ARTICLE pubs.acs.org/EF
Post-combustion Capture of CO2: Results from the Solvent Absorption Capture Plant at Hazelwood Power Station Using Potassium Carbonate Solvent Kathryn A. Mumford,† Kathryn H. Smith,† Clare J. Anderson,† Shufeng Shen,† Wendy Tao,† Yohanes A. Suryaputradinata,† Abdul Qader,† Barry Hooper,† Renato A. Innocenzi,‡ Sandra E. Kentish,† and Geoffrey W. Stevens*,† †
Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), Department of Chemical and Biomolecular Engineering, The University of Melbourne, Parkville, Victoria 3010, Australia ‡ International Power Hazelwood, Melbourne, Victoria 3000, Australia ABSTRACT: Post-combustion capture of CO2 from flue gas generated in a 1600 MW brown-coal-fired power station has been demonstrated using a solvent absorption process. The plant, located at International Power’s Hazelwood power station in Victoria’s Latrobe Valley, was designed to capture up to 25 tons/day of CO2 (expandable to 50 tons/day of CO2). The design of the capture plant was based on a proprietary solvent (BASF PuraTreat F). The main focus of this work, however, is to describe the performance of the plant using an unpromoted 30 wt % potassium carbonate (K2CO3) solution. The CO2-capture plant was successfully operated using both BASF PuratTreat F and K2CO3, during which performance data were collected and analyzed. Although the plant only absorbed 2025% of CO2 from the flue gas when using the potassium carbonate solvent, valuable operating data were collected, which enabled process simulations to be compared to real plant data. Aspen Plus software was used to predict the performance of the plant while operating with potassium carbonate. In general, the model shows a slight difference (within (5%) compared to the pilotplant results. This benchmarked model is an important part of the ongoing development of novel precipitating potassium carbonate processes for large-scale post-combustion CO2 capture.
1. INTRODUCTION Solvent absorption is currently the preferred option for removing CO2 from industrial waste gas and for synthesis and natural gas purification. This process involves passing the flue gas through a liquid that can absorb CO2 (in an absorber vessel) and then release CO2 at an elevated temperature in a regenerator vessel. Hot potassium carbonate solutions have been used commercially for acid gas absorption for many years. The process is commonly known as the Benfield process1 and was originally developed by the U.S. Bureau of Mines in 1954 to reduce the costs of synthesis gas purification for the production of liquid fuel from coal. The process is designed for a gas process stream that has high temperatures and high partial pressures. Because of the high temperature and partial pressure in the absorber, it is therefore not necessary to further heat the solution to the stripping temperature required in the stripping process, rather a reduced pressure is used. This results in a lower process energy requirement and eliminates the need for heat-exchange equipment between the absorber and the regenerator columns. Furthermore, the operation at such high temperatures increases the solubility of the bicarbonate species; therefore, the Benfield process can operate with highly concentrated solutions. In more recent years, aqueous alkanolamines, such as monoethanolamine (MEA) or diethanolamine (DEA), have gained widespread attention for the capture of CO2. MEA is currently the lead technology but has several limitations. These limitations include the following: (1) Corrosion: resulting in the need for expensive materials of construction. (2) Amine degradation: high r 2011 American Chemical Society
temperatures and oxygen act to degrade the amine, reducing its capacity to remove CO2. This results in a requirement for reclaiming equipment and solvent replacement. (3) Formation of heat-stable salts: amine can react irreversibly with minor gas components, forming heat-stable salts that can lead to solvent degradation and foaming problems. (4) Solvent losses: MEA has a high vapor pressure, which can result in high solvent losses in both the absorber and regenerator. (5) MEA has a relatively high energy requirement for regenerating the solvent in the stripping column, although it is currently the cheapest solvent available. For these reasons, a significant amount of research is being conducted to examine alternative solvents and processes. Potassium carbonate has a number of advantages over the amine-based solvents, with one of the most