(CCR) Process - ACS Publications - American Chemical Society

(CCR) Process - ACS Publications - American Chemical Societypubs.acs.org/doi/pdf/10.1021/ie901509kSimilarby W Wang - ‎...

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Ind. Eng. Chem. Res. 2010, 49, 5094–5101

Subpilot Demonstration of the Carbonation-Calcination Reaction (CCR) Process: High-Temperature CO2 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 AVenue, 125 A Koffolt Laboratories, The Ohio State UniVersity, Columbus, Ohio 43210

Increasing concerns over growing CO2 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-Calcination Reaction (CCR) process, which utilizes a calcium-based sorbent in a high-temperature reaction (carbonation) to capture the CO2 from the flue gas stream and releases a pure stream of CO2 in the subsequent calcination reaction that can be sequestered. A 120 KWth subpilot-scale combustion plant utilizing coal at 20 pph along with natural gas has been established at The Ohio State University to test the CCR process. Experimental studies on CO2 capture using calcium-based sorbents have been performed at this facility. Greater than 99% CO2 and SO2 capture has been achieved at the subpilot-scale facility on a once-through basis at a Ca:C mole ratio of 1.6. In addition, the sorbent reactivity is maintained over multiple cycles by the incorporation of a sorbent reactivation hydration step in the carbonation-calcination cycle. Introduction Since the Industrial Revolution, atmospheric CO2 concentrations have steadily increased from 280 ppm (ppm) to its current value of 385 ppm, representing an increase of 35%.1–3 This is mainly due to the unabated emission of CO2 as a result of increasing consumption of fossil fuels such as coal, oil, and natural gas. Point sources, which contribute more than onethird of all anthropogenic CO2 emissions,4 are candidates for implementing CO2 reduction practices due to the relatively high concentration and quantity of CO2 emitted. High fossil fuel consumption per year leads to high CO2 emissions at these large point sources due to their dominant use in electricity generation.5 In the United States, approximately one-third of all CO2 emissions is derived from coal combustion for electricity production, which accounts for nearly one-half of the total electricity generation.6,7 Worldwide, coal combustion is responsible for 42% of the CO2 emissions while providing 41% of the electricity generated.8 Due to the significant CO2 emissions output by fossil fuel power plants, a concerted, worldwide effort is ongoing to develop economical CO2 capture systems from fossil fuel-fired power plants. Comprehensive CO2 management scenarios involve a threestep process that includes separation, transportation, and safe sequestration of CO2. Economic analysis has shown that CO2 separation accounts for 75-85% of the overall cost associated with carbon sequestration.9 Since 99% of all coal-fired power plants in the United States are pulverized coal plants, there is a clear necessity to develop a postcombustion CO2 separation process.10 Currently, though, very few commercial-scale technologies exist for effectively capturing CO2. Further complicating CO2 capture processes is the existence of several additional species in flue gas, which include water * To whom correspondence should be addressed. Tel.: (614)-6883262. Fax: (614)-292-3769. E-mail: [email protected] † Current address: Dow Chemical Company, Freeport, 2301 N. Brazosport Blvd., Freeport, Texas 77541-3257. ‡ Current address: Shell Global Solutions (US) Inc., 3333 Highway 6 S, Houston, TX 77082. § The Babcock & Wilcox Power Generation Group, Barberton, OH 44203.

vapor, oxygen, sulfur oxides, nitrogen oxides, and ash. Regulations currently exist for sulfur dioxide emissions, and any carbon capture process must not violate the existing regulation of 1.2 lb SO2 per million BTU.11 Several technologies have been developed for postcombustion SO2 control. Worldwide, 87% of installed SO2 control technologies use a wet process with 97% using a calcium-based sorbent. The other main technology injects a dry sorbent into the flue gas stream, where the sorbent is still predominantly calcium based.12,13 The most mature and commercially ready technology is aminebased scrubbing. While monoethanolamine (MEA) has the ability to effectively remove greater than 90% of the CO2 in a flue gas stream, the cost of electricity would increase by a minimum of 80% while decreasing power plant efficiency by 30%.14 Further hampering MEA as a CO2 removal process from a coal combustion flue gas stream is its incompatibility with flue gas components. Reports suggest SO2 concentrations must be maintained below 10 ppm to prevent significant solvent deactivation, which requires greater than 98% SO2 removal for even the lowest sulfur coals.15,16 Oxygen and particulates are also known to cause performance issues with the amine solvents.15,16 The dilute CO2 concentration in the flue gas complicates the CO2 separation. By replacing combustion air with oxygen, in a process know as oxy-combustion, a highly concentrated CO2 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 oxycombustion on a 30 MWth boiler.17 Although air separation units (ASUs) are commercially available, several challenges associated with oxy-combustion still exist. They include air infiltration, which dilutes the CO2 flue gas stream, the energy consumption of the ASU, which arises from the use of cryogenic distillation, and the overall economics of oxy-combustion, with estimates 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 CO2/g of adsorbent.18 Adsorbents such as high surface area activated carbon can achieve 0.0657 g of CO2/g of adsorbent.18 Mem-

