The most commonly used technology today for low concentration CO2 capture is absorption with chemical solvents. This chemical absorption process is adapted from the gas processing industry where amine-based processes have been used commercially for the removal of acid gas impurities from process gas streams. However, problems of scale, efficiency, and stability become barriers when chemical solvents are used for high volume gas flows with a relatively smaller fraction of valuable product. The processes require large amounts of material undergoing significant changes in conditions, leading to high investment costs and energy consumption. In addition, degradation and oxidation of the solvents over time produces products that are corrosive and may require hazardous material handling procedures.
The currently preferred chemical solvent technology for carbon capture is amine-based chemical absorbent. CO2 in the gas phase dissolves into a solution of water and amine compounds. The amines react with CO2 in solution to form protonated amine (AH+), bicarbonate (HCO3-), and carbamate (ACO2-). As these reactions occur, more CO2 is driven from the gas phase into the solution due to the lower chemical potential of the liquid phase compounds at this temperature. When the solution has reached the intended CO2 loading, it is removed from contact with the gas stream and heated to reverse the chemical reaction and release high-purity CO2. The CO2-lean amine solvent is then recycled to contact additional gas. The flue gas must first be cooled and treated to remove reactive impurities such as sulfur, nitrogen oxides, and particulate matter. Otherwise, these impurities may react preferentially with the amines, reducing the capacity for CO2, or irreversibly poisoning the solvent. The resulting pure CO2 stream is recovered at pressures near atmospheric pressure. Compression, and the associated energy costs, would be required for geologic storage. Alkanolamines, simple combinations of alcohols and ammonia, are the most commonly used category of amine chemical solvents for CO2 capture. Reaction rates with specific acid gases differ among the various amines. In addition, amines vary in their equilibrium absorption characteristics and have different sensitivities with respect to solvent stability and corrosion.
Alkanolamines can be divided into three groups:
- Primary amines, including monoethanol amine (MEA) and diglycolamine (DGA)
- Secondary amines, including diethanol amine (DEA) and diisopropyl amine (DIPA)
- Tertiary amines, including triethanol amine (TEA) and methyldiethanol amine (MDEA)
MEA, relatively inexpensive and the lowest molecular weight, is the amine that has been used extensively for the purpose of removing CO2 from natural gas streams. MEA has a high enthalpy of solution with CO2, which tends to drive the dissolution process at high rates. However, this also means that a significant amount of energy must be used for regeneration. In addition, a high vapor pressure and irreversible reactions with minor impurities such as COS and CS2 result in solvent loss. Research on improved chemical solvents seeks a high absorption capacity for CO2 without a corresponding large energy requirement for regeneration. Other desirable properties include high chemical stability, low vapor pressure, and low corrosiveness. It has been shown that solvents based on piperazine-promoted K2CO3 can have reaction rates approaching that of MEA, but currently have lower capacity. Sterically hindered amines have been developed with similar capacity and possibly less regeneration energy requirement than conventional MEA absorbents. These modified GCEP Carbon Capture Technology. Amines attempt to balance good absorption and regeneration characteristics under some conditions due to the reduced chemical stability of the amine-CO2 anion. Controlled species selectivity is also possible with these compounds.
Dry Chemical Absorbents
Under some conditions, CO2 can undergo a reversible chemical reaction with a dry absorbent material. The chemical reaction can be reversed by changing the conditions, resulting in the release of pure CO2. Sodium carbonate supported on an inert particle has been proposed as such an absorbent. An exothermic reaction of sodium carbonate with CO2 and water held at 60 to 70ºC forms primarily sodium bicarbonate. The products must be heated to 120 to 200ºC to reverse the reaction. Lithium zirconate is also being investigated for its high capacity chemisorbtion separation of CO2 at high temperatures.
A number of solids can be used to react with CO2 to form stable compounds at one set of operating conditions and then, at another set of conditions, be regenerated to liberate the absorbed CO2 and reform the original compound. However, solids are inherently more difficult to work with than liquids, and no solid sorbent system for large scale recovery of CO2 from flue gas has yet been commercialized, although molecular sieve systems are used to remove impurities from a number of streams, such as in the production of pure H2.
