CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO₂ from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO₂ capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO₂ removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO₂, which is 23% lower than the base case of 3.9 GJ/ton CO₂. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.     

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.     

Heat of absorption of CO2 in aqueous ammonia and ammonium carbonate/carbamate solutions

A reaction calorimeter was used to determine the enthalpies of absorption of CO₂ in aqueous ammonia and in aqueous solutions of ammonium carbonate at temperatures of 35–80 °C. The heat of absorption of CO₂ with 2.5 wt% aqueous ammonia solution was found to be about 70 kJ/mol CO₂, which is lower than that with MEA (around 85 kJ/mol) at 35 and 40 °C. The value decreases with increased loading, but not to as low a value as expected by the carbonate–bicarbonate reaction (26.88 kJ/mol). The enthalpy of absorption of CO₂ in aqueous ammonia at 60 and 80 °C decreases with loadings at first, then increases between 0.2 mol CO₂/mol NH₃ and 0.6 mol CO₂/mol NH₃, and then decreases again. The behavior of the heat of absorption of CO₂ in 10 wt% ammonium carbonate solution was found to be the same as that of aqueous ammonia at loadings above 0.6 mol CO₂/mol NH₃. The heat of absorption increases with increasing temperature. The heats of absorption are directly related to the extent of the various reactions with CO₂ and can be assessed from the species variation in the liquid phase.     

Carbon dioxide capture with concentrated,aqueous piperazine

Concentrated, aqueous piperazine (PZ) has been investigated as a novel amine solvent for carbon dioxide (CO₂) absorption. The CO₂ absorption rate of aqueous PZ is more than double that of 7 m MEA and the amine volatility at 40 °C ranges from 11 to 21 ppm. Thermal degradation is negligible in concentrated, aqueous PZ up to a temperature of 150 °C, a significant advantage over MEA systems. Oxidation of concentrated, aqueous PZ is appreciable in the presence of copper (4 mM), but negligible in the presence of chromium (0.6 mM), nickel (0.25 mM), iron (0.25 mM), and vanadium (0.1 mM). Initial system modeling suggests that 8 m PZ will use 10–20% less energy than 7 m MEA. The fast mass transfer and low degradation rates suggest that concentrated, aqueous PZ has the potential to be a preferred solvent for CO₂ capture.     

Kinetics of sulfur dioxide- and oxygen-induced degradation of aqueous monoethanolamine solution during CO2 absorption from power plant flue gas streams

Studies of the kinetics of sulfur dioxide (SO₂)- and oxygen (O₂)-induced degradation of aqueous monoethanolamine (MEA) during the absorption of carbon dioxide (CO₂) from flue gases derived from coal- or natural gas-fired power plants were conducted as a function of temperature and the liquid phase concentrations of MEA, O₂, SO₂ and CO₂. The kinetic data were based on the initial rate which shows the propensity for amine degradation and obtained under a range of conditions typical of the CO₂ absorption process (3–7 kmol/m³ MEA, 6% O₂, 0–196 ppm SO₂, 0–0.55 CO₂ loading, and 328–393 K temperature). The results showed that an increase in temperature and the concentrations of MEA, O₂ and SO₂ resulted in a higher MEA degradation rate. An increase in CO₂ concentration gave the opposite effect. A semi-empirical model based on the initial rate, ?r_MEA = {6.74 × 10⁹ e^?(29,403/RT)[MEA]^0.02([O]^2.91 + [SO₂]^3.52)}/{1 + 1.18[CO₂]^0.18} was developed to fit the experimental data. With the higher order of reaction, SO₂ has a higher propensity to cause MEA to degrade than O₂. Unlike previous models, this model shows an improvement in that any of the parameters (i.e. O₂, SO₂, and CO₂) can be removed without affecting the usability of the model.     