10.1021/ie901509k  2010 American Chemical Society Published on Web 02/17/2010

Ind. Eng. Chem. Res., Vol. 49, No. 11, 2010


Figure 1. Simplified process flow diagram for the CCR process illustrating the reaction schemes.

branes for separating CO2 from a flue gas stream have potential for commercial-scale applicability. Currently, however, membranes lack the durability to withstand the temperatures and flue gas components, selectivity, and reliability. Operational temperatures for membranes are currently below 100 °C, but the minimum exit temperature of the flue gas is above 120 °C in order to prevent acid gas corrosion.18,19 Separation technologies based on absorption, adsorption, membrane separation, and cryogenic separation necessitate a low temperature and/or high pressure of flue gas to enhance the CO2 sorption capacity of the sorbent/solvent or the diffusion flux of CO2 through the membrane. However, flue gas is typically characterized by subatmospheric pressure and high temperature. Metal oxides are capable of reacting with CO2 under existing flue gas conditions, thereby reducing downstream process modifications. We detailed elsewhere the advantages of a high-temperature reactive separation process based on the carbonation and calcination reactions of CaO to separate CO2 from flue gas.20–22 The key advantage offered by this process is the enhanced CO2 sorption capacity (0.35-0.70 g of CO2/g of CaO) exhibited by the high-reactivity CaO particles under existing flue gas conditions over multiple cycles of CCR. CO2 Capture Using Calcium Sorbents. The concept of utilizing lime for CO2 capture has existed for well over a century. It was first introduced by DuMotay and Marechal in 1869 for enhancing the gasification of coal using lime.23 CONSOL’s CO2 acceptor process was then developed and tested in a 40 tons/day plant.24 A variation of this process called the HyPr-RING process was developed in Japan for the production of hydrogen at high pressures.25 Shimizu et al. (1999) conceptually designed a process that uses twin fluidized bed reactors for capturing CO2 from a coal combustion power plant.26 The calcium-based looping process has also been applied to the production of hydrogen both from syngas by the water-gas shift reaction and methane by the sorption-enhanced steam methane reforming reaction.27–31 The regenerability of the calcium oxide (CaO) sorbent has been the major drawback of high-temperature calcium-based CO2 capture processes. CaO sorbents are prone to sintering during the high-temperature regeneration step. Over multiple cycles, the percentage of sintered CaO progressively increases and reduces the CO2 capture capacity of the sorbent.24,32–39 Due to sintering, higher solid circulation or makeup rates need to

be used to maintain a high level of CO2 removal.40 Pretreatment methods have been developed to reduce the decay in reactivity, which involve hydration of the sorbent,35,41–44 preheating and grinding of the sorbent,45 and synthesis of novel sorbents by physical or chemical modification of the precursor.20,44,46–49 Addition of a sorbent reactivation step as a part of the carbonation-calcination cycle has also been proposed to reverse the effect of sintering during each cycle and thus maintain the sorbent reactivity.50,51 This paper outlines the process concept and details the experimental data for the simultaneous capture of CO2 and SO2 from combustion flue gas streams using the CarbonationCalcination Reaction (CCR) process.21,22,50,52 The CCR process is an outgrowth of two other processes developed at The Ohio State University: the Ohio State Carbonation Ash Reactivation (OSCAR) process53–56 and Calcium-based Reaction Separation for CO2 (CaRS-CO2) process.22 The OSCAR process involves the use of novel calcium-based sorbents for sulfur and trace heavy metal (arsenic, selenium, and mercury) capture in the furnace sorbent injection (FSI) mode. A pilot-scale study of the OSCAR process showed successful scale up of sorbent synthesis and superior extents of capture of sulfur, arsenic, selenium, and mercury from flue gas.54 The CaRS-CO2 process involves the capture of CO2 and SO2 from a multicomponent gas stream using high-reactivity, regenerable calcium-based sorbents.22 The CCR process uses a regenerable calcium-based sorbent with sorbent reactivation by hydration50 as a step in the carbonationcalcination cycle to prevent the decay in sorbent reactivity over multiple cycles. The CCR process has been demonstrated at a 120 KWth subpilot scale facility at The Ohio State University using flue gas from a stoker boiler. Process Scheme. Figure 1 depicts the schematic of the CCR process with various reaction schemes, and Figure 2 illustrates the overall process flow diagram of the CCR process. The CaO or Ca(OH)2 sorbent is injected into the carbonator, which is an entrained bed reactor, where it reacts with the CO2 and SO2 to form calcium carbonate (CaCO3) and calcium sulfate (CaSO4) at a high temperature between 450 and 650 °C. Thermodynamic limitations prevent greater than 90% CO2 removal from a coal combustion flue gas stream at temperatures greater than 650 °C. The CaO sorbent could be obtained from such precursors as natural limestone, hydrated lime, and re-engineered and supported sorbents, while Ca(OH)2 is obtained from CaO


