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Pilot Plant Studies of the CO2 Capture Performance of Aqueous MEA and Mixed MEA/MDEA Solvents at the University of Regina CO2 Capture Technology Development Plant and the Boundary Dam CO2 Capture Demonstration Plant Raphael Idem,* Malcolm Wilson, Paitoon Tontiwachwuthikul, Amit Chakma,† Amornvadee Veawab, Adisorn Aroonwilas, and Don Gelowitz International Test Centre for CO2 Capture (ITC), Faculty of Engineering, UniVersity of Regina, Regina, Saskatchewan, Canada S4S 0A2, and Department of Chemical Engineering, UniVersity of Waterloo, Waterloo, Ontario, Canada N2L 3G1
Evaluations of the benefits of using a mixed MEA/MDEA solvent for CO2 capture in terms of the heat requirement for solvent regeneration, lean and rich loadings, CO2 production, and solvent stability were performed by comparing the performance of aqueous 5 kmol/m3 MEA with that of an aqueous 4:1 molar ratio MEA/MDEA blend of 5 kmol/m3 total amine concentration as a function of the operating time. The tests were performed using two pilot CO2 capture plants of the International Test Centre for CO2 Capture (ITC), which provided two different sources and compositions of flue gas. The University of Regina CO2 plant (UR unit) processes flue gas from the combustion of natural gas while the Boundary Dam CO2 plant (BD unit) processes flue gas from a coal-fired electric power station. The results show that a huge heat-duty reduction can be achieved by using a mixed MEA/MDEA solution instead of a single MEA solution in an industrial environment of a CO2 capture plant. However, this benefit is dependent on whether the chemical stability of the solvent can be maintained. 1. Introduction Postcombustion capture of carbon dioxide (CO2) is undoubtedly the technology for mitigating greenhouse gas (GHG) emissions from existing fossil fuel-fired electric power plants. It is also one of the technologies that can supply huge amounts of CO2, one of the flooding agents used for enhanced oil recovery. One of the most attractive methods to achieve this goal for such dilute and low-pressure CO2 sources is absorption with chemical reaction using aqueous alkanolamine solutions. A wide variety of alkanolamines such as monoethanolamine (MEA), diethanolamine (DEA), di-2-propanolamine (DIPA), and methyldiethanolamine (MDEA) exists, and some have been used industrially for a number of years.1 There are differences in their performance in CO2 absorption using packed columns. The first difference pertains to their reactivities or rates of CO2 absorption. Primary and secondary amines such as MEA and DEA are very reactive and thus are able to effect a high volume of acid gas removal at a fast rate.2 The second is that primary and secondary amines have the limitation that their maximum CO2 loading capacity based on stoichiometry is at best 0.5 mol CO2/mol amine, unlike tertiary amines such as MDEA, which have an equilibrium CO2 loading capacity that approaches 1.0 mol CO2/mol amine. The third is that stripping of CO2 from MEA or DEA during solvent regeneration requires a large amount of energy input as compared to MDEA. It is widely known that the heat duty for solvent regeneration can constitute up to 70% of the total operating costs in a CO2 capture plant. Other operating concerns involve solvent corrosiveness and solvent chemical instability to which, studies have suggested, primary and secondary amines are more prone than tertiary amines. * To whom correspondence should be addressed. E-mail:
[email protected]. Fax: (306) 585-4855. † University of Waterloo.
Mixed amines have been reported to maximize the desirable qualities of the individual amines.3 Thus, the specific goal with respect to the use of mixed amines is to have a solution consisting of tertiary and primary amines or tertiary plus secondary amines that, in comparison with single amine systems, retains much of the reactivity of primary or secondary amines at similar or reduced circulation rates but offers low regeneration costs similar to those of tertiary amines.2 Consequently, by blending a primary or secondary alkanolamine with a tertiary alkanolamine, bulk CO2 removal is easily accomplished while regeneration energy costs are minimized. In addition, another degree of freedom (the amine concentration) is gained. The amine concentration can be altered to achieve precisely the desired separation for a given process. Substantial reductions in energy requirements and modest reduction in circulation rates have been reported for amine blends relative to the corresponding single amine system of similar total amine concentration.4 Also, simulation studies have shown that, for CO2 loadings below 0.5 mol/mol amine, MDEA + MEA and MDEA + DEA blends containing 2 kmol/m3 of each amine produced an equilibrium partial pressure of the amine blend that is intermediate between those of the corresponding single amine systems of equivalent total amine concentration.5 For higher CO2 loadings, the equilibrium partial pressures in blended amine systems were less or comparable with those of single amine systems. Furthermore, experiments on CO2 solubility in aqueous blends of MEA + MDEA and DEA + MDEA have confirmed that equilibrium solution loading is influenced most by the blended compositions under conditions that are typical of industrial regenerators.6,7 Most of these studies have been performed using laboratory scale experimentation or software simulation with simulated flue gas where the effects of other components of real flue gas including fly ash (SiO2, Al2O3, Fe2O3, CaO, MgO, Na2O, K2O, and P2O5), sulfur dioxide (SO2), and oxides of nitrogen (NOx), such as from a coal-fired power plant, are not accounted for.
