Evaluation Of Oxygen-Enriched Air Combustion Process .

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Int. J. of Thermal & Environmental EngineeringVolume 5, No. 2 (2013) 113-121Evaluation of Oxygen-Enriched Air Combustion Process Integrated withCO2 Post-Combustion CaptureAdewale Adeosun, Aravind Muthiah, Mohammad R. M. Abu-Zahra*Separation Technology Laboratory, Masdar Institute of Science and Technology, P.O. Box 54224, Abu Dhabi, United Arab EmiratesAbstractA novel concept combining membrane-based technology for air enrichment combustion process integrated with solventbased post-combustion capture is evaluated using Aspen Plus process simulation tool. The aim of this integratedconcept is to reduce the amount of Nitrogen used in the combustion process and as a result increase the CO2concentration in the flue gas. The effects of the increased CO2 concentration on liquid-to-gas molar flow ratio, solventflow rate, reboiler duty and washing water requirement are evaluated. Based on the cost analysis for the air separationunit and the CO2 capture solvent flow rate and washing water requirement, the optimum enrichment level of air wasfound to be 35% O2. However, in term of CO2 mole concentration in the flue gas and liquid-gas molar ratio in theabsorption process, 40% enrichment shows highest value of 28.22% and 7.15, respectively. No significant benefit isobserved in terms of reboiler duty as expected due to the fixed amount of CO2 captured and the limited increase in thesolvent rich loading. On the other hand, the flue gas flow rate was reduced dramatically at higher CO2 concentration,which will result in a smaller absorption tower and consequently a lower capital investment. In addition, with improvedmembrane technology that can work at lower air inlet pressure and with higher oxygen permeability and selectivity, thetarget energy reduction is achievable. These results encourage a full scale economic evaluation of the novel process ofcombining enriched air combustion and AMP-solvent based post-combustion capture to be conducted in order to weighenrichment costs to absorber size reduction economic benefits.Keywords: Carbon Capture, Post Combustion, Membrane, Coal power plant, Simulation1. IntroductionThe impact of climate change is becoming increasinglyevident, posing significant challenge, both in the political andscientific arenas. The emission of greenhouse gases has beenreported to be the main cause of global warming [1,2,3]. Tomitigate impacts, carbon dioxide capture and storage (CCS) isexpected to play significant role [4]. Since power plants,transportation, cement, metallurgical industries among othersconstitute the largest source of greenhouse gas emission [5], itbecomes vivid why technology research is focused oncapturing CO2 emissions from stationary sources.Three key technologies are currently available for CCS, anoverview of which is described in Figure 1 [6]. Postcombustion capture technology is focused on separating carbondioxide from the flue gas using conventional chemicalabsorption or other novel options such as adsorption. Pre-combustion capture technology is centered on fuelgasification, syngas shifting and extracting hydrogen from fuelthrough gasification. Oxyfuel combustion technology involvesthe combustion of fuel in pure oxygen, leading to high purityCO2 effluent. However, techno-economic evaluations of thevarious technologies indicate that there is yet to be found thewinning technology [7,8]. The winning technology will be onewhich meets the roadmap targets in terms of operating energypenalty, low cost of CO2 avoided and a reduction on capitalinvestment [9].Novel process involving membrane-based air enrichment,integrated with post-combustion capture technology isattracting attention [10, 11]. In fact, energy penalty reductionby 35% is reported to be achievable [12]. In this work, AspenPlus is used to evaluate air enrichment, fuel combustion usingthe enriched air and the post-combustion capture with a view toevaluating enrichment impacts on flue gas composition, liquidto-gas ratio, washing water requirement and reboiler duty. Thenovel evaluated concept is illustrated in the block diagramshown in Figure 2.*Corresponding author. Tel.: 97128109181E-mail: mabuzahra@masdar.ac.ae 2013 International Association for Sharing Knowledge and SustainabilityDOI: 10.5383/ijtee.05.02.003113

