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Subpilot Demonstration of the Carbonation−Calcination Reaction (CCR) Process: High-Temperature CO 2 and Sulfur Capture from Coal-Fired Power Plants

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Subpilot Demonstration of the Carbonation−Calcination Reaction (CCR) Process: High-Temperature CO 2 and Sulfur Capture from Coal-Fired Power Plants
  Subpilot Demonstration of the Carbonation - Calcination Reaction (CCR) Process:High-Temperature CO 2  and Sulfur Capture from Coal-Fired Power Plants William Wang, Shwetha Ramkumar, Songgeng Li, Danny Wong, † Mahesh Iyer, ‡ Bartev B. Sakadjian, § Robert M. Statnick, and L.-S. Fan* William G. Lowrie Department of Chemical and Biomolecular Engineering, 140 West 19th A V enue, 125 AKoffolt Laboratories, The Ohio State Uni V ersity, Columbus, Ohio 43210 Increasing concerns over growing CO 2  levels in the atmosphere have led to a worldwide demand for efficient,cost-effective, and clean carbon capture technologies. One of these technologies is the Carbonation - CalcinationReaction (CCR) process, which utilizes a calcium-based sorbent in a high-temperature reaction (carbonation)to capture the CO 2  from the flue gas stream and releases a pure stream of CO 2  in the subsequent calcinationreaction that can be sequestered. A 120 KWth subpilot-scale combustion plant utilizing coal at 20 pph alongwith natural gas has been established at The Ohio State University to test the CCR process. Experimentalstudies on CO 2  capture using calcium-based sorbents have been performed at this facility. Greater than 99%CO 2  and SO 2  capture has been achieved at the subpilot-scale facility on a once-through basis at a Ca:C moleratio of 1.6. In addition, the sorbent reactivity is maintained over multiple cycles by the incorporation of asorbent reactivation hydration step in the carbonation - calcination cycle. Introduction Since the Industrial Revolution, atmospheric CO 2  concentra-tions have steadily increased from 280 ppm (ppm) to its currentvalue of 385 ppm, representing an increase of 35%. 1–3 This ismainly due to the unabated emission of CO 2  as a result of increasing consumption of fossil fuels such as coal, oil, andnatural gas. Point sources, which contribute more than one-third of all anthropogenic CO 2  emissions, 4 are candidates forimplementing CO 2  reduction practices due to the relatively highconcentration and quantity of CO 2  emitted. High fossil fuelconsumption per year leads to high CO 2  emissions at these largepoint sources due to their dominant use in electricity generation. 5 In the United States, approximately one-third of all CO 2 emissions is derived from coal combustion for electricityproduction, which accounts for nearly one-half of the totalelectricity generation. 6,7 Worldwide, coal combustion is respon-sible for 42% of the CO 2  emissions while providing 41% of the electricity generated. 8 Due to the significant CO 2  emissionsoutput by fossil fuel power plants, a concerted, worldwide effortis ongoing to develop economical CO 2  capture systems fromfossil fuel-fired power plants.Comprehensive CO 2  management scenarios involve a three-step process that includes separation, transportation, and safesequestration of CO 2 . Economic analysis has shown that CO 2 separation accounts for 75 - 85% of the overall cost associatedwith carbon sequestration. 9 Since 99% of all coal-fired powerplants in the United States are pulverized coal plants, there is aclear necessity to develop a postcombustion CO 2  separationprocess. 10 Currently, though, very few commercial-scale tech-nologies exist for effectively capturing CO 2 .Further complicating CO 2  capture processes is the existenceof several additional species in flue gas, which include watervapor, oxygen, sulfur oxides, nitrogen oxides, and ash. Regula-tions currently exist for sulfur dioxide emissions, and any carboncapture process must not violate the existing regulation of 1.2lb SO 2  per million BTU. 11 Several technologies have beendeveloped for postcombustion SO 2  control. Worldwide, 87%of installed SO 2  control technologies use a wet process with97% using a calcium-based sorbent. The other main technologyinjects a dry sorbent into the flue gas stream, where the sorbentis still predominantly calcium based. 12,13 The most mature and commercially ready technology is amine-based scrubbing. While monoethanolamine (MEA) has the abilityto effectively remove greater than 90% of the CO 2  in a flue gasstream, the cost of electricity would increase by a minimum of 80% while decreasing power plant efficiency by 30%. 