Continuous operation of the potassium-based dry sorbent CO2 capture process with two fluidized-bed reactors

The dry sorbent CO₂ capture process is an advanced concept to efficiently remove CO₂ from flue gas with two fluidized-bed reactors. This paper summarizes the results of performance of the two fluidized-bed reactors in the continuous solid circulation mode to investigate the feasibility of using potassium carbonate-based solid sorbent (Sorb KX35). The parameters such as gas velocity, solid circulation, carbonation temperature, and water vapor content were investigated during several continuous operations of two fluidized-bed reactors. The CO₂ removal increased as gas velocity was decreased and as solid circulation rate was increased. The CO₂ removal ranged from 26% to 73% was rather sensitive to the water vapor content among other parameters. A 20 h continuous operation conducted in a bench scale fast fluidized-bed reactor system indicated that the spray-dried potassium-based sorbent, Sorb KX35 having superior attrition resistance and high bulk density, had a promising CO₂ removal capacity of 50–73% at steady state and was able to regenerate and reuse. The results from this work are good enough to prove the concept of the dry sorbent CO₂ capture process to be one of viable methods for capturing CO₂ from dilute flue gas of fossil fuel-fired power plants.     

Calcium oxide for CO2 capture: Operational window and efficiency penalty in sorption-enhanced steam methane reforming

Calcium oxide (CaO) is a material that is being widely investigated in the context of CO₂ capture. One such application is as a CO₂ sorbent in the sorption-enhanced steam methane reforming processes (SERP). CO₂ is captured in an adsorption mode, where the conversion of CH₄ to H₂ is also enhanced, and released later in a separate desorption mode. This work presents an analysis of the relation between different process conditions and parameters during both adsorption and desorption modes. The interrelation between these conditions and the sorbent properties as well as the targeted carbon capture ratio is analysed. Conditions relevant for capturing 85% of carbon in the feed on CaO are determined and interlinked. A steam-to-carbon ratio of 4.2 has been determined to be relevant under 600 °C and 17 bar adsorption conditions. Similarly, process conditions relevant for regenerating the sorbent are determined and interlinked. For purge steam-to-CO₂ ratio of 1.8 at a desorption pressure of 1 bar, relevant desorption temperature has been calculated to be 820 °C. System simulations under these adsorption and desorption conditions resulted in a system efficiency of 50.8%. Effect of tuning process operating conditions on system efficiency as well as the efficiency penalty associated with the regeneration of the sorbent are investigated by process simulations using Aspen Plus^®. Possible system heat integration routes to reduce the efficiency penalty are proposed and the results of the process simulations are presented.     

Integration and evaluation of a power plant with a CaO-based CO2 capture system

This paper explores the integration and evaluation of a power plant with a CaO-based CO₂ capture system. There is a great amount of recoverable heat in the CaO-based CO₂ capture process. Five cases for the possible integration of a 600 MW power plant with CaO-based CO₂ capture process are considered in this paper. When the system is configured so that recovered heat is used to replace part of the boiler heat load (Case 2), modelling not only shows that this is the system recovering the most heat of 1008.8 MW but also results in the system with the lowest net power output of 446 MW and the second lowest of efficiency of 34.1%. It is indicated that system performance depends both on the amount of heat recovery and the type of heat utilization. When the system is configured so that a 400 MW power plant is built using the recovered heat (Case 4), modelling shows that this is the system with the most net power output of 846 MW, the highest efficiency of 36.8%, the lowest cost of electricity of 54.3 €/MWh and the lowest cost of CO₂ avoided of 28.9 €/tCO₂. This new built steam cycle will not affect the operation of the reference plant which vents its CO₂ to the atmosphere, highly reducing the connection between the CO₂ capture process and the reference plant which vents its CO₂ to the atmosphere. The average cost of electricity and the cost of CO₂ avoided of the five cases are about 58.9 €/kWh and 35.9 €/tCO₂, respectively.     