important being that absorption can occur at high temperatures, making the regeneration process more efficient and economical. Potassium carbonate also has a low cost, is less toxic, and is less prone to degradation effects that are commonly seen with amines at high temperatures and in the presence of oxygen and other minor gas components. The biggest challenge associated with using potassium carbonate as a solvent is that it has a low rate of reaction, resulting in poor CO2 mass transfer. Promoters are often added to the solvent to Special Issue: 2011 Sino-Australian Symposium on Advanced Coal and Biomass Utilisation Technologies Received: August 4, 2011 Revised: October 16, 2011 Published: October 18, 2011 138
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Table 1. Typical Properties of Major Components in the Flue Gas Feed to the CO2-Capture Plant gas flow rate to the solvent plant (kg/h)
6400
pressure (kPag)
1
temperature (°C)
240
vapor fraction
1
Table 2. Packing Characteristics and Absorption Column Dimensions parameters
Composition
absorber
regenerator
number of packing sections
2
2
height of packing (m) diameter of packed bed (m)
7 1.5
6 1.4
packing type
Sulzer nutter
Sulzer nutter
carbon dioxide, CO2 (mol %)
13.0
nitrogen, N2 (mol %)
62.0
packing density (kg/m3)
oxygen, O2 (mol %) water, H2O (mol %)
3.5 20.5
packing surface area (m2/m3)
226
226
packing void fraction (m2/m3)
97
97
argon, Ar (mol %)
0.8
nitrate, NOx (ppmv, dry basis)
151
sulfate, SOx (ppmv, dry basis)
212
rings, steel
rings, steel 177
form of K+ ions and reaction 1 can be represented as CO2 þ CO3 2 þ H2 O h 2HCO3
improve the CO2 mass-transfer rates. Traditionally, promoters, such as piperazine,2 diethanolamine,3 and arsenic trioxide,4 have been used, but these are known to be toxic and hazardous to the environment. A number of less-toxic promoters, such as boric acid, have been used in the past and are currently being investigated for today’s applications.5,6 Post-combustion capture of CO2 using various solvent absorption processes has been implemented at a pilot scale. This is an important step toward commercializing carbon capture and storage (CCS) technology because the pilot-plant operations will provide an opportunity to gain operating experience and operating data, which can be used for the design at an industrial scale. To date, there are a number of operating CO2-capture plants using solvent absorption technology around the world. There are at least four operating post-combustion capture plants in Australia alone, including the Loy Yang and Hazelwood capture plants in Victoria’s Latrobe Valley. The Loy Yang pilot plant is designed to capture up to 1.2 tons/day of CO2 using aminebased solvents, while the Hazelwood capture plant is designed with a capacity of 50 tons/day of CO2 using amino-acid- and potassium-carbonate-based solvents. In New South Wales, the Munmorah pilot plant (capacity of 7.2 tons/day of CO2) has been operating with ammonia solvent, and in Queensland, the Tarong pilot plant has been designed to capture up to 2.4 tons/ day of CO2 using amine solutions.7 Operating post-combustion capture plants outside Australia have also been reported in China, U.S.A., and Italy. The Shidongkou project in China is a pilot CCS collaboration project between a research group in Australia (CSIRO) and China’s Huaneng Power Station. It is designed to capture up to 3000 tons/year of CO2 using amine solvents.8 A research group from The University of Texas has tested carbon capture in a pilot plant using an amine-promoted potassium carbonate solvent.9 Finally, a post-combustion pilot plant at the Brindi power station in Italy has been reported. It is designed to capture up to 8000 tons/year of CO2 using amine solvents.10
ð2Þ
Reaction 2 proceeds according to the following sequence of elementary steps: CO2 þ H2 O h HCO3 þ Hþ
ð3Þ
CO2 þ OH h HCO3
ð4Þ
H2 O h Hþ þ OH
ð5Þ
Reactions 3 and 4 are both followed by subsequent instantaneous reactions as follows: Hþ þ CO3 2 h HCO3
ð6Þ
H2 O þ CO3 2 h HCO3 þ OH
ð7Þ
The reaction sequence 3, 5, and 6 is known as the acidic mechanism.14 The contribution of the acidic mechanism to the overall rate is negligible unless the pH of the liquid solution is very low. Almost all cases of industrial absorption are performed at high pH (generally, pH > 8). Hence, the acidic mechanism can be neglected. Reaction 4 is the rate-controlling step for absorption of CO2 into hot potassium carbonate solution, while reactions 5 and 7 are instantaneous reactions.