10.1021/ie050569e CCC: $33.50 © 2006 American Chemical Society Published on Web 08/06/2005
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Also, a corrosion inhibitor is usually added to the solvent in industrial operations in order to minimize equipment corrosion caused by the operating environment. It is necessary to evaluate how this industrial operating environment will affect the performance of mixed amines (in terms of heat requirement for solvent regeneration, lean and rich loading, CO2 production, and solvent stability) if the advantages of mixed amines are to be exploited for field applications. In the present study, these evaluations were performed by comparing the performance of aqueous 5 kmol/m3 MEA with that of an aqueous 4:1 molar ratio MEA/MDEA blend of 5 kmol/m3 total amine concentration as a function of the operating time. The tests were performed using two pilot CO2 capture plants of the International Test Centre for CO2 Capture (ITC), which provided two different sources and compositions of flue gas as well as two different modes of solvent regeneration. These results are presented in this paper. 2. Experimental Section 2.1. Chemicals. Concentrated MEA and MDEA (commercial grade, 99% purity) were obtained from Prairie Petro-Chem, Estevan, Saskatchewan, Canada. These solvents were diluted with distilled water to the desired concentrations. 2.2. Testing Facilities. The International Test Centre for CO2 Capture (ITC) has two major testing facilities: (i) a semicommercial CO2 capture demonstration plant adjacent to the SaskPower’s Boundary Dam power station (BDPS) and (ii) a technology development pilot plant located at the University of Regina. 2.2.1. Boundary Dam Subcommercial Technology Demonstration Plant. The subcommercial technology demonstration unit at the Boundary Dam (BD unit), first built in the summer of 1987 at the site of the Saskatchewan Power Corporation’s (SaskPower’s) Boundary Dam power station, the largest lignite coal-burning station in Canada, processes flue gas from a coalfired electrical power plant. The BD unit was designed to process 500 000 SCFD of flue gases from the Boundary Dam power station and capture up to 4 tons of CO2 per day. The CO2 demonstration pilot plant at BDPS is considered to be the only one of an appropriate size to develop the engineering data required for design of commercial facilities. The Boundary Dam pilot plant consists of three main components that are connected in series as follows: (i) a highefficiency baghouse unit for fly ash removal, (ii) an Anderson 2000 scrubbing unit for removal of SO2, and (iii) an aminebased CO2 capture unit. The CO2 absorption is based on the reaction of a weak base (alkanolamine) with a weak acid (CO2) to produce a water soluble salt. The reaction is reversible and temperature dependent. The removal of CO2 from flue gas is achieved by contacting the feed flue gas in an amine absorber (18 in. in diameter) with an aqueous solution of alkanolamine at a low temperature, whereby the CO2 chemically binds to the amine and thus is removed from the flue gas stream. The CO2 is then liberated from the CO2-rich amine solution by elevated temperature to reverse the absorption reaction. The elevated temperature is supplied by stripping steam in the amine regenerator (16 in. in diameter). The regenerated CO2-lean amine solution is then cooled and recycled to the amine absorber for further CO2 removal. In contacting the flue gas, the amine solution may become contaminated by the formation of degradation products generated from side reactions and the collection of insoluble material, such as pipe scale and fly ash. The conversion of degradation products back to amine and the removal of solid impurities are accomplished by the amine
reclaimer. Also, the pilot plant is equipped with the following analytical facilities: (i) a continuous on-line SO2 and O2 analyzer located downstream of the Anderson 2000 SO2 scrubber, (ii) an on-line analyzer for CO2 concentration along the side of the CO2 absorption column, (iii) a data-logging system installed to retrieve and transmit the process temperature and pressure data to the control room, (iv) local gauges and routine manual logs used for the daily operation of plant facilities, and (v) a corrosometer and electrochemical probes installed to continuously monitor the short-term and long-term corrosion rates at various points in the plant. These points included downstream of the Anderson 2000 SO2 scrubber, the amine absorber bottom, downstream of the feed gas cooler, the hot rich amine solution to regenerator, the amine reboiler, the regenerator overhead, the amine reclaimer, and the regenerator bottom. The corrosometer (model RCS-8) and electrochemical probe (model 2500) were obtained from Rohrback Csasco Systems, Santa Fe, CA. A process flow diagram for the BD unit is given in Figure 1. 