CO2 capture from combined cycles integrated with Molten Carbonate Fuel Cells

In this paper Molten Carbonate Fuel Cells (MCFCs) are considered for their potential application in carbon dioxide separation when integrated into natural gas fired combined cycles. The MCFC performs on the anode side an electrochemical oxidation of natural gas by means of CO₃^2? ions which, as far as carbon capture is concerned, results in a twofold advantage: the cell removes CO₂ fed at the cathode to promote carbonate ion transport across the electrolyte and any dilution of the oxidized products is avoided.The MCFC can be “retrofitted” into a combined cycle, giving the opportunity to remove most of the CO₂ contained in the gas turbine exhaust gases before they enter the heat recovery steam generator (HRSG), and allowing to exploit the heat recovery steam cycle in an efficient “hybrid” fuel cell + steam turbine configuration. The carbon dioxide can be easily recovered from the cell anode exhaust after combustion with pure oxygen (supplied by an air separation unit) of the residual fuel, cooling of the combustion products in the HRSG and water separation. The resulting power cycle has the potential to keep the overall cycle electrical efficiency approximately unchanged with respect to the original combined cycle, while separating 80% of the CO₂ otherwise vented and limiting the size of the fuel cell, which contributes to about 17% of the total power output so that most of the power capacity relies on conventional low cost turbo-machinery. The calculated specific energy for CO₂ avoided is about 4 times lower than average values for conventional post-combustion capture technology. A sensitivity analysis shows that positive results hold also changing significantly a number of MCFC and plant design parameters.     

Integration of post-combustion capture and storage into a pulverized coal-fired power plant

Post-combustion CO₂ capture and storage (CCS) presents a promising strategy to capture, compress, transport and store CO₂ from a high volume–low pressure flue gas stream emitted from a fossil fuel-fired power plant. This work undertakes the simulation of CO₂ capture and compression integration into an 800 MW_e supercritical coal-fired power plant using chemical process simulators. The focus is not only on the simulation of full load of flue gas stream into the CO₂ capture and compression, but also, on the impact of a partial load. The result reveals that the energy penalty of a low capture efficiency, for example, at 50% capture efficiency with 10% flue gas load is higher than for 90% flue gas load at the equivalent capture efficiency by about 440 kWh_e/tonne CO₂. The study also addresses the effect of CO₂ capture performance by different coal ranks. It is found that lignite pulverized coal (PC)-fired power plant has a higher energy requirement than subbituminous and bituminous PC-fired power plants by 40.1 and 98.6 MW_e, respectively. In addition to the investigation of energy requirement, other significant parameters including energy penalty, plant efficiency, amine flow rate and extracted steam flow rate, are also presented. The study reveals that operating at partial load, for example at half load with 90% CO₂ capture efficiency, as compared with full load, reduces the energy penalty, plant efficiency drop, amine flow rate and extracted steam flow rate by 9.9%, 24.4%, 50.0% and 49.9%, respectively. In addition, the effect of steam extracted from different locations from a series of steam turbine with the objective to achieve the lowest possible energy penalty is evaluated. The simulation shows that a low extracted steam pressure from a series of steam turbines, for example at 300 kPa, minimizes the energy penalty by up to 25.3%.     

CO2 capture from power plants: Part II. A parametric study of the economical performance based on mono-ethanolamine

While the demand for reduction in CO₂ emission is increasing, the cost of the CO₂ capture processes remains a limiting factor for large-scale application. Reducing the cost of the capture system by improving the process and the solvent used must have a priority in order to apply this technology in the future. In this paper, a definition of the economic baseline for post-combustion CO₂ capture from 600 MW_e bituminous coal-fired power plant is described. The baseline capture process is based on 30% (by weight) aqueous solution of monoethanolamine (MEA). A process model has been developed previously using the Aspen Plus simulation programme where the baseline CO₂-removal has been chosen to be 90%. The results from the process modelling have provided the required input data to the economic modelling. Depending on the baseline technical and economical results, an economical parameter study for a CO₂ capture process based on absorption/desorption with MEA solutions was performed.Major capture cost reductions can be realized by optimizing the lean solvent loading, the amine solvent concentration, as well as the stripper operating pressure. A minimum CO₂ avoided cost of € 33 tonne⁻¹ CO₂ was found for a lean solvent loading of 0.3 mol CO₂/mol MEA, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa. At these conditions 3.0 GJ/tonne CO₂ of thermal energy was used for the solvent regeneration. This translates to a € 22 MWh⁻¹ increase in the cost of electricity, compared to € 31.4 MWh⁻¹ for the power plant without capture.     

