would have significant impact for US Powder River Basin coals which are known to be high in calcium content. Little data are available on the fate of Hg. Much work remains to be done on determining the rates and mechanisms of the "lead chamber process" nitrogen oxide and sulfur oxide interactions during condensation and compression, and the potential of significant removal of all impurities during that process. Integrated furnace models. Since the seminal work of Payne et al. [15] in 1989, several other simulations of oxy-fuel fired furnaces have been published [16]. 2.3 Interm ediate term objectives. The intermediate research objectives for oxy-coal combustion should be to minimize (or to optimize or to eliminate) externally recycled CO2. This may involve H2O injection or directed pure O2 injection. One can draw on the oxy-fuel experience drawn from modern glass furnace design and the use of internal recycle to diminish temperature peaks, as in flameless combustion. 6 INTERNATIONAL FLAME RESEARCH FOUNDATION 16th IFRF Members' Conference, Boston, MA, June 8th -10th, 2009 The critical barriers to the implementation of oxy-coal combustion with minimum recycle must be identified, whether it be materials or special mixing configurations allowing direct O2 injection. Again, the need is for reliable simulations that allow accurate aerodynamic/temperature predictions for internal recirculation caused by super fast jets, for heat transfer predictions in controlled cooling configurations. Ash partitioning mechanisms must also be validated for situations in which there are spatial variations involving local high temperatures and local stoichiometric ratios. The overall intermediate term objectives are to come up with designs that look somewhat like a current boiler, but may have modest differences in location of heat transfer surfaces. 2.4 Long term objectives. Over the long term oxy-coal combustion configurations are unlikely to look much like a current boiler. They may employ chemical looping using oxygen carriers. The latter may ne iron oxide based or calcium sulfate based. Chemical looping is expected to be the least expensive method to use oxy-coal combustion, but the resulting boiler will not bear much resemblance to a current boiler. Other systems may use oxygen transport membranes, while still others may emply circulating fluidized beds. CONCLUSIONS The near term future of coal requires carbon capture and sequestration (CCS) in existing units. Oxy-coal combustion can play a role for boilers, initially built to use air, but with the potential for future retrofit. The three over-arching issues concern the energy penalties for the O2 supply, the required purity for the CO2 to be sequestered, and the emanation of air leakage. In the short term validated simulations will be the key to allow retrofit with confidence. Simulation sub­ models will require some development and validation, although much is known. The intermediate term should focus on optimizing or minimizing the amount of flue gas to me recycled. Implementation of this also requires validated simulations. In the long term there are many competing concepts, ranging from chemical looping to integrated oxygen membranes. These will lead to units that do not resemble current boilers. ACKNOWLEDGEMENTS This paper resulted from activities funded by the University of Utah, and by the Utah Clean Coal Program, which is funded by the US Department of Energy. 5.0 REFERENCES [1] Dooley, James, Pacific Northwest National Laboratory, Battelle, 2004 [2] Deutch, J and Moniz, E.J., "The Future of Coal", Massachusetts Institute of Technology, 2007 [3] Ciferno, J. P., Fout, T. E., Jones, A. P, and Murphy, J.T., "Capturing Carbon from Existing Coal Fired Plants" Chem Eng Prog, 105, 4 (2009) 33-41. [4] Shah, M., "Oxy-fuel combustion for CO2 capture from PC boilers" Proc. 31st International Conferenrence on Coal Utilization and Fuel Systems, Clearwater, Florida, May 21-26, 2006. [5] [6 ] See web page: http://www.epa.gov/safewater/uic/pdfs/prefr uic co2rule.pdf (2008) Buhre, B.J. P., Elliott, L.K., Sheng, C.D., Gupta, R.P., Wall, T.F. "Oxy-fuel combustion technology for coal-fired power generation", Prog Energy Combust. 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