0.23 ± 0.07

0.42 ± 0.09

0.71 ± 0.14

Costs (US$/tCO2 net injected) 100 km offshore 500 km offshore

6 31

12-14 13-16

Table TS.8. Costs for ocean storage at depths deeper than 3,000 m.

Ocean storage method

Fixed pipeline Moving ship/platforma a The costs for the moving ship option are for injection depths of 2,000-2,500 m.

via pipelines) are not included in the cost of ocean storage. However, the costs of offshore pipelines or ships, plus any additional energy costs, are included in the ocean storage cost. The costs of ocean storage are summarized in Table TS.8. These numbers indicate that, for short distances, the fixed pipeline option would be cheaper. For larger distances, either the moving ship or the transport by ship to a platform with subsequent injection would be more attractive.

Legal aspects and public perception

The global and regional treaties on the law of the sea and marine environment, such as the OSPAR and the London Convention discussed earlier in Section 5 for geological storage sites, also affect ocean storage, as they concern the 'maritime area'. Both Conventions distinguish between the storage method employed and the purpose of storage to determine the legal status of ocean storage of CO2. As yet, however, no decision has been made about the legal status of intentional ocean storage.

The very small number of public perception studies that have looked at the ocean storage of CO2 indicate that there is very little public awareness or knowledge of this subject. In the few studies conducted thus far, however, the public has expressed greater reservations about ocean storage than geological storage. These studies also indicate that the perception of ocean storage changed when more information was provided; in one study this led to increased acceptance of ocean storage, while in another study it led to less acceptance. The literature also notes that 'significant opposition' developed around a proposed CO2 release experiment in the Pacific Ocean.

7. Mineral carbonation and industrial uses

This section deals with two rather different options for CO2 storage. The first is mineral carbonation, which involves converting CO2 to solid inorganic carbonates using chemical reactions. The second option is the industrial use of CO2, either directly or as feedstock for production of various carbon-containing chemicals.

Mineral carbonation: technology, impacts and costs

Mineral carbonation refers to the fixation of CO2 using alkaline and alkaline-earth oxides, such as magnesium oxide (MgO) and calcium oxide (CaO), which are present in naturally occurring silicate rocks such as serpentine and olivine. Chemical reactions between these materials and CO2 produces compounds such as magnesium carbonate (MgCO3) and calcium carbonate (CaCO3, commonly known as limestone). The quantity of metal oxides in the silicate rocks that can be found in the earth's crust exceeds the amounts needed to fix all the CO2 that would be produced by the combustion of all available fossil fuel reserves. These oxides are also present in small quantities in some industrial wastes, such as stainless steel slags and ashes. Mineral carbonation produces silica and carbonates that are stable over long time scales and can therefore be disposed of in areas such as silicate mines, or re-used for construction purposes (see Figure TS.10), although such re-use is likely to be small relative to the amounts produced. After carbonation, CO2 would not be released to the atmosphere. As a consequence, there would be little need to monitor the disposal sites and the associated risks would be very low. The storage potential is difficult to estimate at this early phase of development. It would be limited by the fraction of silicate reserves that can be technically exploited, by environmental issues such as the volume of product disposal, and by legal and societal constraints at the storage location.

The process of mineral carbonation occurs naturally, where it is known as 'weathering'. In nature, the process occurs very slowly; it must therefore be accelerated considerably to be a viable storage method for CO2 captured from anthropogenic sources. Research in the field of mineral carbonation therefore focuses on finding process routes that can achieve reaction rates viable for industrial purposes and make the reaction more energy-efficient. Mineral carbonation technology using natural silicates is in the research phase but some processes using industrial wastes are in the demonstration phase.