Designing a supercritical steam cycle to integrate the energy requirements of CO2 amine scrubbing

Absorption by chemical solvents combined with CO₂ long-term storage appears to offer interesting and commercial applicable CO₂ capture technology. However one of the main disadvantages is related to the large quantities of heat required to regenerate the amine solvent that means an important power plant efficiency penalty. Different studies have analyzed alternatives to reduce the heat duty on the reboiler and the thermal integration requirements on existing power cycles. In these studies integration principles have been well set up, but there is a lack of information about how to achieve an integrated design and the thermal balances of the modified cycle flowsheet. This paper proposes and provides details about a set of modifications of a supercritical steam cycle to overcome the energy requirements through energetic integration with the aim of reducing the efficiency and power output penalty associated with CO₂ capture process. Modifications include a new designed low-pressure heater flowsheet to take advantage of the CO₂ compression cooling for postcombustion systems and integration of amine reboiler into a steam cycle. It has been carried out several simulations in order to obtain power plant performance depending on sorbent regeneration requirements.     

Parametric investigation of the calcium looping process for CO2 capture in a 10 kWth dual fluidized bed

Calcium looping (CaL) is a promising post-combustion CO₂ capture technology which is carried out in a dual fluidized bed (DFB) system with continuous looping of CaO, the CO₂ carrier, between two beds. The system consists of a carbonator, where flue gas CO₂ is adsorbed by CaO and a regenerator, where captured CO₂ is released. The CO₂-rich regenerator flue gas can be sequestered after gas processing and compression. A parametric study was conducted on the 10 kW_th DFB facility at the University of Stuttgart, which consists of a bubbling fluidized bed carbonator and a riser regenerator. The effect of the following parameters on CO₂ capture efficiency was investigated: carbonator space time, carbonator temperature and calcium looping ratio. The active space time in the carbonator, which is a function of the space time and the calcium looping ratio, was found to strongly correlate with the CO₂ capture efficiency. BET and BJH techniques provided surface area and pore volume distribution data, respectively, for collected sorbent samples. The rate of sorbent attrition was found to be 2 wt.%/h which is below the expected sorbent make-up rate required to maintain sufficient sorbent activity. Steady-state CO₂ capture efficiencies greater than 90% were achieved for different combinations of operational parameters. Moreover, the experimental results obtained were briefly compared with results derived from reactor modeling studies. Finally, the implications of the experimental results with respect to commercialization of the CaL process have been assessed.     

Novel lithium-based sorbents from fly ashes for CO2 capture at high temperatures

In this work several Li₄SiO₄-based sorbents from fly ashes for CO₂ capture at high temperatures have been developed. Three fly ash samples were collected and subjected to calcination at 950 °C in the presence of Li₂CO₃. Both pure Li₄SiO₄ and fly ash-based sorbents were characterised and tested for CO₂ sorption at different temperatures between 400 and 650 °C and adding different amounts of K₂CO₃ (0–40 mol%). To examine the sorbents performance, multiple CO₂ sorption/desorption cycles were carried out. The temperature and the presence of K₂CO₃ strongly affect the CO₂ sorption capacity for the sorbents prepared from fly ashes. When the sorption temperature increases by up to 600 °C both the CO₂ sorption capacity and the sorption rate increase significantly. Moreover when the amount of K₂CO₃ increases, the CO₂ sorption capacity also increases. At optimal experimental conditions (600 °C and 40 mol% K₂CO₃), the maximum CO₂ sorption capacity for the sorbent derived from fly ash was 107 mg CO₂/g sorbent. The Li₄SiO₄-based sorbents can maintain its original capacity during 10 cycle processes and reach the plateau of maximum capture capacity in less than 15 min, while pure Li₄SiO₄ presents a continual upward tendency for the 15 min of the capture step and attains no equilibrium capacity.     