3. MATERIALS AND METHODS 3.1. Flue Gas Conditions. The flue gas used in these trials was taken from the Hazelwood power station in Victoria’s Latrobe Valley, which is a 1600 MW brown-coal-fired power station. The operating pressure of the flue gas exiting the stack was 1 kPag, and the temperature was approximately 240 °C. Typical conditions and composition of major components in the flue gas provided to the capture plant are presented in Table 1. 3.2. Pilot-Plant Specifications. The design of absorber column in the pilot plant was based on capturing 25 tons/day of CO2 (expandable to 50 tons/day of CO2) from 6400 kg/h of flue gas using BASF Puratreat solvent. The solvent-capture plant is designed to be operated continuously and consists of three main columns: a direct contact cooler (DCC) (to cool the flue gas using cooling water), an absorber (to remove CO2 from the flue gas via dissolution into the solvent), and a regenerator (to remove CO2 from the solvent through addition of heat). The packing dimensions and properties of the absorption columns are summarized in Table 2. A process flow diagram of the process has been provided in Figure 1, and a photograph has been provided in Figure 2.
2. REACTION SYSTEM The overall reaction for the absorption of carbon dioxide using a potassium carbonate, K2CO3, solution is described as follows:1113 CO2 þ K 2 CO3 þ H2 O h 2KHCO3
177
ð1Þ
Because potassium carbonate and bicarbonate are strong electrolytes, it can be assumed that the metal is present only in the 139
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Figure 1. Process flow diagram of the solvent-capture plant.
3.3. Pilot-Plant Operational Procedures. Feed gas enters the solvent plant through the DCC, which cools the flue gas from 240 to around 45 °C. Flue gas exiting from the DCC then passes to the flue gas blower, where the pressure increases to 10 kPag. The gas then passes to the absorber, where it rises through two 7 m packing sections and is brought into contact counter-currently with a solution of lean solvent, which is sprayed into the top of the column. As the gas rises through the column, the CO2 concentration in the gas stream is progressively reduced. Rich solvent drains into the sump of the absorber before being pumped through the lean/rich heat exchanger by the rich solvent pump. The rich solvent is heated to above 107 °C via the hot lean solvent exiting the regenerator. CO2 is released from the rich solvent in the regenerator, which operates at 40 kPag. Heat for regeneration is provided via a steamheated reboiler. Lean solvent exits from the sump of the regenerator and passes through the lean/rich exchanger before being pumped through the lean solvent cooler (water cooled), which reduces the temperature to 40 °C, before being returned to the absorber. At the top of the regenerator, the vapor stream, including CO2, passes through the overhead condenser to drop the temperature to 45 °C and condense as much of the associated water vapor as possible. This stream then passes through the reflux accumulator, and the liquid is returned back to the regenerator, while the CO2 gas product travels to a compressor for use in the neutralization of ash water produced by the power plant. Water flow to the DCC is controlled by the outlet temperature of flue gas exiting the DCC. Cooling water to the overhead condenser is controlled by the temperature of the stream entering the reflux accumulator. The lean solvent cooler water flow is controlled by the temperature of the lean solvent to the absorber. To maintain solvent efficiency, antifoam and chemical reagents could be added from separate automatic dosing tanks. Heat-exchanger cooling water is circulated via a closed circuit, where it is cooled via a cooling tower. The cooled water was filtered and dosed with biocide and corrosion inhibitors to maintain water quality. Plant operational data were collected continuously while the plant was operating. Stream information, such as flow rate, pressure, and temperature,