14 FurtherhamperingMEAasaCO 2  removalprocessfromacoalcombustionflue gas stream is its incompatibility with flue gas components.Reports suggest SO 2  concentrations must be maintained below 10ppm to prevent significant solvent deactivation, which requiresgreater than 98% SO 2  removal for even the lowest sulfur coals. 15,16 Oxygen and particulates are also known to cause performanceissues with the amine solvents. 15,16 The dilute CO 2  concentration in the flue gas complicates theCO 2  separation. By replacing combustion air with oxygen, in aprocess know as oxy-combustion, a highly concentrated CO 2 flue gas stream is generated. Babcock and Wilcox (reference:http://www.babcock.com/ and http://www.babcock.com/about/ parent_company.html) recently demonstrated coal-fired oxy-combustion on a 30 MWth boiler. 17 Although air separationunits (ASUs) are commercially available, several challengesassociated with oxy-combustion still exist. They include airinfiltration, which dilutes the CO 2  flue gas stream, the energyconsumption of the ASU, which arises from the use of cryogenicdistillation, and the overall economics of oxy-combustion, withestimates predicting a 60% increase in the cost of electricity. 14,17 Newer technologies being developed include adsorbents,membranes, and cyclical reactive separation using solid sorbents.Adsorption onto a high-surface area solid is under development.Currently, molecular sieves can retain 0.246 g of CO 2  /g of adsorbent. 18 Adsorbents such as high surface area activatedcarbon can achieve 0.0657 g of CO 2  /g of adsorbent. 18 Mem- * To whom correspondence should be addressed. Tel.: (614)-688-3262. Fax: (614)-292-3769. E-mail: fan.1@osu.edu. † Current address: Dow Chemical Company, Freeport, 2301 N.Brazosport Blvd., Freeport, Texas 77541-3257. ‡ Current address: Shell Global Solutions (US) Inc., 3333 Highway6 S, Houston, TX 77082. § The Babcock & Wilcox Power Generation Group, Barberton, OH44203.  Ind. Eng. Chem. Res.  2010,  49,  5094–5101 5094 10.1021/ie901509k   ©  2010 American Chemical SocietyPublished on Web 02/17/2010  branes for separating CO 2  from a flue gas stream have potentialfor commercial-scale applicability. Currently, however, mem-branes lack the durability to withstand the temperatures and fluegas components, selectivity, and reliability. Operational tem-peratures for membranes are currently below 100  ° C, but theminimum exit temperature of the flue gas is above 120  ° C inorder to prevent acid gas corrosion. 18,19 Separation technologies based on absorption, adsorption,membrane separation, and cryogenic separation necessitate alow temperature and/or high pressure of flue gas to enhancethe CO 2  sorption capacity of the sorbent/solvent or the diffusionflux of CO 2  through the membrane. However, flue gas istypically characterized by subatmospheric pressure and hightemperature. Metal oxides are capable of reacting with CO 2 under existing flue gas conditions, thereby reducing downstreamprocess modifications. We detailed elsewhere the advantagesof a high-temperature reactive separation process based on thecarbonation and calcination reactions of CaO to separate CO 2 from flue gas. 20–22 The key advantage offered by this processis the enhanced CO 2  sorption capacity (0.35 - 0.70 g of CO 2  /gof CaO) exhibited by the high-reactivity CaO particles underexisting flue gas conditions over multiple cycles of CCR. CO 2  Capture Using Calcium Sorbents.  The concept of utilizing lime for CO 2  capture has existed for well over acentury. It was first introduced by DuMotay and Marechal in1869 for enhancing the gasification of coal using lime. 23 CONSOL’s CO 2  acceptor process was then developed and testedin a 40 tons/day plant. 24 A variation of this process called theHyPr-RING process was developed in Japan for the productionof hydrogen at high pressures. 25 Shimizu et al. (1999) conceptu-ally designed a process that uses twin fluidized bed reactorsfor capturing CO 2  from a coal combustion power plant. 26 Thecalcium-based looping process has also been applied to theproduction of hydrogen both from syngas by the water - gasshift reaction and methane by the sorption-enhanced steammethane reforming reaction. 27–31 The regenerability of the calcium oxide (CaO) sorbent hasbeen the major drawback of high-temperature calcium-basedCO 2  capture processes. CaO sorbents are prone to sinteringduring the high-temperature regeneration step. Over multiplecycles, the percentage of sintered CaO progressively increasesand reduces the CO 2  capture capacity of the sorbent. 