The modelling of a hybrid combined cycle with pressurised fluidised bed combustion and CO2 capture

This study investigates the possibility of capturing CO₂ from flue gas under pressurised conditions, which could prove to be beneficial in comparison to working under atmospheric conditions. Simulations of two hybrid combined cycles with pressurised fluidised bed combustion and CO₂ capture are presented. CO₂ is captured from pressurised flue gas by means of chemical absorption after the boiler but before expansion. The results show a CO₂ capture penalty of approximately 8 percentage points (including 90% CO₂ capture rate and compression to 110 bar), which makes the efficiency for the best performing cycle 43.9%. It is 5.2 percentage points higher than the most probable alternative, i.e. using a natural gas fired combined cycle and a pulverised coal fired condensing plant separately with the same fuel split ratio. The largest part of the penalty is associated with the lower mass flow of flue gas after CO₂ capture, which leads to a decrease in work output in the expander and potential for feed water heating. The penalty caused by the regeneration of absorbent is quite low, since the high pressure permits the use of potassium carbonate, which requires less regeneration heat than for example the more commonly proposed monoethanolamine. Although the efficiencies of the cycles look promising it will be important to perform a cost estimate to be able to make a fair comparison with other systems. Such a cost estimate has not been done in this study. A significant drawback of these hybrid cycles in that respect is the complex nature of the systems that will have a negative effect on the economy.     

Multi-stage chemical looping combustion (CLC) for combined cycles with CO2 capture

This paper presents application of the chemical looping combustion (CLC) method in natural gas-fired combined cycles for power generation with CO₂ capture. A CLC combined cycle consisting of single CLC-reactor system, an air turbine, a CO₂-turbine and a steam cycle has been designated as the base-case cycle. The base-case cycle can achieve net plant efficiency of about 52% at an oxidation temperature of 1200 °C. In order to achieve a reasonable efficiency at lower oxidation temperatures, reheat is introduced into the air turbine by employing multi CLC-reactors. The results show that the single reheat CLC-combined cycle can achieve net plant efficiency of above 51% at oxidation temperature of 1000 °C and above 53% at the oxidation temperature of 1200 °C including CO₂ compression to 110 bar. The double reheat cycle results in marginal efficiency improvement as compared to the single reheat cycle. The CLC-cycles are also compared with a conventional combined cycle with and without post-combustion capture in amine solution. All the CLC-cycles show higher net plant efficiencies with close to 100% CO₂ capture as compared to a conventional combined cycle with post-combustion capture, which is very promising.     

Testing of hydrotalcite-based sorbents for CO2 and H2S capture for use in sorption enhanced water gas shift

The feasibility of the sorption enhanced water gas shift (SEWGS) process under sour conditions is shown. The sour-SEWGS process constitutes a second generation pre-combustion carbon capture technology for the application in an IGCC. As a first critical step, the suitability of a K₂CO₃ promoted hydrotalcite-based CO₂ sorbent is demonstrated by means of adsorption and regeneration experiments in the presence of 2000 ppm H₂S. In multiple cycle experiments at 400 °C and 5 bar, the sorbent displays reversible co-adsorption of CO₂ and H₂S. The CO₂ sorption capacity is not significantly affected compared to sulphur-free conditions. A mechanistic model assuming two different sites for H₂S interaction explains qualitatively the interactions of CO₂ and H₂S with the sorbent. On the type A sites, CO₂ and H₂S display competitive sorption where CO₂ is favoured. The type B sites only allow H₂S uptake and may involve the formation of metal sulphides. This material behaviour means that the sour-SEWGS process likely eliminates CO₂ and H₂S simultaneously from the syngas and that an almost CO₂ and H₂S-free H₂ stream and a CO₂ + H₂S stream can be produced.     

Conceptual design of a three fluidised beds combustion system capturing CO2 with CaO