Adeosun et al. / Int. J. of Thermal & Environmental Engineering, 5 (2013) 113-121Fig.1. Schematic representation of the different capture systems [6]Fig.2. Block diagram of enriched air combustion with AMP-solvent based CO2 capture2. BackgroundGlobal dependence on fossil fuel is expected to increase untilthe middle of the century, especially from the emergingeconomies in Asia and Africa. New coal- and gas-fired powerplants will be built in order to meet the growing demand forelectricity and other industrial needs. To ensure that 50% CO2reduction target is met, key technologies including CCS,nuclear energy, improved energy/process efficiency, fuelswitching and renewable energy utilization are promoted byInternational Energy Agency [4]. For CCS, Post-combustiontechnology is the near term option for industrial deploymentdue to its retrofitability to existing power plants, suitability tolow CO2 partial pressure systems and process maturity, asapplied to gas sweetening [13]. However, large scaleimplementation for CO2 capture is plagued with high energypenalty and the capital intensive nature of the capture plant forthe monoethanolamine (MEA)-based chemical absorption.This leads to increased power generation cost.Efforts have been made to improve the process foreconomic viability. For example, major energy savings arereported through parametric optimizations involving leansolvent loading, amine solvent concentration, stripper operatingpressure, capture ratio, process temperature and pressure[9,14]. However, MEA-based PCC has been identified to havelow absorption capacity, low cyclic capacity, high degradationrate, high equipment corrosion rate and high regeneration114

Adeosun et al. / Int. J. of Thermal & Environmental Engineering, 5 (2013) 113-121energy requirement [15]. This has necessitated research intoother classes of amines including sterically-hindered-amines(e.g. AMP), secondary, tertiary amines and heterocyclic aminesincluding piperazine.In addition, smart process design, novel integration andadvanced solvents are to be investigated to make CO2 captureeconomically feasible for industrial deployment [9]. Otherefforts consider the option of increasing the CO2 concentrationin the flue gas stream either by recycling the flue gas with freshair over the boiler or by utilizing the concept of air enrichment[16,17,25]. Both options are expected to be beneficial to theoverall capture scenario due to expected reduction in flue gasflow rate. Thus, smaller absorber/desorber columns will berequired under these conditions. The capital investment cost,cost of CO2 avoided and the cost of electricity will be reduced.Based on these aforementioned benefits, this work evaluatesmembrane-based air enrichment integrated with postcombustion capture is applied to a coal-fired power plant usingAspen Plus simulations.3. Process and Simulation Description3.1. Air EnrichmentCryogenic separation has been the choice for high purityoxygen production for large scale production among thevarious available technologies as depicted in Table 1 [18].However, the energy penalty associated with the subzerooperations with the attending high capital investment in termsof equipment size and waste energy has led to findingalternatives. Modern membrane engineering has been seen asone of the future technologies to meet the roadmap targets forhigh CO2 flue gas concentration; hence the need for enrichedair combustion [19, 20].Table 1. Oxygen production technology urity(vol%)CryogenicMatureExcellent99 aturePoor 40ChemicalDevelopingPoor99 CeramicMembraneDevelopingPoor99 The choice of membrane in this work is based on permeability,selectivity, material structure and thickness and operatingtemperature. Recent work of Robeson [21] showed thatmembranes made of polymers of intrinsic microporosity (PIM)have better material properties and better trade-offs betweenoxygen permeability and oxygen-nitrogen selectivity. Theproperties needed for the simulation is presented in Table 2.As a pressure-driven process, compressor with isentropicefficiency of 85% and mechanical efficiency of 95% wasselected for the simulation with outlet pressure values of 3, 5,10, 15, 20 and 30 bar for the parametric studies. For each ofthese pressure values, the corresponding membrane area isdetermined using the mathematical relation in Equation 1 [12]and the compressor cost is determined from the electricalenergy consumption as obtained from simulations.Table 2.Membrane Modeling Fixed ParametersParameterValueUnitReferenceOxygen Permeability100Barrer[23]Thickness of membrane2.00E-06m[24]Pressure on permeateside1.013barCost of membrane45 /m2(1)The optimum pressure is determined from total capital cost plotagainst the pressure. The capital cost accounts to the membraneand compression costs only. Separator unit was chosen tomodel the membrane in the simulation and the processconsiders 25%, 30%, 35% and 40% air enrichment subjected tothe limitation for polymeric membranes as indicated in Table 1.Economic evaluation is restricted to the enrichment section.3.2. Power Plant DescriptionThe conventional power plants, novel and advancecombustion processes and their related gaseous emissions arewell established technology as discussed intensively in openliterature [26, 27, 28, 29]. Figure 3 shows the power plantsimulation with the enrichment section. The power plantsimulation involves coal crushing, enriched air combustion,steam turbine electricity production, flue gas cooling andrecirculation section. Due to the pressure gradient and thehigher selectivity and permeability of the chosen membrane,enriched air is produced and pumped into combustion furnace.Assumptions for power plant simulations include thefollowing: Fuel rate of 3kg/s is considered in all cases. Lean fuel combustion at 5% excess oxygen in the hotgas from the furnace. This is essentially set to justifycomplete combustion of coal assumption. Since increased oxygen relative to nitrogencomposition is expected to lead to higher combustiontemperature, flue gas is recirculated with fresh enrichedair to keep the boiler temperature at 1400 C. Thistemperature is well below the fuel adiabatic flametemperature and therefore hinders the thermal NOxformation which is promoted beyond1800 C [22].Coal typically delivered at the power plant as nonpulverized and characterized with different sizes that can reachseveral centimeters. Therefore, crushing of the coal isimportant to increase the specific surface area per unit volume.Also, complete combustion of the fuel can be achieved whenthe particle size distribution is within the range of 180 to 360microns. Multistage crushing model is used; with multiplescreens to sieve the coal particles to the appropriate size. Toensure a reduction in the power consumption by the crushingprocess as a result of solid transport, the coal particles are115