CO2 capture from hot stove gas in steel making process

The capture of CO₂ from a hot stove gas in steel making process containing 30 vol% CO₂ by chemical absorption in a rotating packed bed (RPB) was studied. The RPB had an inner diameter of 7.6 cm, an outer diameter of 16 cm, and a height of 2 cm. The aqueous solutions containing 30 wt% of single and mixed monoethanolamine (MEA), 2-(2-aminoethylamino)ethanol (AEEA), and piperazine (PZ) were used. The CO₂ capture efficiency was found to increase with increasing temperature in a range of 303–333 K. It was also found to be more dependent on gas and liquid flow rates but less dependent on rotating speed when the speed was higher than 700 rpm. The obtained results indicated that the mixed alkanolamine solutions containing PZ were more effective than the single alkanolamine solutions. This was attributed to the highest reaction rate of PZ with CO₂. A higher portion of PZ in the mixture was more favorable to CO₂ capture. The highest gas flow rates allowed to achieve a desired CO₂ capture efficiency and the correspondent height of transfer unit (HTU) were determined at different aqueous solution flow rates. Because all the 30 wt% single and mixed alkanolamine solutions could result in a HTU less than 5.0 cm at a liquid flow rate of 100 mL/min, chemical absorption in a RPB instead of a packed bed adsorber is therefore suggested to capture CO₂ from the flue gases in steel making processes.     

Worst case scenario study to assess the environmental impact of amine emissions from a CO2 capture plant

Use of amines is one of the leading technologies for post-combustion carbon dioxide capture from gas and coal-fired power plants. This study assesses the potential environmental impact of emissions to air that result from use of monoethanol amine (MEA) as an absorption solvent for the capture of carbon dioxide (CO₂). Depending on operation conditions and installed reduction technology, emissions of MEA to the air due to solvent volatility losses are expected to be in the range of 0.01–0.8 kg/tonne CO₂ captured. Literature data for human and environmental toxicity, together with atmospheric dispersion model calculations, were used to derive maximum tolerable emissions of amines from CO₂ capture. To reflect operating conditions with typical and with elevated emissions, we defined a scenario MEA-LOW, with emissions of 40 t/year MEA and 5 t/year diethyl amine (DEYA), and a scenario MEA-HIGH, with emissions of 80 t/year MEA and 15 t/year DEYA. Maximum MEA deposition fluxes would exceed toxicity limits for aquatic organisms by about a factor of 3–7 depending on the scenario. Due to the formation of nitrosamines and nitramines, the estimated emissions of DEYA are close to or exceed safety limits for drinking water and aquatic ecosystems. The “worst case” scenario approach to determine maximum tolerable emissions of MEA and other amines is in particular useful when both expected environmental loads and the toxic effects are associated with high uncertainties.     

Modeling CO2 capture with aqueous monoethanolamine

Hilliard completed several thermodynamic models in Aspen Plus^® for modeling CO₂ removal with amine solvents, including MEA–H₂O–CO₂. This solvent was selected to make a system model for CO₂ removal by absorption/stripping. Both the absorber and the stripper used RateSep? to rigorously calculate mass transfer rates. The accuracy of the new model was assessed using a recent pilot plant run with 35 wt.% (9 m) MEA. Absorber loading and removal were predicted within 6%, and the temperature profile was approached within 5 °C. An average 3.8% difference between measured and calculated values was achieved in the stripper. A three-stage flash configuration which efficiently utilizes solar energy was developed. It reduces energy use by 6% relative to a simple stripper. Intercooling was used to reach 90% removal in the absorber at these optimized conditions.     

Investigation of amine amino acid salts for carbon dioxide absorption

The carbon dioxide capture potential of amine amino acid salts (AAAS), formed by mixing equinormal amounts of amino acids; e.g. glycine, β-alanine and sarcosine, with an organic base; 3-(methylamino)propylamine (MAPA), was assessed by comparison with monoethanolamine (MEA), and with amino acid salt (AAS) from amino acid neutralized with an inorganic base; potassium hydroxide (KOH). Carbon dioxide absorption and desorption experiments were carried out on the solvent systems at 40 °C and 80 °C respectively. Experimental results showed that amine amino acid salts have similar CO₂ absorption properties to MEA of the same concentration. They also showed good signs of stability during the experiments. Amino acid salt from an inorganic base, KOH, showed lower performance in CO₂ absorption than the amine amino acid salts (AAAS) mainly due to a lower equilibrium temperature sensitivity. AAAS showed better performance than MEA of same concentration. AAAS from neutralization of sarcosine with MAPA showed the best performance and the performance could be further enhanced when promoted with excess MAPA. The solvent comparison is semi-quantitative since the bubble structure, and thus gas–liquid interfacial area may not be the same for all experiments, however superficial gas velocities were kept constant.     

