Confidence level (see Table 3.6)
low to moderate
Notes: All costs in this table are for capture only and do not include the costs of CO2 transport and storage; see Chapter 8 for total CCS costs. * Reported HHV values converted to LHV assuming LHV/HHV = 0.96 for coal, 0.846 for hydrogen, and 0.93 for F-T liquids. ** CO2 capture efficiency = (C in CO2 captured)/(C in fossil fuel input to plant - C in carbonaceous fuel products of plant) x100; C associated with imported electricity is not included. ***Includes CO2 emitted in the production of electricity imported by the plant. ****Reported total plant investment values increased by 3.5% to estimate total capital requirement.
producing liquid fuels plus electricity. In these cases the amounts of electricity produced are sizeable compared to the liquid products, so the assumed selling price of electricity has a major influence on the product cost results. So too does the assumption in two of the cases of co-disposal of H2S with CO2 (as described above). For these reasons, the incremental cost of CO2 capture ranges from a 13% decrease to a 13% increase in fuel product cost relative to the no-capture case. Note too that the overall level of CO2 reductions per unit of product is only 27-56%. This is because a significant portion of carbon in the coal feedstock is exported with the liquid fuel products. Nonetheless, an important benefit of these fuel-processing schemes is a reduction (of 30-38%) in the carbon content per unit of fuel energy relative to the feedstock fuel. To the extent these liquid fuels displace other fuels with higher carbon per unit of energy, there is a net benefit in end-use CO2 emissions when the fuels are burned. However, no credit for such reductions is taken in Table 3.11 because the system boundary considered is confined to the fuel production plant.
factors, particularly the scale of operation and the electricity price. Based on 2 MtCO2 yr-1 and an electricity price of US$ 0.05 kWh-1, the cost is estimated to be around 10 US$/tCO2 emissions avoided. Electricity accounts for over half of the total cost.
As noted in Chapter 2, cement plants are the largest industrial source of CO2 apart from power plants. Cement plants normally burn lower cost high-carbon fuels such as coal, petroleum coke and various wastes. The flue gas typically has a CO2 concentration of 14-33% by volume, significantly higher than at power plants, because CO2 is produced in cement kilns by decomposition of carbonate minerals as well as by fuel combustion. The high CO2 concentration would tend to reduce the specific cost of CO2 capture from flue gas. Pre-combustion capture, if used, would only capture the fuel-related CO2, so would be only a partial solution to CO2 emissions. Oxy-fuel combustion and capture using calcium sorbents are other options, which are described in Sections 3.2.4 and 3.7.11.
3.7.8 Capture costs for other industrial processes (current technology)
CO2 can be captured in other industrial processes using the techniques described earlier for power generation. While the costs of capture may vary considerably with the size, type and location of industrial processes, such costs will be lowest for processes or plants having: streams with relatively high CO2 concentrations; process plants that normally operate at high load factors; plants with large CO2 emission rates; and, processes that can utilize waste heat to satisfy the energy requirements of CO2 capture systems. Despite these potential advantages, little detailed work has been carried out to estimate costs of CO2 capture at industrial plants, with most work focused on oil refineries and petrochemical plants. A summary of currently available cost studies appears in Table 3.12.
220.127.116.11 Oil refining and petrochemical plants Gas-fired process heaters and steam boilers are responsible for the bulk of the CO2 emitted from typical oil refineries and petrochemical plants. Although refineries and petrochemical plants emit large quantities of CO2, they include multiple emission sources often dispersed over a large area. Economies of scale can be achieved by using centralized CO2 absorbers or amine regenerators but some of the benefits are offset by the cost of pipes and ducts. Based on Table 3.14, the cost of capturing and compressing CO2 from refinery and petrochemical plant heaters using current technology is estimated to be 50-60 US$/ tCO2 captured. Because of the complexity of these industrial facilities, along with proprietary concerns, the incremental cost of plant products is not normally reported.
High purity CO2 is currently vented to the atmosphere by some gas processing and petrochemical plants, as described in Chapter 2. The cost of CO2 capture in such cases would be simply the cost of drying and compressing the CO2 to the pressure required for transport. The cost would depend on various
Integrated steel mills are some of the world's largest emitters of CO2, as described in Chapter 2. About 70% of the carbon introduced into an integrated steel mill is contained in the blast furnace gas in the form of CO2 and CO, each of which comprise about 20% by volume of the gas. The cost of capturing CO2 from blast furnace gas was estimated to be 35 US$/tCO2 avoided (Farla et al., 1995) or 18 US$/tCO2 captured (Gielen, 2003).
Iron ore can be reacted with synthesis gas or hydrogen to produce iron by direct reduction (Cheeley, 2000). Direct reduction processes are already used commercially but further development work would be needed to reduce their costs so as to make them more widely competitive with conventional iron production processes. The cost of capturing CO2 from a direct reduction iron (DRI) production processes was estimated to be 10 US$/tCO2 (Gielen, 2003). CO2 also could be captured from other gases in iron and steel mills but costs would probably be higher as they are more dilute or smaller in scale.
The main large point sources of biomass-derived CO2 are currently wood pulp mills, which emit CO2 from black liquor recovery boilers and bark-fired boilers, and sugar/ethanol mills, which emit CO2 from bagasse-fired boilers. Black liquor is a byproduct of pulping that contains lignin and chemicals used in the pulping process. The cost of post-combustion capture was estimated to be 34 US$/tCO2 avoided in a plant that captures about 1 MtCO2 yr-1 (Mollersten et al., 2003). Biomass gasification is under development as an alternative to boilers.
CO2 could be captured from sucrose fermentation and from combustion of sugar cane bagasse at a cost of about 53 US$/ tCO2 avoided for a plant capturing 0.6 MtCO2 yr-1 avoided (Mollersten et al., 2003). CO2 from sugar cane fermentation has a high purity, so only drying and compression is required. The overall cost is relatively high due to an annual load factor that is lower than that of most power stations and large industrial
Study Assumptions and Cost Results
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