Adeosun et al. / Int. J. of Thermal & Environmental Engineering, 5 (2013) 113-121mixed with water. This leads to addition in the coal particlemoisture content up to 15wt%.In Aspen Plus simulation, the final coal particles wereseparated from the conveying water stream through a SEP2unit. The coal properties were established on chemical speciesassociated with both conventional and non-conventionalfeedstock specifications. For the physical property, PengRobinson with Mathias modification was used to model gasphase behavior. Elemental composition reactions are used torepresent coal combustion summary of the coal proximate andultimate properties, the coal fuel feed composition is given inTable 3. At this combustion temperature and particle size, theburner is modeled with RGibbs reactor, achieving equilibriumachieved through the Gibbs free energy minimization. Aftercombustion, the particulate matters are separated from the fluegas using SSplit model as an electrostatic precipitator. The hotgas stream is then used to produce superheated steam at 500 Cand 35atm pressure, modeled using two heater unit operations.This is subsequently used to be expanded in a steam turbinewhich is coupled with electric generator for electricityproduction. Before the flue gas is channeled to the stack, it issubjected to desulphurization and it is modeled using separatorand cooler units.Table 3.3.3. Post-Combustion Capture DescriptionThough, AMP has lower reaction kinetics than MEA, it isappropriate for enriched air post-combustion capturesimulation. This is because the potential higher cyclic loadingof AMP that can be harnessed, compared to MEA at higherCO2 partial pressure [25]. This will lead to lower solvent rateand higher liquid-to-gas ratio, thus smaller absorber size. Areduction in the condenser water rate is expected due to AMPlow vapour pressure. This can ultimately lead to elimination ofwashing section, and reducing further the capital expenditure.The process flow sheet diagram is presented in Figure 4.The flue gas is set to 1.2 bar pressure and 50 C temperature.Each of the obtained flue gas streams is simulated for thescrubbing using Radfrac unit as the absorber, with 4 stages anda pressure drop of 10kPa. The rich solvent from the bottoms ofthe absorber is pumped to 2.3 bar pressure to enhance the CO2desorption in the stripper. The pressurized rich solvent streampasses through a cross heat exchanger where it receives heatfrom the stripper bottom outlet stream. This cross heatexchanger is an important heat integration option to reduce theamount of thermal energy required for the feed stream enteringthe stripper for regeneration. The stripper is modeled usingRadfrac with 6 stages, 1.8 bar column bottom pressure and30kPa column pressure drop.Coal Feed Composition [30]Componentweight %Moisture9.535Fixed carbon50.909Volatile matter39.452Ash9.639The constraints used for the simulation is 90% CO2recovery by mole and less than 97% CO2 mass fraction in theCO2 stream from the top of the stripper. The simulation is donewith a heat exchanger design given by the difference in the hotstream outlet temperature and the cold stream outlettemperature. In this case, 5 C is chosen.CRUSHINGCCOALFG-RECY CHIERARCHYCUNITSULP HBURNE R1BOILER-AINHOT-P RODFEEDCOA LHOTGA SBURNE R2SULREMOVGRATECOOLPRODCLEA NGA SSP LITTE RQB OILFG-P CC2NITROGENAS HENRAIRTURBINEFG-P CCWATE RST EAMCONDBOILE-BWTRCOOLERCOMP-AIRPUMPAIRSE PAIRWORK 1WWEP OWERCOMPFig. 3. Coal-fired power plant with air enrichment section simulation process flow sheet116

