CO2 Scrubber

Entails passing the flue gas stream through an absorbent stream but in this case the CO2 chemically reacts with the absorbent to reduce the Gibbs free energy of the mixture.

The absorption reaction requires a low temperature of approximately 50oC and the desorption reaction to regenerate the absorbent occurs at approximately 120 oC (ESRU 2006). Chemical absorption is most effective with low CO2 concentrations and is therefore appropriate for flue gas processing where the CO2 is diluted with air and steam.

To further consider CO2 capture technologies, the technology must be placed in
the context of the power plant. Among power plants fueled by natural gas, the current
predominant system is natural gas combined cycle (NGCC).

Among power plants fueled by coal the most common system is a pulverized coal power plant (PC). In both systems, the fuel is combusted without chemical preprocessing except that which is necessary to remove contaminants. However, both coal and natural gas are capable of being chemically reformed through partial oxidation reactions into syngas, a mixture of CO and ?

Subsequently the syngas may be combusted in a combined cycle system for
electricity generation. When coal is the fuel the reforming occurs in a gasifier, this entire
process is called integrated gasification combined cycle (IGCC). With natural gas the
reforming can take place with catalytic partial oxidation (CPO) and the process is called
integrated reforming combined cycle (IRCC).

Chemical preprocessing through gasification or catalytic partial oxidation enables the carbon to be separated out of the syngas before the syngas is diluted by air in the combustion process. When capturing carbon pre-combustion, adsorption is typically employed to separate the carbon bearing species from the syngas.

When coal or natural gas is combusted without chemical modification, chemical absorption is well suited to remove CO2 from the flue gas.

The performance of the separation technology is largely dependent on how it is integrated into the power plant system; therefore, for the majority of this study, capture technologies will be considered within the context of the power generation system.

Pre-combustion capture occurs at high total pressure and high CO2 fraction. These
conditions are present because the syngas exiting the reformer is at high pressure and has not yet been diluted with air.

Capture under these conditions is inherently easier because there is a larger driving force so less energy input is required. Post-combustion capture occurs after the syngas has been diluted in the combustion process and expanded in the turbine.

Therefore less driving force is present and separation is more difficult.  Nevertheless, post-combustion capture requires less system integration than precombustion capture.

Post-Combustion Capture

Chemical Absorption

Chemical absorption of CO2 from gas streams is currently utilized in many
industries using monoethanolamine.

Once CO2 is absorbed, the monoethanolamine is thermally regenerated to release
CO2 and H2O, which must be separated through condensing the H2O (Soong 2005). The
ability to absorb and then desorb CO2 for capture and release without degrading the
reactants is the primary factor that makes monoethanolamine commonly used for CO2
capture.

Post-combustion CO2 capture monoethanolamine system.  The CO2 rich flue gas flows through an absorption chamber with a counter flow of the lean monoethanolamine solvent. CO2 and the solvent chemically react and are pumped out of the absorber as rich solvent. The thermal regeneration used to strip the CO2 and regenerate the lean solvent occurs at high temperature and is endothermic requiring that approximately 4MJ of heat be added per kg of recovered CO2.

A heat exchanger between rich and lean solvents is commonly utilized to recycle
some of the heat, but the majority is extracted from the low-pressure steam turbine. The
primary cost drivers of the monoethanolamine system are the heat utilized for
regeneration, solvent loss, and CO2 loading.

Development of power plant post-combustion chemical absorption CO2 capture
technologies has resulted in both chemical and system level advancements that reduce
costs. Praxair, (Chakravarti 2001), Mitsubishi (2002) and FluorDaniel (Chapel 1999) all
attempted to develop low cost products by decreasing the impact of one or more of these cost drivers.

In a review of Praxair’s CO2 capture technology, Chakravarti 2001 notes:
“Chemical absorption with [monoethanolamine] has been generally used in processes
such as natural gas sweetening and hydrogen production for the rejection of carbon
dioxide.” Similar processes using monoethanolamine are not cost effective for postcombustion CO2 capture because of the high operating cost and corrosion rates.

According to Chakravarti, Praxair determined the operating cost and corrosion rates are
worth mitigating with process modifications because of the high loading rates even at low
partial pressure. In order to mitigate the corrosion problems, the CO2 rich monoethanolamine is deoxygenated by depressurization as described by Chakravarti.
Praxair reduced operating costs by employing monoethanolamine blends with
concentrations of up to 50 percent from 30 percent thus reducing the high cost steam
consumption for regeneration.

Similarly, Mitsubishi developed advanced post-combustion CO2 capture technology based on monoethanolamine (Mitsubishi 2002). Unlike the Praxair technology, which utilizes a unique process, Mitsubishi’s technology uses a unique reagent called KS-1, a sterically hindered monoethanolamine with reduced oxidation rates. According to Mitsubishi, KS-1 has improved operating characteristics with respect to monoethanolamines. The reduced oxidation rate decreases the degradation of the solvent and solvent loss enabling operation without a corrosion inhibitor. While the Mitsubishi data offers a relative comparison, no absolute data is provided and no background on the testing used to generate the data is discussed. Based on the data provided, Mitsubishi maintains the total CO2 capture cost to be approximately $ per thousand standard cubic feet (MSCF) or $20 per ton for a coal fired boiler and $1.44 per MSCF or $28 per ton for a natural gas fired gas turbine.  