A commercial process would require mining, crushing and milling of the mineral-bearing ores and their transport to a processing plant receiving a concentrated CO2 stream from a capture plant (see Figure TS.10). The carbonation process

Generation Storage process Re-use/Disposal

Figure TS.10. Material fluxes and process steps associated with the mineral carbonation of silicate rocks or industrial residues (Courtesy ECN).

energy required would be 30 to 50% of the capture plant output. Considering the additional energy requirements for the capture of CO2, a CCS system with mineral carbonation would require 60 to 180% more energy input per kilowatt-hour than a reference electricity plant without capture or mineral carbonation. These energy requirements raise the cost per tonne of CO2 avoided for the overall system significantly (see Section 8). The best case studied so far is the wet carbonation of natural silicate olivine. The estimated cost of this process is approximately 50-100 US$/tCO2 net mineralized (in addition to CO2 capture and transport costs, but taking into account the additional energy requirements). The mineral carbonation process would require 1.6 to 3.7 tonnes of silicates per tonne of CO2 to be mined, and produce 2.6 to 4.7 tonnes of materials to be disposed per tonne of CO2 stored as carbonates. This would therefore be a large operation, with an environmental impact similar to that of current large-scale surface mining operations. Serpentine also often contains chrysotile, a natural form of asbestos. Its presence therefore demands monitoring and mitigation measures of the kind available in the mining industry. On the other hand, the products of mineral carbonation are chrysotile-

free, since this is the most reactive component of the rock and therefore the first substance converted to carbonates.

A number of issues still need to be clarified before any estimates of the storage potential of mineral carbonation can be given. The issues include assessments of the technical feasibility and corresponding energy requirements at large scales, but also the fraction of silicate reserves that can be technically and economically exploited for CO2 storage. The environmental impact of mining, waste disposal and product storage could also limit potential. The extent to which mineral carbonation may be used cannot be determined at this time, since it depends on the unknown amount of silicate reserves that can be technically exploited, and environmental issuessuch as those noted above.

Industrial uses

Industrial uses of CO2 include chemical and biological processes where CO2 is a reactant, such as those used in urea and methanol production, as well as various technological applications that use CO2 directly, for example in the horticulture industry, refrigeration, food packaging, welding, beverages and fire extinguishers. Currently, CO2 is used at a rate of approximately 120 MtCO2 per year (30 MtC yr-1) worldwide, excluding use for EOR (discussed in Section 5). Most (two thirds of the total) is used to produce urea, which is used in the manufacture of fertilizers and other products. Some of the CO2 is extracted from natural wells, and some originates from industrial sources - mainly high-concentration sources such as ammonia and hydrogen production plants - that capture CO2 as part of the production process.

Industrial uses of CO2 can, in principle, contribute to keeping CO2 out of the atmosphere by storing it in the "carbon chemical pool" (i.e., the stock of carbon-bearing manufactured products). However, as a measure for mitigating climate change, this option is meaningful only if the quantity and duration of CO2 stored are significant, and if there is a real net reduction of CO2 emissions. The typical lifetime of most of the CO2 currently used by industrial processes has storage times of only days to months. The stored carbon is then degraded to CO2 and again emitted to the atmosphere. Such short time scales do not contribute meaningfully to climate change mitigation. In addition, the total industrial use figure of 120 MtCO2 yr-1 is small compared to emissions from major anthropogenic sources (see Table TS.2). While some industrial processes store a small proportion of CO2 (totalling roughly 20 MtCO2 yr-1) for up to several decades, the total amount of long-term (century-scale) storage is presently in the order of 1 MtCO2 yr-1 or less, with no prospects for major increases.

Another important question is whether industrial uses of CO2 can result in an overall net reduction of CO2 emissions by substitution for other industrial processes or products. This can be evaluated correctly only by considering proper system boundaries for the energy and material balances of the CO2 utilization processes, and by carrying out a detailed life-cycle analysis of the proposed use of CO2. The literature in this area is limited but it shows that precise figures are difficult to estimate and that in many cases industrial uses could lead to an increase in overall emissions rather than a net reduction. In view of the low fraction of CO2 retained, the small volumes used and the possibility that substitution may lead to increases in CO2 emissions, it can be concluded that the contribution of industrial uses of captured CO2 to climate change mitigation is expected to be small.