were continuously logged online via a PLC (Allen-Bradley) connected to individual transmitters. The operational data were downloaded on a weekly basis at 1 h intervals. Rich and lean solvent samples were collected throughout the testing period from the outlet of the rich and lean solvent pumps and analyzed for solvent concentration and CO2 loading, defined as [HCO3]/[K+], via a titration technique.15 Gas samples (from the inlet and outlet of the absorber) were analyzed using a PG250 gas analyzer (Horiba, Japan), which enabled the concentration of CO2, O2, SO2, and NOx to be measured on a dry basis. The moisture content of the gas stream was measured using a HT-305 humidity meter (Lutron Electronic). The gas composition of the CO2 gas product stream exiting the regeneration process was determined using a CP-3800 gas chromatograph (Varian, Palo Alto, CA). 3.4. Simulation Method. Simulation of the CO2-capture plant was completed using Aspen Plus (version 7.1). Within Aspen Plus, the Electrolyte-NRTL (ENTRL) model was chosen for modeling the potassium carbonate solvent system because previous works have found this most appropriate. The vaporliquid equilibrium data were based on the original work completed by Tosh et al.,16 with updated binary interaction parameters by Cullinane and Rochelle.17 The liquid-phase mass-transfer coefficient was predicted using the Onda correlation,18 which is relevant for a range of packing materials, including Sulzer nutter rings. The Radfrac unit operation, which takes into account the ratelimiting step of eq 4 via a rate expression, was used to model the absorber and the regenerator columns. The reaction condition factor, which is a weighting factor used for calculating the reaction rate based on conditions at the interface or in the bulk, was determined to be 1. This was based on a Hatta number of ∼2, which implies that there is little enhancement of mass transfer because of the chemical reaction.19 The interfacial area factor was determined to be 1 because no fouling was observed in the packing. Further details on the simulation development and inputs to the simulation have been described by Smith et al.19 The inputs to the simulation from the plant data were chosen in a manner that is representative of what could be controlled on the actual plant. Therefore, the following parameters were fixed in the Aspen Plus simulation: (1) feed gas temperature, pressure, flow, and composition as 140
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Figure 2. Carbon-capture plant at Hazelwood Power Station.
level transmitters, resulted in plant shutdown for maintenance or cleaning out of equipment. Precipitation of KHCO3 in the solvent is dependent upon the solvent temperature and the CO2 loading, for a given initial concentration of K2CO3. This relationship is shown in Figure 4. The highlighted band shows the operating area, within (average) lean and rich solvent loadings of 0.17 and 0.23, respectively. The initial solvent concentration ranged from 27 to 28 wt % K2CO3, corresponding to a KHCO3 precipitation temperature of ∼5 °C. During plant operation, the solvent temperature did not reach this temperature; however, when the plant was shutdown, the overnight temperatures and, hence, solvent temperature frequently decreased to this level and KHCO3 precipitation was observed. Because the plant was not originally designed to be used with potassium carbonate, no provisions were made for items such as heat tracing at critical locations. However, precipitation was also observed to occur in the plant while operational. As such, investigations were conducted into its constituents, and it was found to be potassium sulfate. Discussion of this analysis is presented in section 4.2. 4.2. Solvent Interaction with Flue Gas Impurities. Potassium carbonate has been shown to absorb CO2, as well as both SOx and NOx.15,20 Solvent samples were regularly collected and analyzed for sulfur components via inductively coupled plasma optical emission spectroscopy (ICPOES; 720-OES, Varian, Inc.) and for nitrogen components via ion chromatography (IC; Dionex ICS-1000). It was found that a significant amount of SOx in the flue gas was removed in the DCC. The pH of the cooling water from the DCC gradually decreased to around 3.7
per the selected operating days, (2) lean solvent inlet temperature, pressure, and flow into the absorber, (3) lean solvent CO2 loading, (4) regenerator pressure and vapor overhead flow, (5) condenser outlet temperature, and (6) rich/lean heat-exchanger cold outlet temperature.
