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Studies indicate that, in most cases, IGCC plants are slightly higher in cost without capture and slightly lower in cost with capture than similarly sized PC plants fitted with a CCS system. On average, NGCC systems have a lower COE than both types of new coal-based plants with or without capture for baseload operation. However, the COE for each of these systems can vary markedly due to regional variations in fuel cost, plant utilization, and a host of other parameters. NGCC costs are especially sensitive to the price of natural gas, which has risen significantly in recent years. So comparisons of alternative power system costs require a particular context to be meaningful.

For existing, combustion-based, power plants, CO2 capture can be accomplished by retrofitting an amine scrubber to the existing plant. However, a limited number of studies indicate that the post-combustion retrofit option is more cost-effective when accompanied by a major rebuild of the boiler and turbine to increase the efficiency and output of the existing plant by converting it to a supercritical unit. For some plants, similar benefits can be achieved by repowering with an IGCC system that includes CO2 capture technology. The feasibility and cost of any of these options is highly dependent on site-specific circumstances, including the size, age and type of unit, and the availability of space for accommodating a CO2 capture system. There has not yet been any systematic comparison of the feasibility and cost of alternative retrofit and repowering options for existing plants, as well as the potential for more cost-effective options employing advanced technology such as oxyfuel combustion.

Table 8.1 also illustrates the cost of CO2 capture in the production of H2, a commodity used extensively today for fuels and chemical production, but also widely viewed as a potential energy carrier for future energy systems. Here, the cost of CO2 capture is mainly due to the cost of CO2 compression, since separation of CO2 is already carried out as part of the H2 production process. Recent studies indicate that the cost of CO2 capture for current processes adds approximately 5 to 30 per cent to the cost of the H2 product.

In addition to fossil-based energy conversion processes, CO2 could also be captured in power plants fuelled with biomass. At present, biomass plants are small in scale (<100 MW). Hence, the resulting costs of capturing CO2 are relatively high compared to fossil alternatives. For example, the capturing of 0.19 MtCO2 yr-1 in a 24 MWe biomass IGCC plant is estimated to be about 82 US$/tCO2 (300 US$/tC), corresponding to an increase of the electricity costs due to capture of about 80 US$ MWh-1 (Audus and Freund, 2004). Similarly, CO2 could be captured in biomass-fuelled H2 plants. The cost is reported to be between 22 and 25 US$/tCO2 avoided (80-92 US$/tC) in a plant producing 1 million Nm3 d-1 of H2 (Makihira et al., 2003). This corresponds to an increase in the H2 product costs of about 2.7 US$ GJ-1 (i.e., 20% of the H2 costs without CCS). The competitiveness of biomass CCS systems is very sensitive to the value of CO2 emission reductions, and the associated credits obtained with systems resulting in negative emissions. Moreover, significantly larger biomass plants could benefit from economies of scale, bringing down costs of the CCS systems to broadly similar levels as those in coal plants. However, there is too little experience with large-scale biomass plants as yet, so that their feasibility has still not been proven and their costs are difficult to estimate.

CCS technologies can also be applied to other industrial processes. Since these other industrial processes produce off-gases that are very diverse in terms of pressure and CO2 concentration, the costs range very widely. In some of these non-power applications where a relatively pure CO2 stream is produced as a by-product of the process (e.g., natural gas processing, ammonia production), the cost of capture is significantly lower than capture from fossil-fuel-fired power plants. In other processes like cement or steel production, capture costs are similar to, or even higher than, capture from fossil-fuel-fired power plants.

New or improved technologies for CO2 capture, combined with advanced power systems and industrial process designs, can significantly reduce the cost of CO2 capture in the future. While there is considerable uncertainty about the magnitude and timing of future cost reductions, studies suggest that improvements to current commercial technologies could lower CO2 capture costs by at least 20-30%, while new technologies currently under development may allow for more substantial cost reductions in the future. Previous experience indicates that the realization of cost reductions in the future requires sustained R&D in conjunction with the deployment and adoption of commercial technologies.

8.2.2 Transport

The most common and usually the most economical method to transport large amounts of CO2 is through pipelines. A cost-competitive transport option for longer distances at sea might be the use of large tankers.