Adeosun et al. / Int. J. of Thermal & Environmental Engineering, 5 (2013) RBERR-AMP-HRICH-AMPPUMPL-AMP-XFig. 4. Post-combustion CO2 capture simulation process flow sheet.4. Results and Discussionevaluate the effect on the combustion process efficiency,operation and emissions.4.3. Post-Combustion Capture Result4.1. Air Enrichment ResultFigure 5 shows the total cost against pressure for four oxygenenrichments levels. It is observed that the cost is higher at lowpressure and as the enrichment percentage increases. However,at higher compression, the cost flattens out for pressure above19 bars. The observed result implies that increasing the air inletcompression cost is counterbalanced by reduction in membranecost of the same order of magnitude as a result of a smallermembrane area requirement. Figure 6 elaborates on one of theoxygen enrichment as an example of 25% enrichment. Theoptimum pressure in this specific case is found to be 11.5 bar,giving a total membrane and compression cost of US 180million. Figure 7 shows a plot of optimum pressure againsttotal cost and the enrichment. As expected, the minimum costat optimum membrane inlet pressure increases with increasingenrichment ratio. At 40% air enrichment, carbon dioxide molepercent rises to 28.22% with optimum pressure of 17.5bar. ThisCO2 concentration is about twice the observed concentrationfor conventional air combustion process.4.2. Combustion ResultThe combustion process is simulated with flue gas recirculationin other to avoid increased NOx concentrations due to higheroxygen concentrations from enrichment. Flue gas is recycled toachieve 1400 C hot gas temperature from the furnace. Table 5gives the recycle ratio required to obtain the temperature setvalue. The result shows that significant amount of the flue gasmust be recycled. In the case of 40% enrichment, above 60% isrecycled, about twice the requirement in the case of conventioncombustion process. This reiterates the significant importanceof nitrogen as a diluent in combustion process. With this airenriched concept, more detailed study should be carried out toTable 4 shows liquid-to-gas ratios and reboiler duties whileTable 6 presents the solvent flow rates and washing water flowrate requirements for various enrichments. In both tables,values are compared with AMP-based post-combustion capturevalues using conventional air of 21% oxygen by mole. Theliquid-to-gas flow rates increase with increasing airenrichment. This is expected due to the reduction in the gasflow rate from air enrichment. With the same amount of fuelused in combustion process and same amount of CO2 to becaptured, the liquid flow rate requirement is marginal indifference for various enrichments. In terms of the reboilerduty, there is marginal decrease as the enrichment proportionincreases, which directly connected with the increase in thesolvent rich loading. With the air enrichment (N2 decrease), theCO2 concentration increases in the flue gas, the composition ofthe rich solvent to the stripper is also increased. This is thecritical factor that determines the reboiler duty. From table 5, itis observed that 35% air enrichment has the lowest solventflow rate of 15.36 L/kg-CO2 and lowest washing waterrequirement of 0.02 L/kg-CO2. Essentially, 40% air enrichmentis expected to have smallest absorber size reduction due to itslower liquid-gas ratio. When compared to the reference case ofconventional air combustion with AMP scrubbing with 4.38liquid-to-gas ratio, air enrichment of 40%. shows 44% decreasein flue gas flow rate, leading to 63% increase in liquid-to-gasratio. Since absorber typically represents 50% of purchasedequipment cost and gas path equipment constitutes 75% oftotal capture equipment cost [9], a significant reduction inabsorber size is expected at constant liquid flow. 25%, 30%and 35% enrichments show 14.8%, 27% and 37% reduction influe gas flow rates respectively, indicating expected benefits interms of reduced equipment cost from smaller absorber size.117

Adeosun et al. / Int. J. of Thermal & Environmental Engineering, 5 (2013) 113-121Fig. 5. Plot of total cost against membrane pressureFig. 6. Cost vs. membrane inlet pressure plot for 25% enrichment.118

Adeosun et al. / Int. J. of Thermal & Environmental Engineering, 5 (2013) 113-121Fig. 7. CO2 concentration and total cost results for air enrichmentsTable 4. Flue gas recirculation vs. enrichment ratioOxygen Enrichment (%)Recycle Ratio210.334250.427300.507350.564400.605Table 5.Liquid-to-gas ratio and reboiler duty simulation result for enrichmentsOxygen EnrichmentL/GRatioReboiler DutyRich loading 19

Adeosun et al. / Int. J. of Thermal & Environmental Engineering, 5 (2013) 113-121Table 6.Solvent flow rate and washing water requirementOxygenEnrichment (%)21Solvent Flowrate(L/kg-CO2)16.93Washing Water 24015.500.055. ConclusionAir enrichment combustion process integrated with CO2 postcombustion capt

combining enriched air combustion and AMP-solvent based post-combustion capture to be conducted in order to weigh enrichment costs to absorber size reduction economic benefits. Keywords: Carbon Capture, Post Combustion, Membrane, Coal power plant, Simulation 1. Introduction The impact of climate change is becoming increasingly

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