4. RESULTS AND DISCUSSION The post-combustion capture plant at Hazelwood Power Station has successfully demonstrated using potassium carbonate startup steady station operation and shutdown operation. No safety incident during operation was reported. The data collected and operating issues encountered during the testing period are discussed in the following sections. The plant results are also compared to the results derived from Aspen Plus simulations, which is useful for the process improvement in the next scale-up. 4.1. Solvent Concentration and Solvent Loading. A nominal solvent concentration of 30 wt % K2CO3 was initially used as the lean solvent in the absorber. Figure 3 shows the variation of the solvent concentration over the testing period. It can be seen that the solvent concentration decreased gradually from an initial 30 wt % to approximately 20 wt %. This dilution occurred during plant maintenance operations, i.e., cleaning of level transmitters, pump strainers, and repairs to the reboiler. There was no indication of solvent degradation. As seen from Figure 3, there does not seem to be any significant change in solvent loading because of the change in the solvent concentration. There was also no significant change in solvent loading with the solvent flow rate. Throughout the trials with potassium carbonate solvent, solid precipitation in various parts of the plant, including filters and 141
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Figure 3. Variation in the solvent loading and solvent concentration with time (using potassium carbonate solvent).
Figure 4. Solubility of bicarbonate (KHCO3) as a function of the temperature and solvent loading (Aspen Plus).
because of SOx absorption, which led to some operational problems, including internal corrosion of the DCC demister pads. SOx was also absorbed into the solvent in the absorption column. As discussed in section 4.1, crystals were collected from the plant during operation and analyzed. This analysis found that the crystals were >90% potassium sulfate. The rich solvent was analyzed for nitrate/nitrite content, and results showed that the nitrite content in solution was twice that of the nitrate concentration. This suggests that nitrite was stable in solution even after several months in storage at room temperature. A
mass balance around the absorber also showed that the nitrogen concentration in the rich solvent was far greater than that which is present in the flue gas. This confirms that there was a build up of nitrate and nitrite in the solvent over time. Because the solubility of nitrate/nitrite is far greater than the corresponding sulfate, nitrate/ nitrite precipitation was not found to be a significant operational problem. 4.3. Overall Performance and Operational Reliability. 4.3.1. Absorber Performance. The concentration of CO2 entering the absorber showed large variation during the initial trials, which 142
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Figure 5. Pressure drop across the absorber packing (using 30 wt % K2CO3).
Figure 6. Flow rate of CO2 entering and exiting the absorber (using 30 wt % K2CO3).
was likely due to the instability in the gas flow rate to the plant, but attained a fairly stable level of 16 wt % CO2 throughout most of the testing period. The pressure drop across the absorber packing was also reasonable and did not show a significant change over the course of the trial, indicating that little, if any, fouling or flooding occurred (refer to Figure 5). The calculation
of the predicted pressure drop based on the generalized pressure drop correlation agreed well with the observed values and was well below that for flooding. The average CO2 gas concentration exiting the absorber was around 13 wt %. The CO2 flow rate entering the absorber was ∼1000 kg/h, and ∼200 kg/h was removed, which corresponds to a capture rate of approximately 143
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Figure 7. Pressure drop across the regenerator packing (using 30 wt % K2CO3).