CO2 capture from coal-fired power plants based on sodium carbonate slurry; a systems feasibility and sensitivity study

In this work the feasibility of a CO₂ capture system based on sodium carbonate–bicarbonate slurry and its integration with a power plant is studied. The results are compared to monoethanolamine (MEA)-based capture systems. Condensing power plant and combined heat and power plant with CO₂ capture is modelled to study the feasibility of combined heat and power plant for CO₂ capture.Environmental friendly sodium carbonate would be an interesting chemical for CO₂ capture. Sodium carbonate absorbs CO₂ forming sodium bicarbonate. The low solubility of sodium bicarbonate is a weak point for the sodium carbonate based liquid systems since it limits the total concentration of carbonate. In this study the formation of solid bicarbonate is allowed, thus forming slurry, which can increase the capacity of the solvent. With this the energy requirement of stripping of the solvent could potentially be around 3.22 MJ/kg of captured CO₂ which is significantly lower than with MEA based systems which typically have energy consumption around 3.8 MJ/kg of captured CO₂.Combined heat and power plants seem to be attractive for CO₂ capture because of the high total energy efficiency of the plants. In a condensing power plant the CO₂ capture decreases directly the electricity production whereas in a combined heat and power plant the loss can be divided between district heat and electricity according to demand.     

1D and 2D absorption-rate/kinetic modeling and simulation of carbon dioxide absorption into mixed aqueous solutions of MDEA and PZ in a laminar jet apparatus

The kinetics of the reaction between carbon dioxide (CO₂) and mixed solutions of methyldiethanolamine (MDEA) and piperazine (PZ) was investigated experimentally in a laminar jet apparatus. The experimental kinetic data were obtained under no interfacial turbulence and over a temperature range from 313 to 333 K, MDEA/PZ wt% concentration ratios of 27/3, 24/6 and 21/9, and CO₂ loadings from 0.0095 to 0.33 mol CO₂/mol amine. In addition, a new absorption-rate/kinetics model for the kinetics of the mixed of solvents was developed, which takes into account the coupling between chemical equilibrium, mass transfer, and all possible chemical reactions involved in the CO₂ reaction with MDEA/PZ solvent. The partial differential equations of this model were solved by the finite element numerical method (FEM) based on COMSOL software. The obtained experimental kinetics data were used to obtain the kinetic parameters of CO₂ absorption into MDEA/PZ solutions. The reaction-rate constant obtained for PZ blended with MDEA was kPZ = 2.572 × 10¹² exp(?5211/T). The 2D model for the blended amines MDEA/PZ has revealed the concentration profiles of all the species in both the radial and axial directions of the laminar jet which has enabled a better understanding of the correct sequence in which the reaction steps involved in the reactive absorption of CO₂ in aqueous mixed MDEA/PZ solution occur. It also revealed that PZ may be depleted by the time the solvent blend of MDEA/PZ with a loading greater than 0.015 mol/mol amine is exposed to CO₂ from the top of the laminar jet absorber.     

Degradation of aqueous piperazine in carbon dioxide capture

Concentrated, aqueous piperazine (PZ) is a novel solvent for carbon dioxide (CO₂) capture by absorption/stripping. One of the major advantages of PZ is its resistance to thermal degradation and oxidation.At 135 and 150 °C, 8 m PZ is up to two orders of magnitude more resistant to thermal degradation than 7 m monoethanolamine (MEA). After 18 weeks at 150 °C, only 6.3% of the initial PZ was degraded, yielding an apparent first order rate constant for amine loss of 6.1 × 10^?9 s^?1. PZ was the most resistant amine tested, with the other screened amines shown in order of decreasing resistance: 7 m 2-amino-2-methyl-1-propanol, 7 m Diglycolamine^®, 7 m N-(2-hydroxyethyl)piperazine, 7 m MEA, 8 m ethylenediamine, and 7 m diethylenetriamine. Thermal resistance allows the use of higher temperatures and pressures in the stripper, potentially leading to overall energy savings.Concentrated PZ solutions demonstrate resistance to oxidation compared to 7 m MEA solutions. Experiments investigating metal-catalyzed oxidation found that PZ solutions were 3–5 times more resistant to oxidation than MEA. Catalysts tested were 1.0 mM iron (II), 4.0–5.0 mM copper (II), and a combination of stainless steel metals (iron (II), nickel (II), and chromium (III)). Inhibitor A reduced PZ degradation catalyzed by iron (II) and copper (II).     