24,32–39 Dueto sintering, higher solid circulation or makeup rates need tobe used to maintain a high level of CO 2  removal. 40 Pretreatmentmethods have been developed to reduce the decay in reactivity,which involve hydration of the sorbent, 35,41–44 preheating andgrinding of the sorbent, 45 and synthesis of novel sorbents byphysical or chemical modification of the precursor. 20,44,46–49 Addition of a sorbent reactivation step as a part of the car-bonation - calcination cycle has also been proposed to reversethe effect of sintering during each cycle and thus maintain thesorbent reactivity. 50,51 This paper outlines the process concept and details theexperimental data for the simultaneous capture of CO 2  and SO 2 from combustion flue gas streams using the Carbonation - Calcination Reaction (CCR) process. 21,22,50,52 The CCR processis an outgrowth of two other processes developed at The OhioState University: the Ohio State Carbonation Ash Reactivation(OSCAR) process 53–56 and Calcium-based Reaction Separationfor CO 2  (CaRS-CO 2 ) process. 22 The OSCAR process involvesthe use of novel calcium-based sorbents for sulfur and traceheavy metal (arsenic, selenium, and mercury) capture in thefurnace sorbent injection (FSI) mode. A pilot-scale study of theOSCAR process showed successful scale up of sorbent synthesisand superior extents of capture of sulfur, arsenic, selenium, andmercury from flue gas. 54 The CaRS-CO 2  process involves thecapture of CO 2  and SO 2  from a multicomponent gas streamusing high-reactivity, regenerable calcium-based sorbents. 22 TheCCR process uses a regenerable calcium-based sorbent withsorbent reactivation by hydration 50 as a step in the carbonation - calcination cycle to prevent the decay in sorbent reactivity overmultiple cycles. The CCR process has been demonstrated at a120 KWth subpilot scale facility at The Ohio State Universityusing flue gas from a stoker boiler. Process Scheme.  Figure 1 depicts the schematic of the CCRprocess with various reaction schemes, and Figure 2 illustratesthe overall process flow diagram of the CCR process. The CaOor Ca(OH) 2  sorbent is injected into the carbonator, which is anentrained bed reactor, where it reacts with the CO 2  and SO 2  toform calcium carbonate (CaCO 3 ) and calcium sulfate (CaSO 4 )at a high temperature between 450 and 650  ° C. Thermodynamiclimitations prevent greater than 90% CO 2  removal from a coalcombustion flue gas stream at temperatures greater than 650 ° C. The CaO sorbent could be obtained from such precursorsas natural limestone, hydrated lime, and re-engineered andsupported sorbents, while Ca(OH) 2  is obtained from CaO Figure 1.  Simplified process flow diagram for the CCR process illustrating the reaction schemes. Ind. Eng. Chem. Res., Vol. 49, No. 11, 2010  5095  hydration. The spent sorbent mixture is then regenerated bycalcining it at a high temperature between 850 and 1300  ° C,where the CaCO 3  decomposes to yield CaO and a pure, drystream of CO 2  when calcined. The calciner could be a flash orentrained bed calciner, a fluidized bed, or a rotary kiln. Whileenergy has to be provided for the calcination reaction, thecarbonation reaction is exothermic and releases high-qualityheat. Hence, a good heat integration strategy aids in reducingthe parasitic energy consumption of the process. With Ca(OH) 2 as the sorbent, the CaO is further reactivated by hydration andrecirculated to the carbonator, while the CO 2  is compressed andtransported for sequestration. Since CaSO 4  begins to decomposeonly at temperatures greater than 1450  ° C under the conditionsexperienced in the calciner, CaSO 4  is stable and a small amountof solids must be continuously purged out of the system toprevent complete conversion of sorbent to CaSO 4 . The amountof solid purge from the CCR process will depend on the amountof sulfur and fly ash that are fed to the carbonator to preventthe accumulation of inert solids in the process. On the basis of a preliminary economic analysis, the purge percentage will bein the range of 2 - 10%. Thus, the CCR process captures CO 2 in the flue gas stream and converts it into a concentratedsequestration-ready CO 2  stream. The CCR process is capableof capturing CO 2  from flue gas streams produced from variousfuels including coal, oil, natural gas, biomass, etc. Experimental SectionChemicals.  