Table 3. Summary of Performance Indicators for Best Days of Operation flue gas
CO2
energy usage
day
flow rate (kg/h)
removed (%)
(kJ/kg of CO2)
1
5602
22
35
2
6617
20
37
3
4740
23
38
which resulted in more water being evaporated rather than CO2 being regenerated from the solvent. To reduce this energy consumption, more CO2 needs to be absorbed into the solvent. This may be achieved via the addition of solvent promoters and/or operating the absorber at higher temperatures to improve reaction kinetics and/or the use of higher packing sections for greater mass transfer. Analysis of the gas stream exiting the regenerator concluded that the product purity was greater than 95% CO2. 4.4. Comparison between Simulation and Pilot-Plant Trials. Understanding the thermodynamics and ability to model the behavior of the potassium carbonate solvent system is of great importance for process development, design, and optimization. Three different days have been chosen for comparing plant data to outputs provided by Aspen Plus simulations. 4.4.1. Performance Evaluation. The following performance indicators have been used for analyzing the performance of the CO2-capture plant:
20% (refer to Figure 6). This low capture rate can be attributed to a number of factors, including (1) operating K2CO3 in a plant that was designed for BASF PuraTreat F solvent, (2) operation at low temperature, low CO2 partial pressure, and without any rate promoters, resulting in poor reaction kinetics, (3) insufficient packing area and height for the operating conditions, and (4) low K2CO3 concentration. 4.3.2. Regenerator Performance. The reboiler temperature was restricted to a maximum of 116 °C. At temperatures above this, the amount of water vapor exiting the top of the regenerator column was beyond the cooling capacity of the condenser at the top of the regenerator (maximum set point of 50 °C), resulting in the loss of water from the solvent, column instability, and tripping of the plant. The pressure drop across the packing in the regenerator, similar to the absorber, indicated no evidence of fouling or flooding, as shown in Figure 7. An accurate measurement of the reboiler duty was compromised because of the inability to accurately measure the steam flow rate (because of an inappropriate location of the flow transmitter) and understand the steam conditions (because of the de-superheating process, resulting in unknown enthalpy). However, if it is assumed that 50% saturated steam was used in the reboiler, the energy usage varies from 20 to 55 GJ/ton of CO2 captured, which matches the Aspen Plus model predictions. The observed and predicted energy usage is very high because of low CO2 loadings in the rich solvent,
% CO2 removedðregeneratorÞ ¼
energy usage ðkJ=kgÞ ¼
CO2ðregenerator outÞ CO2ðfeedÞ
Qreboiler CO2ðregenerator outÞ
ð8Þ
ð9Þ
where CO2 (feed) is the CO2 mass flow rate in the feed stream (kg/h), CO2 (regnerator out) is the CO2 mass flow rate in the regenerator overhead stream (kg/h), and Qreboiler is the energy of the reboiler (kJ/h). The values of these performance indicators have been provided in Table 3. Because of problems associated with analyzing data from the reboiler, the energy usage calculations were calculated from data provided by Aspen Plus simulations. The energy usage values obtained from this study are significantly higher than work conducted by other investigators who report values ranging from 3 to 4.5 kJ/kg of CO2.21,22 This is due to the 144
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145
leanrich exchanger
reflux accumulator
regenerator
absorber
unit
38.1 0.3
temperature (°C) pressure (kPag)
temperature (°C) temperature (°C)
rich solvent in
rich solvent out
temperature (°C) 113
43.6
40.1
2081
flow rate (kg/h)
lean solvent out
2000
flow rate (kg/h) temperature (°C)
48.1
pressure (kPag)
lean solvent in
reflux outlet
vapor overhead outlet
temperature (°C)
lean solvent outlet
113 110.3
temperature (°C)
rich solvent inlet
115
temperature (°C)
temperature (°C)
39940
43.6
temperature (°C) flow rate (kg/h)
39870
flow rate (kg/h)
40.1
5602
flow rate (kg/h)
temperature (°C)
3.2
pressure (kPag)
4360
44.7
temperature (°C)
flow rate (kg/h)
plant data
parameter
column
rich solvent outlet
lean solvent inlet