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Figure 2. Process flow diagram of the CCR process.

hydration. The spent sorbent mixture is then regenerated by calcining it at a high temperature between 850 and 1300 °C, where the CaCO3 decomposes to yield CaO and a pure, dry stream of CO2 when calcined. The calciner could be a flash or entrained bed calciner, a fluidized bed, or a rotary kiln. While energy has to be provided for the calcination reaction, the carbonation reaction is exothermic and releases high-quality heat. Hence, a good heat integration strategy aids in reducing the parasitic energy consumption of the process. With Ca(OH)2 as the sorbent, the CaO is further reactivated by hydration and recirculated to the carbonator, while the CO2 is compressed and transported for sequestration. Since CaSO4 begins to decompose only at temperatures greater than 1450 °C under the conditions experienced in the calciner, CaSO4 is stable and a small amount of solids must be continuously purged out of the system to prevent complete conversion of sorbent to CaSO4. The amount of solid purge from the CCR process will depend on the amount of sulfur and fly ash that are fed to the carbonator to prevent the accumulation of inert solids in the process. On the basis of a preliminary economic analysis, the purge percentage will be in the range of 2-10%. Thus, the CCR process captures CO2 in the flue gas stream and converts it into a concentrated sequestration-ready CO2 stream. The CCR process is capable of capturing CO2 from flue gas streams produced from various fuels including coal, oil, natural gas, biomass, etc. Experimental Section Chemicals. In order to generate a flue gas stream, approximately 20 pounds per hour (pph) of coal and 3 actual cubic feet per minute (acfm) of natural gas were cofired in an underfeed stoker. High-sulfur, stoker-grade coal was obtained from the Sands Hill Coal Co. located in Hamden, Ohio. The proximate and ultimate analysis of the coal are shown in Tables 1 and 2. To maintain the flue gas temperature between 450 and 650 °C, a small volume of natural gas was cofired with the coal. This is necessary only to obtain the proper temperature profile of the flue gas in the 120 KWth facility. The natural gas is provided by Columbia Gas, and its general composition is provided in Table 3.57

Table 1. Proximate Analysis of Stoker-Grade Coal proximate analysis

wt %

moisture ash volatile matter fixed carbon BTU/lb MAF BTU/lb

6.065 7.036 38.626 48.273

wt % (dry basis) 7.49 41.12 51.39 13 311 14 389

Table 2. Ultimate Analysis of Stoker-Grade Coal ultimate analysis

wt % (dry basis)

carbon hydrogen nitrogen chlorine sulfur, total ash oxygen (difference)

73.91 4.79 1.43 0.00 3.73 7.49 8.65

Table 3. Composition of Natural Gas component

chemical formula

volume percentage

methane ethane propane n-butane carbon dioxide nitrogen BTU/ft3 at 1 atm

CH4 C2H6 C3H8 C4H10 CO2 N2

93.1 3.2 0.7 0.4 1.0 1.6 1032

Two types of sorbents were tested: commercial-grade, highcalcium calcium hydroxide and commercial-grade, high-calcium calcium oxide. Both sorbents were obtained from Graymont. During cyclic studies the calcined sorbent was reactivated using offline hydration for every cycle. Table 4 lists an approximate chemical composition for Graymont ground lime and Graymont calcium hydroxide, as provided by the manufacturer. Test Facility. Once-through testing of sorbents and cyclical testing of calcium hydroxide (Ca(OH)2) were both conducted at a 120 KWth subpilot-scale facility at The Ohio State University.

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Figure 3. Snapshot of the subpilot-scale facility of the CCR process integrated with a coal-fired combustor. Table 4. Composition of Solid Sorbents Tested component

Graymont calcium hydroxide

Graymont calcium oxide


min 72.0% min 0.4% max 1.1%

min 94.0% min 0.5%

Table 5. Flue Gas Inlet Conditions component



350 ppm 4.5% vol. 10 ppm 12.5% vol. 1450 ppm

Table 6. Flue Gas Temperature Profile location

temperature (°C)

stoker fly ash injection carbonator/sulfator baghouse

1000 850 650-450