In this work, the Aspen Hysys conceptual design of a new process for energy generation at large scale with implicit CO₂ capture is presented. This process makes use of the CaO capability for CO₂ capture at high temperature and the possibility of regenerating this sorbent working in interconnected fluidised bed reactors operating at different temperatures. The proposed process has the advantage of producing power with minimum CO₂ emissions and very low energy penalties compared with similar air-based combustion power plants. In this system, five main parts can be distinguished: the combustor where coal is burnt with air, the calciner where the fresh and the recycled CaCO₃ is calcined, the carbonator where the CO₂ produced in the combustor is captured, the supercritical steam cycle and the CO₂ compression system. In this arrangement, the three fluidised bed reactors are interconnected in such a way that it is possible to perform the CaCO₃ calcination at a temperature of 950 °C with the energy transported by a hot solid stream produced in the circulating fluidised bed combustor operating at 1030 °C. The stream rich in CaO produced in the calciner is split into three parts. One of them is transported to the carbonator operating at 650 °C where most of the CO₂ in the flue gas produced in the combustor is captured. The second one is sent to the combustor, where it is heated up and used as energy carrier. The third solid stream that leaves the calciner is a purge in order to maintain the capture system activity and to avoid inert material accumulation. Because of the high temperatures involved in all the system, it is possible to recover most of the energy in the fuel and to produce power in a supercritical steam cycle. A case study is presented and it is demonstrated that under these operating conditions, 90% CO₂ capture efficiency can be achieved with no energy penalty further than the one originated in the CO₂ compression system.     

Integration of CO2 capture unit using single- and blended-amines into supercritical coal-fired power plants: Implications for emission and energy management

This work provides the essential information and approaches for integration of carbon dioxide (CO₂) capture units into power plants, particularly the supercritical type, so that energy utilization and CO₂ emissions can be well managed in the subject power plants. An in-house model, developed at the University of Regina, Canada, was successfully used for simulating a 500 MW supercritical coal-fired power plant with a post-combustion CO₂ capture unit. The simulations enabled sensitivity and parametric study of the net efficiency of the power plant, the coal consumption rate, and the amounts of CO₂ captured and avoided. The parameters of interest include CO₂ capture efficiency, type of coal, flue gas delivery scheme, type of amine used in the capture unit, and steam pressure supplied to the capture unit for solvent regeneration. The results show that the advancement of MEA-based CO₂ capture units through uses of blended monoethanolamine–methyldiethanolamine (MEA–MDEA) and split flow configuration can potentially make the integration of power plant and CO₂ capture unit less energy intensive. Despite the increase in energy penalty, it may be worth capturing CO₂ at a higher efficiency to achieve greater CO₂ emissions avoided. The flue gas delivery scheme and the steam pressure drawn from the power plant to the CO₂ capture unit should be considered for process integration.     

Experimental validation of in situ CO2 capture with CaO during the low temperature combustion of biomass in a fluidized bed reactor

A novel concept for capturing CO₂ from biomass combustion using CaO as an active solid sorbent of CO₂ is discussed and experimentally tested. According to the CaO/CaCO₃ equilibrium, if a fuel could be burned at a sufficiently low temperature (below 700 °C) it would be possible to capture CO₂ “in situ” with the CaO particles at atmospheric pressure. A subsequent step involving the regeneration of CaCO₃ in a calciner operating at typical conditions of oxyfired-circulating fluidized combustion would deliver the CO₂ ready for purification, compression and permanent geological storage. Several series of experiments to prove this concept have been conducted in a 30 kW interconnected fluidized bed test facility at INCAR-CSIC, made up of two interconnected circulating fluidized bed reactors, one acting as biomass combustor-carbonator and the other as air-fired calciner (which is considered to yield similar sorbent properties than those of an oxyfired calciner). CO₂ capture efficiencies in dynamic tests in the combustor-carbonator reactor were measured over a wide range of operating conditions, including different superficial gas velocities, solids circulation rates, excess air above stoichiometric, and biomass type (olive pits, saw dust and pellets). Biomass combustion in air is effective at temperatures even below the 700 °C, necessary for the effective capture of CO₂ by carbonation of CaO. Overall CO₂ capture efficiencies in the combustor-carbonator higher than 70% can be achieved with sufficiently high solids circulation rates of CaO and solids inventories. The application of a simple reactor model for the combined combustion and CO₂ capture reactions allows an efficiency factor to be obtained from the dynamic experimental test that could be valuable for scaling up purposes.     