CO2 removal using membrane gas absorption

The objective of this study is to investigate the potential process for the removal of carbon dioxide (CO₂) from flue gas using fundamental membrane contactor, which is a membrane gas absorption (MGA) system. The experiments consisted of microporous polyvinylidenefluoride (PVDF) flat sheet membrane with 0.1 μm (as module I) and 0.45 μm (as module II) pore size. 2-Amino-2-methyl-1-propanol (AMP) solution was employed as the liquid absorbent. The effect of AMP concentration was studied with variation in the range 1–5 M. In addition, the experiments were carried out with 10%, 20%, 30% and 40% gas ratio of CO₂ to N₂ and pure CO₂ as well. Through contact angle measurement, membranes for module I and module II were obtained with CA values of around 130.25° and 127.77°, respectively. The mass transfer coefficients for module II are lower than those of module I for 1–5 M of AMP. Furthermore, the increase in CO₂ concentration in the feed gas stream enhanced the CO₂ flux as the driving force of the system was increased in sequence from 1 M to 5 M of AMP. However, after the particular percentage (40%) of CO₂ inlet concentration, the CO₂ fluxes seem saturated. The combination of AMP as liquid absorbent and PVDF microporous membrane in MGA system has shown the potential to remove the CO₂ from flue gas. In addition, the higher AMP concentration gave higher mass transfer coefficient at low liquid flow rates.     

Amine volatility in CO2 capture

Amine volatility is a key screening criterion for amines to be used in CO₂ capture. Excessive volatility may result in significant economic losses and environmental impact. It also dictates the capital cost of the water wash. This paper reports measured amine volatility in 7 m MEA (monoethanolamine), 8 m PZ (piperazine), 7 m MDEA (n-methyldiethanolamine)/2 m PZ (piperazine), 12 m EDA (ethylenediamine), and 5 m AMP (2-amino-2-methyl-1-propanol) at 40–60 °C with lean and rich loadings giving CO₂ partial pressures of 0.5 and 5 kPa at 40 °C. The amine concentrations were chosen to maximize CO₂ capture capacity at acceptable viscosity. At the lean loading condition (where volatility is of greatest interest), the amines are ranked in order of increasing volatility: 7 m MDEA/2 m PZ (6/2 ppm), 8 m PZ (8 ppm), 12 m EDA (9 ppm), 7 m MEA (31 ppm), and 5 m AMP (112 ppm). The apparent amine partial molar excess enthalpies in these systems were estimated to range from ～10 to 87 kJ/mol of amine.     

A 13C NMR investigation of CO2 absorption and desorption in aqueous 2,2′-iminodiethanol and N-methyl-2,2′-iminodiethanol

The carbon dioxide capture and release from aqueous 2,2′-iminodiethanol (DEA) and N-methyl-2,2′-iminodiethanol (MDEA) have been investigated by means of ¹³C NMR spectroscopy. We have designed two experimental procedures using a gas mixture containing 12% (v/v) CO₂ in N₂ or air and 0.667 M aqueous solutions of DEA and MDEA. To understand the CO₂–amine reaction equilibria, separate experiments of CO₂ absorption (at 293, 313 and 333 K) and desorption (at boiling temperature, room pressure) were carried out. The ¹³C NMR analysis has allowed us to establish: (1) the percentage of CO₂ stored in solution as HCO₃^?, CO₃^2? and DEA carbamate; (2) the formation of DEA carbamate as a function of absorption temperature and time; (3) the slower decomposition of DEA carbamate than that of bicarbonate. In the experiments planned to test the reuse of the regenerated amines, the absorbent solution was continuously circulated in a closed cycle while it was absorbing CO₂ in the absorber (set at 293 K) and simultaneously regenerating amine in the desorber (set at 388 K). After the equilibrium has been reached (13 h), the CO₂ absorption efficiency is comprised between 84.0% (DEA) and 82.6% (MDEA) and the average amine regeneration efficiency ranges between 69.6% (DEA) and 78.2% (MDEA). Additionally, MDEA is more stable towards thermal degradation than DEA.     