8. Costs and economic potential

The stringency of future requirements for the control of greenhouse gas emissions and the expected costs of CCS systems will determine, to a large extent, the future deployment of CCS technologies relative to other greenhouse gas mitigation options. This section first summarizes the overall cost of CCS for the main options and process applications considered in previous sections. As used in this summary and the report, "costs" refer only to market prices but do not include external costs such as environmental damages and broader societal costs that may be associated with the use of CCS. To date, little has been done to assess and quantify such external costs. Finally CCS is examined in the context of alternative options for global greenhouse gas reductions.

Cost of CCS systems

As noted earlier, there is still relatively little experience with the combination of CO2 capture, transport and storage in a fully integrated CCS system. And while some CCS components are already deployed in mature markets for certain industrial applications, CCS has still not been used in large-scale power plants (the application with most potential).

The literature reports a fairly wide range of costs for CCS components (see Sections 3-7). The range is due primarily to the variability of site-specific factors, especially the design, operating and financing characteristics of the power plants or industrial facilities in which CCS is used; the type and costs of fuel used; the required distances, terrains and quantities involved in CO2 transport; and the type and characteristics of the CO2 storage. In addition, uncertainty still remains about the performance and cost of current and future CCS technology components and integrated systems. The literature reflects a widely-held belief, however, that the cost of building and operating CO2 capture systems will decline over time as a result of learning-by-doing (from technology deployment) and sustained R&D. Historical evidence also suggests that costs for first-of-a-kind capture plants could exceed current estimates before costs subsequently decline. In most CCS systems, the cost of capture (including compression) is the largest cost component. Costs of electricity and fuel vary considerably from country to country, and these factors also influence the economic viability of CCS options.

Table TS.9 summarizes the costs of CO2 capture, transport and storage reported in Sections 3 to 7. Monitoring costs are also reflected. In Table TS.10, the component costs are combined to show the total costs of CCS and electricity generation for three power systems with pipeline transport and two geological storage options.

For the plants with geological storage and no EOR credit, the cost of CCS ranges from 0.02-0.05 US$/kWh for PC plants and 0.01-0.03 US$/kWh for NGCC plants (both employing post-combustion capture). For IGCC plants (using pre-combustion capture), the CCS cost ranges from 0.01-0.03 US$/kWh relative to a similar plant without CCS. For all electricity systems, the cost of CCS can be reduced by about 0.01-0.02 US$/kWh when using EOR with CO2 storage because the EOR revenues partly compensate for the CCS costs. The largest cost reductions are seen for coal-based plants, which capture the largest amounts of CO2. In a few cases, the low end of the CCS cost range can be negative,

Table TS.9. 2002 Cost ranges for the components of a CCS system as applied to a given type of power plant or industrial source. The costs of the separate components cannot simply be summed to calculate the costs of the whole CCS system in US$/CO2 avoided. All numbers are representative of the costs for large-scale, new installations, with natural gas prices assumed to be 2.8-4.4 US$ GJ-1 and coal prices 1-1.5 US$ GJ-1.

Table TS.9. 2002 Cost ranges for the components of a CCS system as applied to a given type of power plant or industrial source. The costs of the separate components cannot simply be summed to calculate the costs of the whole CCS system in US$/CO2 avoided. All numbers are representative of the costs for large-scale, new installations, with natural gas prices assumed to be 2.8-4.4 US$ GJ-1 and coal prices 1-1.5 US$ GJ-1.

CCS system components

Cost range


Capture from a coal- or gas-fired power plant

15-75 US$/tCO2 net captured

Net costs of captured CO2, compared to the same plant without capture.

Capture from hydrogen and ammonia production or gas processing

5-55 US$/tCO2 net captured

Applies to high-purity sources requiring simple drying and compression.

Capture from other industrial sources

25-115 US$/tCO2 net captured

Range reflects use of a number of different technologies and fuels.


1-8 US$/tCO2 transported

Per 250 km pipeline or shipping for mass flow rates of 5 (high end) to 40 (low end) MtCO2 yr-1.

