Components and special considerations

The largest plants commissioned at present fall below 1000 tonnes of recovered CO2/day. Large-scale carbon dioxide capture projects are

currently being planned. With absorber diameters of 40 to 50 feet considered feasible, CO2 recovery plant capacities of up to 8000 tonnes/day are

achievable, depending on the inlet flue gas CO2 concentration. Even larger plants can be realized by employing multiple absorbers that share a common stripper (Roberts, 2002). As a comparison, a 500 MWe coal fired power plant produces about 8900 tonnes/day, whilst a 400 MWe natural gas fired power plant produces about 3400 tonnes/day. These numbers of course vary somewhat with electric efficiency, fuel composition and CO2 capture rate.

Amine absorption can be designed to capture from 85 - 95 % of the CO2 in the flue gas and produce a CO2 with a purity of > 99.95 %. Both the level of recovery and the CO2 purity require optimization since there are no

theoretical limitations on these parameters.

The choice of amine(s) used for the absorption is also an issue for

optimization. Important considerations for choice of absorbent include CO2 -loading (mol CO2/mol amine), high solvent concentration in the aqueous solution, heat of reaction, heat of vaporization, reaction rate, the temperature level required for regeneration, corrosion issues and also cost. All of these parameters are obviously not optimal simultaneously for any one solvent;

high absorption rates generally cause high reaction heat rates etc. Finding the optimal solvent is thus a question of compromise. For example, MDEA

would offer energy savings compared to MEA but the reaction rate is lower and the absorption column would have to be much taller.

Aqueous solutions of amines are used to avoid excessive plant corrosion.

However, the water is a diluent that places additional demands on the process sizing and energy requirements. These factors need to be considered alongside the associated economics. Increasing the amine concentration by means of corrosion inhibitors and advanced amine formulations is therefore a high priority for the manufacturers.

Kansai Electric Power Company and Mitsubishi Heavy Industries have been developing sterically hindered amines, the most well known are called KS-1 and KS-2. These amines have the advantage of a lower circulation rate due to a higher CO2 loading differential, a lower regeneration temperature and a lower heat of reaction. They are also non-corrosive to carbon steel at 130°C in the presence of oxygen. A first commercial plant using KS-1 for Petronas Fertiliser Kedah Sbn Bhd’s fertilizer plant in Malaysia has been in operation since 1999 (Mimura et al., 2001).

Chemical absorption can be complemented with gas absorption membranes that act as contacting devices between the gas flow and the liquid flow. The gas and the amine solution are thereby not brought into direct contact and elements in the flue gas that deteriorate the amine solution, such as oxygen, are not transferred to the amine solution to the same extent. The problem of evaporation into the cleaned flue gas is reduced. The column pressure drop is also reduced, when compared with conventional packing, and the

efficiency reduction can therefore be smaller. The equipment can also be made more compact, due to the increased gas-liquid contact area, which is of particular importance in off-shore applications. The membrane technology was developed by Aker Kvaerner and used in gas separation applications within the oil and gas industry (Herzog and Falk-Pedersen, 2001). Scale-up to sizes required to capture CO2 from large power plants is considered to be a difficult issue.

As mentioned earlier, the CO2 concentration is the most important parameter that controls the absorption process. By applying supplementary firing before the HRSG the efficiency of the steam cycle increases and the CO2

concentration also increases. This has a positive effect on the overall plant efficiency.

Design issues relevant to CO2 recovery processes using amine solutions are discussed below. Most information is taken from Chapel et al. (2001) and is related to the Fluor Econamine process.

The absorption technology is described relatively detailed including many reported considerations to avoid potential problems and minimize costs. In section 2.3.3 reference is made to two commercial CO2 absorption plants operated on coal flue gas in US. Here no major problems are reported.

Regeneration energy

Absorption processes that are active at low partial pressures are those with higher reaction energies that require the most energy for regeneration. The design challenges are to a) minimize regeneration energy by selecting a solvent or mixture of solvents with a low reaction energy and b) to use low value heat source to provide this energy. MEA-based absorbent solutions generally require regeneration energies of 3 - 4 GJ/tonne CO2. Goals for ongoing development in the CASTOR project is to reach 2 GJ/tonne. (Note:

Cost calculations in Chapter 3 are based on 5 GJ/tonne CO2 according to IEA report). Steam with a pressure of about 3 - 4.5 bar is used to regenerate the solvent in the reboiler and steam at 4 - 6 bar is used in the reclaimer.

The steam for the reboiler has to be extracted from the steam turbine and thereby reduces the mass flow through the turbine and the power output of the turbine by up to 20%.

Uninhibited MEA is generally limited by corrosion problems to about 15-20 % by weight concentration. The low concentration raises the reboiler duty substantially. By applying inhibitors the concentration can be increased to about 25-30 % by weight, thus lowering the heat demand.

Flue gas temperature

Hot flue gases can cause solvent degradation and decrease absorber efficiency. For MEA based solvents the inlet flue gas must have a temperature of max. 50°C.

Oxygen

Presence of oxygen in the flue gas can increase corrosion and solvent degradation in the absorption system. Uninhibited alkanolamines such as MEA and DEA can be oxidized to give carboxylic acids and heat-stable amine salts. A solution to this problem is to apply an inhibitor to both

passivate the metal and inhibit amine degradation. An alternative approach would be to remove all of the oxygen by applying a near stoichiometric combustion and a catalytic reactor.

SOx

SOx reacts irreversibly with MEA based solvents to produce non-reclaimable corrosive salts. For MEA-based processes it is estimated that it is less expensive to install a SOx scrubber than accept the solvent loss at flue gas SOx levels exceeding 10 ppm(v). This is especially a problem for high sulphur fuels like coal but a less problem for natural gas. The acceptable SOx content in the flue gas and the investment in additional de-SOx plant is an optimisation issue in relation to the price of the absorbent.

SO3 presents additional problems in that it not only causes solvent loss through formation of heat stable salts but it also forms corrosive sulphuric acid aerosol in wet scrubbers. A special mist eliminator or a wet electrostatic precipitator and also flue gas cooling should be used to increase the SO3

removal in the scrubbing system.

NOx

Nitrogen oxides have led to corrosion problems and amine degradation in some absorption plants. The main problem is NO2 (including N2O4 etc.), which reacts to form nitric acid in the amine solvent and ultimately heat stable salts. An NO2-level of < 20 ppm(v) is recommended. Since modern plants are below this critical concentration, the limit on NO2 should be of minor concern.

Fly ash

Fly ash in the absorption solvent may cause foaming in the absorber and stripper, scaling and plugging of equipment, erosion, corrosion and increased solvent loss through chemical degradation and physical association with the waste sludge.

Soot

When amine capture is applied to heavy oil fired plant, soot presents a

special problem in the absorber. The soot stabilises an amine mist above the CO2 absorption zone that is not captured in the water wash zone. In this instance, a special mist eliminator has to be employed to prevent the micron sized MEA mist particles leaving the absorber with the CO2-lean flue gas.

Waste products

Degradation of the amine solution as described above creates a waste product that has to be dealt with, possibly by incineration. The quantity of waste is somewhat uncertain but it is anticipated to be of the order of several tens to hundreds of tonnes per year for a full-scale plant.