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.     

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.     

Catalysts and inhibitors for oxidative degradation of monoethanolamine

MEA solutions were subjected to oxidative degradation at both low and high gas rates. Solutions were degraded with 100 mL/min of 98%O₂/2%CO₂ with mass transfer achieved by vortexing. Solutions were analyzed for degradation products by IC and HPLC. In a parallel apparatus 7.5 L/min of 15%O₂/2%CO₂ was sparged through solution, with additional mass transfer achieved by vortexing. A Fourier Transform Infrared (FTIR) analyzer collected continuous gas-phase data on volatile products.Hydroxyethyl-formamide (HEF) and hydroxyethylimidazole (HEI) are the major liquid-phase oxidation products. In the presence of Fe²⁺ and Cu²⁺, HEF, HEI, and MEA losses increase by a factor of 3 compared to Fe²⁺ alone. Cr³⁺ and Ni²⁺, two metals present in stainless steel alloys, resulted in MEA losses that are 55% greater. In terms of oxidative degradation potential (greatest to lowest): Cu²⁺ > Cr³⁺/Ni²⁺ > Fe²⁺ > V⁵⁺.Inhibitor A reduces the formation of known products by 90% when catalyzed by Fe²⁺ and Cu²⁺ and by 99% with Cr³⁺/Ni²⁺. Inhibitor B reduces product rates by 97% and MEA losses by 75%, while a 100:1 ratio of EDTA to Fe²⁺ completely inhibits oxidation.     

Natural analogue of the rise and dissolution of liquid CO2 in the ocean

The behavior of natural carbon dioxide (CO₂) droplets (8–10 mm in diameter) were observed in a seafloor hydrothermal system at the Okinawa Trough. The natural CO₂ droplet contain 95–98% of CO₂, 2–3% of H₂S, and other gas species. The ascending CO₂ droplets were tracked by a remotely operated vehicle (ROV), and depth, temperature, salinity, pH and partial pressure of CO₂ (pCO₂) in seawater near the CO₂ droplets were measured during droplet ascent by a conductivity-temperature-depth sensor (CTD) and in situ pH/pCO₂ sensor. The visual images of the rising CO₂ droplets were recorded with a high definition television camera on the ROV. A mapping survey (400 m × 400 m; 4 horizontal layers) revealed a dominant distribution of low pH area over the natural CO₂ venting site. The size and rise rate of CO₂ droplets decreased during their ascent in the water column from depths of 1424 to 679 m (a tracking interval of 745 m). The CO₂ droplets dissolved gradually to become small flakes of CO₂ hydrate while rising, and these ascending flakes were found to disappear at 679 m depth. Although a pH as low as 5 was detected just above the liquid CO₂ venting site on the seafloor, no detectable pH depression in the water column ambient to the rising CO₂ droplets was observed. The results of the pH mapping survey showed only localized pH depression over the CO₂ venting site.     

Carbon dioxide storage capacity in uneconomic coal beds in Alberta,Canada: Methodology,potential and site identification

Methodology is presented for a first-order regional-scale estimation of CO₂ storage capacity in coals under sub-critical conditions, which is subsequently applied to Cretaceous-Tertiary coal beds in Alberta, Canada. Regions suitable for CO₂ storage have been defined on the basis of groundwater depth and CO₂ phase at in situ conditions. The theoretical CO₂ storage capacity was estimated on the basis of CO₂ adsorption isotherms measured on coal samples, and it varies between ∼20 kt CO₂/km² and 1260 kt CO₂/km², for a total of approximately 20 Gt CO₂. This represents the theoretical storage capacity limit that would be attained if there would be no other gases present in the coals or they would be 100% replaced by CO₂, and if all the coals will be accessed by CO₂. A recovery factor of less than 100% and a completion factor less than 50% reduce the theoretical storage capacity to an effective storage capacity of only 6.4 Gt CO₂. Not all the effective CO₂ storage capacity will be utilized because it is uneconomic to build the necessary infrastructure for areas with low storage capacity per unit surface. Assuming that the economic threshold to develop the necessary infrastructure is 200 kt CO₂/km², then the CO₂ storage capacity in coal beds in Alberta is greatly reduced further to a practical capacity of only ∼800 Mt CO₂.