treated gas out of absorber
blower feed gas inlet
stream
Table 4. Summary of Aspen Plus Simulation Results
107.1
43.9
49.8
114
1623
input
48.4
112.9
114
107.1
113.4
40155
43.9
input
input
5317
0
40.4
input
input
input
simulation result
day 1
0.4
+5.2
0.7
24.2
+22
112
46.5
46.8
2629
2639
41.7
0.7 N/A
109.1
112
112.8
2.4
+5.2
+1.4
44400
46.5
0.7 0.5
45030
46.8
5182
N/A
N/A
21.9
+100
6617 45.7
N/A
3
42
plant data
6
N/A
N/A
percent difference
104.2
46.6
53.7
112.2
2168
input
44.1
111.1
112.2
104.2
111.6
45169
46.6
input
input
6478
0
47.1
input
input
input
simulation result
day 2
+7
0.2
14.7
+17.5
N/A
5.9
1.8
+7.0
+1.1
1.7
0.2
N/A
N/A
25.0
+100.0
3.1
N/A
N/A
N/A
percent difference
48.7
46.7
2600
2500
41.9
109
112.7
45100
48.7
45060
46.7
4290
0.2
45.6
4740
2.9
47.1
plant data
104
48.2
55.4
112
2082
input
43.5
111.1
112
104
111.5
45268
48.2
input
input
4532
0
46.9
input
input
input
simulation result
day 3
+1
18.6
+19.9
N/A
3.9
1.9
+1.1
0.4
+1.0
N/A
N/A
5.6
+100
2.9
N/A
N/A
N/A
percent difference
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low CO2 absorption in the absorber, which results in wasted energy in the regenerator, as discussed in section 4.3. 4.4.2. Results as against Simulation. The results of the simulation for 3 different days are shown in Table 4. In general, the model predicts the performance well (within (5%). The exceptions to this can be explained as follows. The gas temperatures in the absorber and regenerator determined by Aspen Plus are slightly higher (4 and 2%, respectively) because the simulation model does not directly account for heat loss from the vessels. The difference ((4%) in the measured loading and that determined by Aspen Plus is attributed to errors in the experimental technique used to determine the loading and the timing of the samples not exactly correlating with the time period used for the modeling.
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5. CONCLUSION Post-combustion capture of CO2 from flue gas produced from a 1600 MW brown-coal-fired power station has been demonstrated using a 2030 wt % potassium carbonate solvent absorption CO2-capture plant. The plant has undergone successful commissioning, startup steady station operation, and shutdown operation with no safety incidents. Because the plant was not originally designed to be operated with potassium carbonate, the conditions were not optimal for CO2 capture, resulting in only 2025% of the CO2 being removed from the flue gas. This corresponded to a nominal capture rate of 45 tons/day. Calculation of energy consumption was limited because of uncertainty associated with calculating steam consumption. A preliminary understanding into the interaction between the solvent and flue gas impurities, such as SOx and NOx, has also been obtained. An Aspen Plus model has been developed and is able to successfully predict the performance of the plant to within (5%. These models will be very important for further improvement of alternative precipitating potassium-carbonate-based CO2-capture processes, which are currently under development. ’ AUTHOR INFORMATION Corresponding Author
*Telephone: +61-3-8344-6621. Fax: +61-3-8344-8824. E-mail:
[email protected].
’ ACKNOWLEDGMENT The Hazelwood carbon-capture plant has been funded by International Power with support from the Federal Government’s Low Emission Technology Development Fund (LETDF) and the Victorian Government’s Energy Technology Innovation Strategy Large Scale Demonstration Plant Fund (ETIS LSDP). The authors acknowledge Renato Anthony Innocenzi and his group at International Power Hazelwood (IPRH) for access to equipment and their support. The authors also acknowledge the financial support from Brown Coal Innovation Australia (BCIA) and the Australian Government through its Cooperative Research Centre Program. We thank Process Group (PG), CO2CRC participants, and the wider industry for their support. Infrastructure support from the Particulate Fluids Processing Centre (PFPC), a special research center of the Australian Research Council, is also gratefully acknowledged. ’ REFERENCES (1) Benson, H. E.; Field, J. H.; Jimeson, R. M. Chem. Eng. Prog. 1954, 50, 356–364. 146
dx.doi.org/10.1021/ef201192n |Energy Fuels 2012, 26, 138–146