The relatively higher CO2 capture cost per ton in gas turbine systems is due to the low CO2 flue gas concentration of 3 to 5 percent compared to 12 to 14 percent coal fired boiler flue gas.  Thus, the gas turbine KS-1 system operates with a lower CO2 loading parameter. Despite the uncertainty of the data source, the low cost of the KS-1 system appears to make the capture process comparable with a current trading value of approximately $20 per ton and, therefore, should be considered further.

A third flue gas CO2 capture technology was developed by FluorDaniel and is
described by Chapel (1999). The FluorDaniel Econamine FG process utilizes an
inhibited 30 percent by mass monoethanolamine solution for CO2 capture.  

According to Chapel, the inhibitor reduces corrosion and solvent degradation problems, which ultimately drives down cost. Chapel conducted an economic analysis for a coal-fired plant with a typical 13 percent by mass flue gas CO2 concentration and natural gas fired plant with a typical 3 percent by mass flue gas CO2 concentration.  

The resulting capital and operating cost for a 1000 ton per day coal-fired plant was $29.5 per ton and for a 1000 ton per day natural gas fired plant $43.5 per ton. In a conversation with co-author Carl Mariz, Mariz speculated capital cost improvements along with efficiency improvements and economies of scale could reduce the total cost to between $20 per ton and $25 per ton for a 500 MW coal-fired plant (Mariz 2005). Given the potential cost reductions cited by Mariz the Economanie FG process should be considered further because the cost could become comparable with current CO2 credit trading values. 

Biological Absorption

An alternative post-combustion capture technology known as “enhanced photosynthetic CO2 mitigation”. The photosynthetic CO2 mitigation system described passes cooled flue gas through a bioreactor, containing thermophilic organisms that use chlorophyll to produce sugar from CO2.

As the microalgea age, the CO2 uptake is limited. Some of the microalgea must
be periodically removed to provide sufficient space and light available for new
productive microalgea. Light is collected in parabolic solar dishes then transmitted
through fiber optic cables to the bioreactor. According to Bayless, this current light
collection and transmission system is cost prohibitive. With advances in microbial
research and light delivery systems, future developments might make similar
bioremediation technologies feasible, especially since photosynthesis alleviates the need
for CO2 storage. Currently, Bayless does not suggest photosynthetic CO2 mitigation is a
near term solution and consequently it will not be considered further in this study.

Pre-Combustion Capture Pre-combustion capture has the potential to occur under high CO2 partial pressure and high fuel stream total pressure. In order to utilize pre-combustion capture, both coal and natural gas must be partially oxidized into syngas, a mixture of predominately CO, CO2 and H2. Partial oxidation or reforming can be implemented with coal in an integrated gasification combined cycle power plant and with natural gas in an integrated reforming combined cycle power plant. A discussion of both technologies follows. 

Integrated Gasification Combined Cycle (IGCC)

In the case of coal, the coal and either oxygen or air, flow into the gasifier, where
under elevated pressure and temperature, the coal undergoes partial oxidation to produce
syngas. The actual composition of syngas can vary by site in the amount and type of
constituents. Table 3 provides a sample of gasification sites and their respective syngas
constituents from 11 different power plants or chemical plants that gasify coal (Brdar,
2000). The integrated gasification combined cycle power plant subsystems, which
potentially include a CO2 capture system, must be robust for the range of constituents and concentrations.

In an integrated gasification combined cycle power plant without CO2 capture, as
shown in Figure 4, the syngas is scrubbed to remove SO2 and combusted in a gas turbine
to produce about 60 percent of the electricity.  

The hot exhaust is delivered to a heat recovery steam generator (HRSG) to produce steam, which is sent to a steam turbine that produces the remaining 40 percent of the plant’s electricity. The thermal efficiency of advanced integrated gasification combined cycle power plants and sub critical coal fired boiler power plants are 46 percent higher heating value and 34 percent higher heating value respectively (Hughes, 2000).  

Consequently integrated gasification combined cycle power plants convert coal to electricity 35 percent more efficiently than pulverized coal power plants so they can use 35 percent less coal to produce the same amount of electricity. In terms of CO2 emissions, the 35 percent less fuel utilized per kWh translates into a 35 percent CO2 reduction on a tons/kWh basis.

Other advanced coal technologies such as super-critical coal boilers and fluidized
bed combustors are capable of achieving comparable efficiencies. Nordjyllands, the ultra
super-critical coal fired power plant in Denmark, operates at 4200 PSI and 47 percent lower heating value (Bendixen 2003). The formation of syngas, however, provides
integrated gasification combined cycle power plants with an opportunity to employ precombustion capture, a significant competitive advantage in a carbon constrained market.

An integrated gasification combined cycle power plant with precombustion CO2 capture, syngas leaves the gasifier and is processed in a shift reactor, which reacts the CO with H2O