The three major cost elements for pipelines are construction costs (e.g., material, labour, possible booster station), operation and maintenance costs (e.g., monitoring, maintenance, possible energy costs) and other costs (e.g., design, insurance, fees, right-of-way). Special land conditions, like heavily populated areas, protected areas such as national parks, or crossing major waterways, may have significant cost impacts. Offshore pipelines are about 40% to 70% more costly than onshore pipes of the same size. Pipeline construction is considered to be a mature technology and the literature does not foresee many cost reductions.

Figure 8.1 shows the transport costs for 'normal' terrain conditions. Note that economies of scale dramatically reduce the cost, but that transportation in mountainous or densely populated areas could increase cost.

Tankers could also be used for transport. Here, the main cost elements are the tankers themselves (or charter costs), loading and unloading facilities, intermediate storage facilities, harbour

Figure 8.1 CO2 transport costs range for onshore and offshore pipelines per 250 km, 'normal' terrain conditions. The figure shows low (solid lines) and high ranges (dotted lines). Data based on various sources (for details see Chapter 4).

Mass flow rate (MtC02 yr1)

Figure 8.1 CO2 transport costs range for onshore and offshore pipelines per 250 km, 'normal' terrain conditions. The figure shows low (solid lines) and high ranges (dotted lines). Data based on various sources (for details see Chapter 4).

fees, and bunker fuel. The construction costs for large specialpurpose CO2 tankers are not accurately known since none have been built to date. On the basis of preliminary designs, the costs of CO2 tankers are estimated at US$ 34 million for ships of 10,000 tonnes, US$ 58 million for 30,000-tonne vessels, and US$ 82 million for ships with a capacity of 50,000 tonnes.

To transport 6 MtCO2 per year a distance of 500 km by ship would cost about 10 US$/tCO2 (37 US$/tC) or 5 US$/ tCO2/250km (18 US$/tC/250km). However, since the cost is relatively insensitive to distance, transporting the same 6 MtCO2 a distance of 1250 km would cost about 15 US$/tCO2 (55 US$/tC) or 3 US$/tCO2/250km (11 US$/tC/250km). This is close to the cost of pipeline transport, illustrating the point that ship transport becomes cost-competitive with pipeline transport if CO2 needs to be transported over larger distances. However, the break-even point beyond which ship transportation becomes cheaper than pipeline transportation is not simply a matter of distance; it involves many other aspects.

8.2.3 Storage

8.2.3.1 Geological storage3

Because the technologies and equipment used for geological storage are widely used in the oil and gas industries, the cost estimates can be made with confidence. However, there will be a significant range and variability of costs due to site-specific factors: onshore versus offshore, the reservoir depth and the geological characteristics of the storage formation (e.g., permeability, thickness, etc.). Representative estimates of the cost for storage in saline formations and disused oil and gas fields (see Table 8.2) are typically between 0.5-8.0 US$/ tCO2 stored (2-29 US$/tC), as explained in Section 5.9.3. The lowest storage costs will be associated with onshore, shallow, high permeability reservoirs and/or the reuse of wells and infrastructure in disused oil and gas fields.

The full range of cost estimates for individual options is very large. Cost information for storage monitoring is currently limited, but monitoring is estimated to add 0.1-0.3 US$ per tonne of CO2 stored (0.4-1.1 US$/tC). These estimates do not include any well remediation or long-term liabilities. The costs of storage monitoring will depend on which technologies are used for how long, regulatory requirements and how long-term monitoring strategies evolve.

When storage is combined with EOR, enhanced gas recovery (EGR) or ECBM, the benefits of enhanced production can offset some of the capture and storage costs. Onshore EOR operations have paid in the range of 10-16 US$ per tonne of CO2 (37-59 US$/tC). The economic benefit of enhanced production depends very much on oil and gas prices. It should be noted that most of the literature used as the basis for this report did not take into account the rise in oil and gas prices that started in 2003. For example, oil at 50 US$/barrel could justify a credit of 30 US$/tCO2 (110 US$/tC). The economic benefits from enhanced production make EOR and ECBM potential early cost-effective options for geological storage.

Table 8.2 Estimates of CO2 storage costs.

Option

Representative Cost Range (uS$/tonne CO2 stored)

Representative Cost Range (uS$/tonne C stored)

Geological - Storage1

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