In order to generate a flue gas stream, ap-proximately 20 pounds per hour (pph) of coal and 3 actual cubicfeet per minute (acfm) of natural gas were cofired in anunderfeed stoker. High-sulfur, stoker-grade coal was obtainedfrom the Sands Hill Coal Co. located in Hamden, Ohio. Theproximate and ultimate analysis of the coal are shown in Tables1 and 2. To maintain the flue gas temperature between 450 and650  ° C, a small volume of natural gas was cofired with thecoal. This is necessary only to obtain the proper temperatureprofile of the flue gas in the 120 KWth facility. The natural gasis provided by Columbia Gas, and its general composition isprovided in Table 3. 57 Two types of sorbents were tested: commercial-grade, high-calcium calcium hydroxide and commercial-grade, high-calciumcalcium oxide. Both sorbents were obtained from Graymont.During cyclic studies the calcined sorbent was reactivated usingoffline hydration for every cycle. Table 4 lists an approximatechemical composition for Graymont ground lime and Graymontcalcium hydroxide, as provided by the manufacturer. Test Facility.  Once-through testing of sorbents and cyclicaltesting of calcium hydroxide (Ca(OH) 2 ) were both conductedat a 120 KWth subpilot-scale facility at The Ohio StateUniversity. Figure 2.  Process flow diagram of the CCR process. Table 1. Proximate Analysis of Stoker-Grade Coal proximate analysis wt % wt % (dry basis)moisture 6.065ash 7.036 7.49volatile matter 38.626 41.12fixed carbon 48.273 51.39BTU/lb 13 311MAF BTU/lb 14 389 Table 2. Ultimate Analysis of Stoker-Grade Coal ultimate analysis wt % (dry basis)carbon 73.91hydrogen 4.79nitrogen 1.43chlorine 0.00sulfur, total 3.73ash 7.49oxygen (difference) 8.65 Table 3. Composition of Natural Gas component chemical formula volume percentagemethane CH 4  93.1ethane C 2 H 6  3.2propane C 3 H 8  0.7 n -butane C 4 H 10  0.4carbon dioxide CO 2  1.0nitrogen N 2  1.6BTU/ft 3 at 1 atm 1032 5096  Ind. Eng. Chem. Res., Vol. 49, No. 11, 2010  Coal was stored in a coal hopper, which is connected to anunderfeed stoker, provided by Babcock & Wilcox Co., Barber-ton, OH. The underfeed stoker has two forced draft (FD) fansthat provide combustion air to the stoker. Natural gas isconnected to the inlet of the stoker for start up and to maintaingas temperature. The flue gas stream is transported through theductwork via an induced draft (ID) fan. Connected to theductwork are a hopper and screw feeder, two sets of gasanalyzers, multiple temperature monitoring ports, multiplepressure measurement ports, a cyclone, and a baghouse. Figure3 illustrates a snapshot of the subpilot-scale facility. Table 5provides inlet gas concentrations, and Table 6 provides atemperature profile throughout the facility.Since a stoker produces mainly bottom ash, provision wasmade to inject fly ash into the ductwork in a few tests to studythe effect of fly ash in a typical pulverized coal power plantflue gas on the CCR process. A Schenck-Accurate low-rangevolumetric hopper and screw feeder is located downstream of the stoker and used for fly ash injection into the flue gas stream.A Schenck-Accurate midrange volumetric hopper is the mainsorbent feeder and connected to the calciner feed inlet. Anelectrically heated rotary calciner manufactured by FEECO thathas a maximum operating temperature of 980  ° C is used tocalcine the spent calcium sorbent. The calcined sorbent washydrated offline for the data reported in this study and injectedinto the flue gas duct. Once injected into the ductwork, thesorbent is entrained by the flue gas and simultaneously reactswith the CO 2  and SO 2  present in the flue gas. At the end of theprocess, a Donaldson Torit downflow baghouse is used toseparate the solid sorbent from the CO 2  /SO 2  free flue gas, whichis emitted to the outside atmosphere.To monitor the gas composition, two sets of gas analyzersare employed. One set of gas analyzers is located upstream of the sorbent injection port and used as the baseline. The otherset of gas analyzers is located downstream of the sorbentinjection. The difference, after correcting for air in leakage andother factors, between the two measurements determines thepercent removal. The gas analyzers are CAI 600 analyzers andcontinuously monitor the concentrations of CO 2 , SO 2 , and CO.In addition, a CAI NOxygen analyzer monitors the upstreamoxygen and nitrogen oxides concentrations, while a TeledyneAnalytical 3000P analyzer monitors the downstream oxygenconcentration. All data are continuously recorded via a dataacquisition system. Multiple Type K thermocouples continu-ously monitor the temperature throughout the entire system todetermine the proper operating temperature for the carbonationreaction, which occurs at a reasonable rate between 450 and650  ° C. 20,35,36,58,59 Operating Procedures.  