2.2.2. Technology Development Pilot Plant at UR. The University of Regina technology development pilot plant processes up to 4.8 × 103 m3/day of flue gas and captures up to 1 ton of CO2 per day. Figure 2 shows a process flow diagram of the UR pilot plant. As seen in the figure, the UR pilot plant consists of three main units connected in series as follows: (i) a flue gas generation/pretreatment unit, (ii) an absorption-based unit for CO2 capture, and (iii) a postconditioning unit for product purification. A steam boiler (250 kW) is the heart of the flue gas generation/pretreatment unit, producing both flue gas and high-quality steam for the CO2 capture unit. Also in the same unit is a 30 kW micro-gas-turbine connected to the steam boiler. The configuration is designed such that the boiler can operate on its own or in conjunction with the micro-gas-turbine. When operating the microturbine, a low CO2 concentration feed is produced; therefore, the boiler is operated as a duct burner to enrich the CO2 concentration of the flue gas while consuming the high excess O2 content from the turbines exhaust. The CO2 capture unit design is based on the gas absorption technology using amine solvent. Here, CO2 is removed from the preconditioned flue gas in one of the three absorption columns and high quality CO2 stream is released from a solvent regenerator, operated at an elevated temperature. Each absorption column is composed of three 0.3 m-diameter sections for a total height of 10 m and is also equipped with a series of temperature sensors and gas sampling points at a regular interval of 0.6 m to allow measurements of the temperature and gas-phase CO2 concentration during testing. In the postconditioning unit, the CO2 product from the solvent regenerator is treated in a CO2-wash scrubber. An independent chiller is used to provide the cooling medium in order to cool the CO2 gas to the desired temperature of 4 °C. From here, the CO2 product can either exit back to the atmosphere or pass through a dryer and purification unit for further treatment to meet food-grade specifications. The UR technology development pilot plant is considered to be one of the best testing facilities, equipped with a state-ofthe-art process control/instrumentation and data acquisition system called DeltaV. This system has allowed us to control, monitor, and record a complete spectrum of process operating conditions including temperature, flow rate, CO2 removal efficiency, CO2 production rate, and, more importantly, energy consumption for CO2 capture. These data can be retrieved from the historical database and saved in a spreadsheet format for detailed analysis. A control room was constructed in the building to house the control system computers.
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Figure 1. Process flow diagram of the Boundary Dam CO2 capture demonstration plant.
2.3. Feed to the Absorption Plants. 2.3.1. Boundary Dam Subcommercial Technology Demonstration Plant. Flue gas from the coal-fired power station provides a plentiful supply of CO2 but at the same time contains fly ash, oxygen (O2), and trace contaminants such as sulfur dioxide (SO2) and nitrogen dioxide (NO2) which are undesirable to the amine treating unit. Flyash is the fine solid component in the flue gas typically composed of SiO2, Al2O3, Fe2O3, CaO, MgO, Na2O, K2O, and P2O5. The presence of fly ash in a gas stream results in a number of operational difficulties. It can deposit or cake on the process equipment, thereby blocking flow, wrenching pumps and pump seals, and clogging equipment and instrumentation. Most of the fly ash is usually removed from the flue gas before it is discharged to the atmosphere through the flue stack. For the contaminated gases, oxygen in the flue gas originates as excess combustion air in the boiler and SO2 and NO2 are the combustion products of sulfurous and nitrogen compounds in the coal. The residual fly ash is removed in a high efficiency baghouse, which consists of 36 composite filter bags housed by a structure complete with a hopper bottom for dust collection and removal. The structure is heat traced and insulated to withstand extreme climate variances and to maintain a temperature above the sulfur dew point on the baghouse walls. The bags are cleaned using blasts of air via solenoids controlled by an electronic control panel that measures pressure differential across the bags. SO2 is removed by scrubbing in an Anderson 2000 unit, which is a two-stage wet-scrubbing system that uses sodium sulfite (Na2SO3) as an aqueous absorbent for SO2 removal. The primary reaction product is sodium bisulfite (NaHSO3). When sodium
hydroxide (NaOH) is added to the system as a makeup reagent, it converts the NaHSO3 product back to Na2SO3 for further SO2 removal. The amine extraction unit treats the preconditioned flue gas from the Anderson 2000 unit. The flue gas is virtually free of fly ash but may contain some (