Scientists have developed an amine-enriched sorbent (Gray et al., 2005) that has been investigated with flue gas streams at temperatures similar to those found after lime/limestone desulfurization scrubbing. The CO2 capture sorbents are prepared by treating high surface area substrates with various amine compounds. The immobilization of amine groups on the high surface area material significantly increases the contact area between CO2 and amine. This advantage, combined with the elimination of liquid water, has the potential to improve the energy efficiency of the process compared to MEA scrubbing Research Triangle Institute (RTI) is investigating a dry, inexpensive, regenerable, supported sorbent, sodium carbonate (Na2CO3), which reacts with CO2 and water to form sodium bicarbonate (NaHCO3). A temperature swing is then used to regenerate the sorbent and produce a pure CO2/water stream. This process is ideally suited for retrofit application in the non-power and power generation sectors. After condensing the water, the CO2 is ready for commercial use or sequestration. Laboratory and pilot plant tests have consistently achieved over 90% CO2 removal from simulated flue gas.
RTI’s process has advanced through pilot-scale testing with simulated and coal combustion flue gases. In addition, the reproducibility of their sorbent at a commercial operating facility (Su¨ d Chemie) has been confirmed. The process advantages translate into lower capital costs and power requirements than conventional MEA technology (based on a preliminary economic analysis) (Nelson et al., 2005, 2006a,b).
To address problems associated with pressure drop and heat transfer with solid sorbents, research is being conducted to examine the use of metallic monolith structures coated with a nano-structured hydrophobic zeolite-grafted amine. These systems, currently being researched by the University of Akron, could be tuneable for CO2 binding strength by altering the alkyl chain of the amine. Also, regenerable SO2 absorption may be possible through the use of aryl amines.
Ammonia-based wet scrubbing is similar in operation to amine systems. Ammonia and its derivatives react with CO2 via various mechanisms, one of which is the reaction of ammonium carbonate, CO2, and water to form ammoniumbicarbonate. This reaction has a significantly lower heat of reaction than amine-based systems, resulting in energy savings, provided the absorption/desorption cycle can be limited to this mechanism. Ammonia-based absorption has a number of other advantages over amine-based systems, such as the potential for high CO2 capacity, lack of degradation during absorption/regeneration, tolerance to oxygen in the flue gas, low cost, and potential for regeneration at high pressure. There is also the possibility of reaction with SOx and NOx—criteria pollutants found in flue gas—to form fertilizer (ammonium sulfate and ammonium nitrate) as a salable by-product. A few concerns exist related to ammonia’s higher volatility compared to that of MEA. One is that the flue gas must be cooled to the 60–80 F range to enhance the CO2 absorptivity of the ammonia compounds and to minimize ammonia vapor emissions during the absorption step. Additionally, there is concern over ammonia losses during regeneration, which occurs at elevated temperatures. R&D process improvements include process optimization to increase CO2 loading and use of various engineering techniques to eliminate ammonia vapor losses from the system during operation (Resnik et al., 2004, 2006; Yeh et al., 2005).
Another ammonia-based system, under development by Alstom, is the chilled ammonia process (CAP). This process uses the same AC/ABC absorption chemistry as the aqueous system, but differs in that no fertilizer is produced and a slurry of aqueous AC and ABC and solid ABC is circulated to capture CO2 (Black, 2006). The process operates at near freezing temperatures (32–50 F), and the flue gas is cooled prior to absorption using chilled water and a series of direct contact coolers. Technical hurdles associated with the technology include cooling the flue gas and absorber to maintain operating temperatures below 50 F (required to reduce ammonia slip, achieve high CO2 capacities), mitigating the ammonia slip during absorption and regeneration, achieving 90% removal efficiencies in a single stage, and avoiding fouling of heat transfer and other equipment by ABC deposition as a result of absorber operation with a saturated solution. Both the aqueous and chilled ammonia processes have the potential for improved energy efficiency over amine-based systems, if the hurdles can be overcome.
Mixed Chemical Physical Solvents
Some CO2 capture applications benefit from a mixture of physical and chemical solvents. The most commonly used examples are Sulfinol, a mixture of the physical solvent sulfolane and the amines DIPA or MDEA, and Amisol, a mixture of methanol and secondary amines. These hybrid solvents attempt to exploit the positive qualities of each constituent.