Geological storage3

0.5-8 US$/tCO2 net injected

Excluding potential revenues from EOR or ECBM.

Geological storage: monitoring and verification

0.1-0.3 US$/tCO2 injected

This covers pre-injection, injection, and post-injection monitoring, and depends on the regulatory requirements.

Ocean storage

5-30 US$/tCO2 net injected

Including offshore transportation of 100-500 km, excluding monitoring and verification.

Mineral carbonation

50-100 US$/tCO2 net mineralized

Range for the best case studied. Includes additional energy use for carbonation.

a Over the long term, there may be additional costs for remediation and liabilities.

a Over the long term, there may be additional costs for remediation and liabilities.

indicating that the assumed credit for EOR over the life of the plant is greater than the lowest reported cost of CO2 capture for that system. This might also apply in a few instances of low-cost capture from industrial processes.

In addition to fossil fuel-based energy conversion processes, CO2 could also be captured in power plants fueled with biomass, or fossil-fuel plants with biomass co-firing. At present, biomass plants are small in scale (less than 100 MWe). This means that the resulting costs of production with and without CCS are relatively high compared to fossil alternatives. Full CCS costs for biomass could amount to 110 US$/tCO2 avoided. Applying CCS to biomass-fuelled or co-fired conversion facilities would lead to lower or negative13 CO2 emissions, which could reduce the costs for this option, depending on the market value of CO2 emission reductions. Similarly, CO2 could be captured in biomass-fueled H2 plants. The cost is reported to be 22-25 US$/tCO2 (80-92 US$/tC) avoided in a plant producing 1 million Nm3 day-1 of H2, and corresponds to an increase in the H2 product costs of about 2.7 US$ GJ-1. Significantly larger biomass plants could potentially benefit from economies of scale, bringing down costs of the CCS systems to levels broadly similar to coal plants. However, to date, there has been little experience with large-scale biomass plants, so their feasibility has not been proven yet, and costs and potential are difficult to estimate.

The cost of CCS has not been studied in the same depth for non-power applications. Because these sources are very diverse in terms of CO2 concentration and gas stream pressure, the available cost studies show a very broad range. The lowest costs were found for processes that already separate CO2 as part of the production process, such as hydrogen production (the cost of capture for hydrogen production was reported earlier in Table TS.4). The full CCS cost, including transport and storage, raises the cost of hydrogen production by 0.4 to 4.4 US$ GJ-1 in the case of geological storage, and by -2.0 to 2.8 US$ GJ-1 in the case of EOR, based on the same cost assumptions as for Table TS.10.

Cost of CO2 avoided

Table TS.10 also shows the ranges of costs for 'CO2 avoided'. CCS energy requirements push up the amount of fuel input (and therefore CO2 emissions) per unit of net power output. As a result, the amount of CO2 produced per unit of product (a kWh of electricity) is greater for the power plant with CCS than the reference plant, as shown in Figure TS.11. To determine the CO2 reductions one can attribute to CCS, one needs to compare CO2 emissions per kWh of the plant with capture to that of a reference plant without capture. The difference is referred to as the 'avoided emissions'.

13 If for example the biomass is harvested at an unsustainable rate (that is, faster than the annual re-growth), the net CO2 emissions of the activity might not be negative.

Table TS.10. Range of total costs for CO2 capture, transport and geological storage based on current technology for new power plants using bituminous coal or natural gas

Power plant performance and cost parameters'

Pulverized coal power plant

Natural gas combined cycle power plant

Integrated coal gasification combined cycle power plant

Reference plant without CCS

Cost of electricity (US$/kWh)

Power plant with capture

Increased fuel requirement (%)

CO2 captured (kg/kWh)

CO2 avoided (kg/kWh)

% CO2 avoided

Power plant with capture and geological storageb

Cost of electricity (US$/kWh)

% increase in cost of electricity

Mitigation cost (US$/tCO2 avoided)

Power plant with capture and enhanced oil recoveryc

Cost of electricity (US$/kWh)

% increase in cost of electricity

Mitigation cost (US$/tCO2 avoided)

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