Prior to each experimental run, allanalyzers were calibrated. The stoker was heated and operatedaccording to the start-up procedures. The flue gas temperatureat the sorbent injection location reached approximately 650  ° C,which is sufficiently high to allow both the carbonation andthe sulfation reactions to proceed at a high rate and achievegreater than 90% removal of the CO 2 . The flow rate of thesorbent was set via the control panel. After the sorbent reactedwith the CO 2  and SO 2  in the carbonator, the gas temperaturewas lowered and the spent sorbent was collected in thebaghouse. To calcine the spent sorbent, the calciner temperaturewas set to 950  ° C and the calcined solids were then reactivatedusing offline hydration. The carbonation - calcination - hydrationcycle was repeated.At the completion of each experiment, solids from thebaghouse were collected and analyzed via a thermogravi-metric analyzer (TGA) and the data from the gas analyzerswas also analyzed. The CO 2  and SO 2  capture data obtainedfrom the gas analyzers were in good agreement with CO 2 and SO 2  capture obtained from the solids analysis. Results and Discussion Parameters investigated include effect of fly ash, sorbent type,calcium:carbon (Ca:C) mole ratio, and residence time. The cyclictests were conducted to determine the effectiveness of sorbentreactivation through hydration. Effect of Fly Ash.  In a pulverized coal-fired boiler, 70% - 80%of the ash from the coal is entrained as fly ash. 60 The effect of fly ash on the combined carbonation and sulfation reaction wasdetermined by injecting fly ash into the flue gas in single-cycletests. The CO 2  and SO 2  removals obtained with fly ash injection Figure 3.  Snapshot of the subpilot-scale facility of the CCR processintegrated with a coal-fired combustor. Table 4. Composition of Solid Sorbents Tested component Graymont calcium hydroxide Graymont calcium oxideCaO min 72.0% min 94.0%MgO min 0.4% min 0.5%CaCO 3  max 1.1%MgCO 3 Table 5. Flue Gas Inlet Conditions component concentrationNO  x   350 ppmO 2  4.5% vol.CO 10 ppmCO 2  12.5% vol.SO 2  1450 ppm Table 6. Flue Gas Temperature Profile location temperature ( ° C)stoker 1000fly ash injection 850carbonator/sulfator 650 - 450baghouse  < 70 Table 7. Effect of Fly Ash Injection on CO 2  and SO 2  Removal sorbentCa:C moleratiofly ash feed PPH(ash:C pound ratio)average CO 2 removal (%)average SO 2 removal (%)calciumhydroxide0.6 4.9 (0.27) 42 - 50  ∼ 100calciumhydroxide0.7 0 40 - 50  ∼ 100 Ind. Eng. Chem. Res., Vol. 49, No. 11, 2010  5097  were compared with results obtained without fly ash injection.The results, shown in Table 7, indicate that fly ash does nothave an effect on the CO 2  or SO 2  removals in the CCR process.The accumulation of fly ash in the circulating solid stream willbe prevented by maintaining an adequate sorbent purge whichwill depend on the amount of fly ash entering the carbonator. Effect of Sorbent Type and Ca:C Ratio.  Two sorbent typeswere tested in single-cycle experiments, viz. (i) Graymont high-calcium calcium hydroxide and (ii) Graymont high-calcium lime.Three different particle size distributions for Graymont high-calcium lime were used and are classified by particle D 50 . Thelime included (i) Graymont ground lime, (ii) Graymont pulver-ized ground lime, and (iii) Graymont pulverized lime. TheGraymont ground lime and Graymont pulverized lime were bothprocured from Graymont Lime and Stone. The Graymontpulverized ground lime was obtained by reducing the groundlime particle size distribution (PSD) using a Quadro-Comilmodel 197 particle grinder. Figure 4 shows the PSD for thefour sorbents. The Graymont pulverized lime and Graymont Figure 4.  Particle size distribution for (a) calcium hydroxide, (b) Graymont pulverized lime, (c) Graymont pulverized ground lime, and (d) Graymont groundlime. Table 8.  D 50 , by Mass, of Sorbents Tested sorbent  D 50  (  µ m)calcium hydroxide 3pulverized lime 18pulverized ground lime 300ground lime 600 Figure 5.  Effect of Ca:C mole ratio on CO 2  removal for multiple sorbentsat a relative residence time of 1 and carbonation temperature of   ∼ 500 ° C. Figure 6.  Effect of sorbent and Ca:C mole ratio on SO 2  removal at a relativeresidence time of 1 and carbonation temperature of   ∼ 500  ° C. 5098  Ind. Eng. Chem. Res., Vol. 49, No. 11, 2010
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