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The CO2 capture efficiency of any system represented in Figure 2.6 is given in Equation 2.6. Table 2.11 summarises estimates of CO2 capture efficiencies for post and pre-combustion systems of interest that have been recently reported in several studies. This information is provided for illustrative purposes only as it is good practice to use measured data on volume captured rather than efficiency factors to estimate emissions from a CO2 capture installation.

Where:

EfflClenCyco2 capture technology = CO2 capture system efficiency (percent)

Where:

EfflClenCyco2 capture technology = CO2 capture system efficiency (percent)

c captured CO2

fuel

products

= amount of carbon in the captured CO2 stream (kg) = amount of carbon in fossil fuel or biomass input to the plant (kg) = amount of carbon in carbonaceous chemical or fuel products of the plant (kg).

Table 2.11

Typical CO2 capture efficiencies for post and pre-combustion systems

Technologies

Efficiency (%)

References

Power plant / Capture system

Average

Minimum

Maximum

Pulverised sub-bituminous/bituminous coal (250-760 MWe, 41-45% net plant efficiency)1'2 / Amine-based post-combustion capture.

90

85

96

Alstom, 2001; Chen et al, 2003; Gibbins et al, 2005; IEA GHG, 2004; Parsons, 2002; Rao and Rubin, 2002; Rubin et al., 2005; Simbeck, 2002; Singh et al, 2003.

Natural gas combined cycle (380-780 MWe, 55-58% net plant efficiency, LHV)1 / Amine-based post-combustion capture.

88

85

90

CCP, 2005; EPRI, 2002; IEA GHG, 2004; NETL, 2002; Rubin et al., 2005.

Integrated gasification combined cycle (400-830 MWe, 31-40% net plant efficiency)1 / Physical solvent-based pre-combustion capture (Selexol)

88

85

91

IEA GHG, 2003; NETL, 2002; Nsakala et al, 2003; Parsons, 2002; Rubin et al., 2005; Simbeck, 2002.

Electricity + H2 plant (coal, 2600-9900 GJ/hr input capacity)1 / Physical solvent-based pre-combustion capture (mostly Selexol)

83

80

90

Kreutz et al, 2005, Mitretek, 2003; NRC, 2004; Parsons, 2002.

Electricity + dimethyl ether (coal, 7900-8700 GJ/hr input capacity)1 / Physical solvent-based pre-combustion capture (Selexol or Rectisol)

64

32

97

Celik et al., 2005; Larson, 2003

Electricity + methanol (coal, 9900 GJ/hr input capacity)1 / Physical solvent-based pre-combustion capture (Selexol)

60

58

63

Larson, 2003

Electricity + Fischer-Tropsch liquids (coal, 16000 GJ/hr input capacity)1 / Physical solvent-based pre-combustion capture (Selexol)

91

Mitretek, 2001

1 Reference plant without CO2 capture system

2 These options include existing plants with retrofitting post-combustion capture system as well as new designs integrating power generation and capture systems.

TIER 3 CO2 EMISSION ESTIMATES

Because this is an emerging technology, it requires plant-specific reporting at Tier 3. Plants, with capture and storage will most probably meter the amount of gas removed by the gas stream and transferred to geological storage. Capture efficiencies derived from the measured data can be compared with the values in Table 2.11 as a verification cross-check.

Under Tier 3, the CO2 emissions are therefore estimated from the fuel consumption estimated as described in earlier sections of this chapter minus the metered amount removed.

Where:

s = source category or subcategory where capture takes place

Captures = Amount captured.

Productions = Estimated emissions, using these guidelines assuming no capture

Emissionss = Reported emission for the source category or sub-category

This method automatically takes into account any increase in energy consumption at the plant because of the capture process (since this will be reflected in the fuel statistics), and it does not require independent estimation of the capture efficiency, since the residual emissions are estimated more accurately by the subtraction. If the plant is supplied with biofuels, the corresponding CO2 emissions will be zero (these are already included in national totals due to their treatment in the AFOLU sector), so the subtraction of the amount of gas transferred to long-term storage may give negative emissions. This is correct since if the biomass carbon is permanently stored, it is being removed from the atmosphere. The corollary of this is that any subsequent emissions from CO2 transport, CO2 injection and the storage reservoir itself should be counted in national total emissions, irrespective of whether the carbon originates from fossil sources or recent biomass production. This is why in sections 5.3 (CO2 transport), 5.4 (Injection) and 5.5 (Geological Storage) no reference is made to the origin of the CO2 stored in underground reservoirs. The metering for the amount removed should be installed in line with industrial practice and will normally be accurate to about 1 percent.

Quantities of CO2 for later use and short-term storage should not be deducted from CO2 emissions except when the CO2 emissions are accounted for elsewhere in the inventory12.

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