Low-energy sodium hydroxide recovery for CO2 capture from atmospheric air—Thermodynamic analysis

To reduce the risks of climate change, atmospheric concentrations of greenhouse gases must be lowered. Direct capture of CO₂ from ambient air, “air capture”, might be one of the few methods capable of systematically managing dispersed emissions. The most commonly proposed method for air capture is a wet scrubbing technique which absorbs CO₂ in an alkaline absorbent, i.e. sodium hydroxide producing an aqueous solution of sodium hydroxide and sodium carbonate. In most of the previous works it was assumed that the absorbent would be regenerated and CO₂ liberated from the alkaline carbonate solution using a lime and calcium carbonate causticization cycle.We describe a novel technique for recovering sodium hydroxide from an aqueous alkaline solution of sodium carbonate and present an end-to-end energy and exergy analysis. In the first step of the recovery process, anhydrous sodium carbonate is separated from the concentrated sodium hydroxide solution using a two-step precipitation and crystallization process. The anhydrous sodium carbonate is then causticized using sodium tri-titanate. The titanate direct causticization process has been of interest for the pulp and paper industry and has been tested at lab- and pilot-scale. In the causticization process, sodium hydroxide is regenerated and carbon dioxide is liberated as a pure stream, which is compressed for use or disposal. The technique requires ～50% less high-grade heat than conventional causticization and the maximum temperature required is reduced by at least 50 °C. This titanate cycle may allow a substantial reduction in the overall cost of direct air capture.     

Exergy analysis as a tool for the integration of very complex energy systems: The case of carbonation/calcination CO2 systems in existing coal power plants

A common characteristic of carbon capture and storage systems is the important energy consumption associated with the CO₂ capture process. This important drawback can be solved with the analysis, synthesis and optimization of this type of energy systems. The second law of thermodynamics has proved to be an essential tool in power and chemical plant optimization. The exergy analysis method has demonstrated good results in the synthesis of complex systems and efficiency improvements in energy applications.In this paper, a synthesis of pinch analysis and second law analysis is used to show the optimum window design of the integration of a calcium looping cycle into an existing coal power plant for CO₂ capture. Results demonstrate that exergy analysis is an essential aid to reduce energy penalties in CO₂ capture energy systems. In particular, for the case of carbonation/calcination CO₂ systems integrated in existing coal power plants, almost 40% of the additional exergy consumption is available in the form of heat. Accordingly, the efficiency of the capture cycle depends strongly on the possibility of using this heat to produce extra steam (live, reheat and medium pressure) to generate extra power at steam turbine. The synthesis of pinch and second law analysis could reduce the additional coal consumption due to CO₂ capture 2.5 times, from 217 to 85 MW.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

The oxyfuel process is one of the most promising options to capture CO₂ from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90 vol% CO₂ on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO₂ stream with purity in the range from 85 to 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO₂ stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO₂ purity for capture and storage.     

Carbonic anhydrase-facilitated CO2 absorption with polyacrylamide buffering bead capture

A novel CO₂ separation concept is described wherein the enzyme carbonic anhydrase (CA) is used to increase the overall rate of CO₂ absorption after which hydrated CO₂ reacts with regenerable amine-bearing polyacrylamide buffering beads (PABB). Following saturation of the material's immobilized tertiary amines, CA-bearing carrier water is separated and recycled to the absorption stage while CO₂-loaded material is thermally regenerated. Process application of this concept would involve operation of two or more columns in parallel with thermal regeneration with low-pressure steam taking place after the capacity of a column of amine-bearing polymeric material was exceeded. PABB CO₂-bearing capacity was evaluated by thermogravimetric analysis (TGA) for beads of three acrylamido buffering monomer ingredient concentrations: 0 mol/kg bead, 0.857 mol/kg bead, and 2 mol/kg bead. TGA results demonstrate that CO₂-bearing capacity increases with increasing PABB buffering concentration and that up to 78% of the theoretical CO₂-bearing capacity was realized in prepared PABB samples (0.857 mol/kg recipe). The highest observed CO₂-bearing capacity of PABB was 1.37 mol of CO₂ per kg dry bead. TGA was also used to assess the regenerability of CO₂-loaded PABB. Preliminary results suggest that CO₂ is partially driven from PABB samples at temperatures as low as 55 °C, with complete regeneration occurring at 100 °C. Other physical characteristics of PABB are discussed. In addition, the effectiveness of bovine carbonic anhydrase for the catalysis of CO₂ dissolution is evaluated. Potential benefits and drawbacks of the proposed process are discussed.