Economics act against CCS retrofits

Oct. 4, 2010
Economics will likely prevent retrofitting carbon capture and sequestration technologies to existing power plants with a capture efficiency

Based on presentation to Oil Sands and Heavy Oil Technology Conference, Calgary, July 20-22, 2010.

Economics will likely prevent retrofitting carbon capture and sequestration technologies to existing power plants with a capture efficiency <40% and a residual life <15 years.

Only capture of flue gases (postcombustion) is practical for existing units, although even this is often made difficult by space constraints. Other solutions use processes (oxycombustion or gasification), which cannot generally be adapted to existing installations except with major revamping.

Current CO2 capture, transport, and storage costs are high because they apply to demonstration projects, requiring considerable research and development. These costs will drop by 2020-30 for new units, the various technologies being better demonstrated and commercial products benefiting from their larger scale. Some experts estimate potential cost reductions of about 40%. A high degree of uncertainty remains, however, regarding storage costs, which represent about 20% of the total CCS expenses.

This article provides information on the cost of CO2 capture, transport, and geological storage. Based on information published by various institutions, industry sources, and consultants, it reviews the main economic aspects of the chain.

After presenting the calculation bases, the article examines the three steps of CCS technology:

• Capture, from the capture unit to the outlet of the compression zone.

• Transport, from the outlet of the compression zone to the inlet of the storage units.

• Storage and long-term monitoring, from the inlets of the storage units.

Most CCS studies have occurred in the energy production sector (power plants). This article's focus as concerns capture therefore uses references specific to this sector.

Economic evaluation

Economic analysis seeks to determine, from a project's technical specifications, an estimate of its required investment, operating costs, and possible revenues (sale of products and by-products if any). The data are then used to conduct a project profitability study or compare different projects according to chosen economic criteria. The cost/tonne of captured CO2 can guide economic evaluation of CCS projects, corresponding to the extra cost required for CO2 capture, transport, and storage divided by the quantity of CO2 stored.

Fig. 1 illustrates the difference between CO2 captured and CO2 avoided. A traditional coal-fired power plant (900 Mw) emits 4.870 million tonnes/year of CO2. Installing a capture-compression system increases energy consumption, resulting in a total of 6.270 million tonnes/year CO2 generated for the same net amount of power produced. The capture system retains 90% of the gas emitted, about 5.640 million tonnes/year CO2, the quantity that will be captured, transported, and stored.

Referring to the power plant without capture, the quantity of CO2 avoided equals 4.870 million tonnes less the residual emission of the power plant with capture (630,000 tonnes), or 4.240 million tonnes. In this example, the ratio between CO2 captured (5.640 million tonnes) and CO2 avoided (4.240 million tonnes) is 1.33, meaning the tonne avoided is 33% more expensive than the tonne captured.

In this case the ratio depends on only three parameters: net efficiency of the power plant with capture, net efficiency of the power plant without capture, and CO2 capture rate.

The cost/tonne of CO2 captured, however, cannot be used to compare the different CCS options. Such comparison requires using the cost/tonne of CO2 avoided, since the capture operations themselves consume energy and emit CO2.

CO2 emissions avoided equal the difference between the emissions of an installation without capture and those of the same installation with capture (Fig. 1). They also correspond to the quantities of CO2 captured reduced by the emissions generated by capture operations. Dividing the cost of the CCS chain by the net quantity of CO2 avoided calculates the cost/tonne of CO2 avoided.

Evaluation limitations

The data used to estimate the costs must be accurate and dated. The most accurate estimation methods require an exhaustive knowledge of the project to be evaluated and its technical details, as well as a large database.

Estimated costs published to date are relatively inaccurate, and the methods and bases chosen to determine these costs are rarely shown. Published studies frequently report global costs for each CCS step, emphasizing the variability and uncertainties related to the estimations. This is due mainly to project details being difficult to access at the research and development stage and the scarcity of commercial industrial installations, none at all for some CO2 capture technologies.

The various sections of the CCS chain have been demonstrated to work individually, but virtually no integrated industrial installations exist (apart from the North Sea Sleipner project) capable of checking the validity of future estimations. The researcher must therefore use caution in applying estimations, bearing in mind they are only accurate to within a range of ±30%, sometimes even ±50%.

It is important to indicate a time frame to which the estimations put forward would apply. Current demonstration projects suffer from high costs per tonne of CO2 avoided compared with projects of industrial scale likely to be running by 2020. This article uses the Euro as the reference currency. The conversion factor for all estimates is $1.25-1.30 = €1.00.

Capture costs

The following three technologies seem to be competing for CCS use in electricity and heat production:

• Postcombustion treatment (flue-gas treatment).

• Oxycombustion (combustion in oxygen to obtain CO2-rich flue gases).

• Precombustion treatment (a modification of traditional coal combustion involving gasification).

These widely differing technologies exhibit features specific to the industrial sector for which they are intended. This review of the capture costs therefore distinguishes between power and heat production, on the one hand, and the other industrial sectors.

The capture step includes the capture itself as well as CO2 conditioning, particularly CO2 compression to a pressure of about 110-140 bar before transport. Irrespective of sector, capture represents about 70% of total known CCS costs.

Compared with processes currently used for treating flue gases, the capture processes are highly energy-intensive. Amine absorption, for example, requires energy for solvent regeneration (3-4 MMbtu/tonne CO2) corresponding to 70-80% of capture operating costs. CO2 compression for transport also requires 0.4-0.5 MMbtu/tonne CO2.

The capture cost depends mainly on the technologies used, the CO2 concentration in the flue gases (especially for postcombustion), the CO2 capture rate (percentage of CO2 extracted from the gases), the presence of impurities in the flue gases requiring more or less pretreatment, and the size of the emitter (annual quantity to be treated). Sources of virtually pure CO2 emitted by some hydrogen and ammonia processes therefore have a low capture cost (about $13/ton CO2), effectively limited to compression alone. These processes actually include the CO2 extraction costs in the hydrogen or ammonia production costs.

The costs published for capture therefore vary depending on the study and sector. Known technologies and currently accepted average costs, however, yield the following costs:

• Iron and steel production, cement, refining. and petrochemical manufacturing, €50-90/tonne of CO2 avoided.

• Coal-fired power plant, $65-78/tonne CO2 avoided.

• Gas-fired power plant, $85-97/tonne CO2 avoided.

These indicative cost brackets currently apply to one or the other of the capture technologies, especially in the case of electricity production. Further demonstration projects will estimate the costs of the various technologies, for each application, more accurately and reliably.

Table 1 shows the results of a 2008 analysis of CO2 capture costs according to various types of emitter and using available technologies, such as monoethanolamine (MEA) capture.1 Current research and development programs can reduce these costs.

Power, heat sectors

CO2 capture costs in power and heat production depend on the capture technology chosen (post, oxy, or precombustion) and the power and heat production technology, which is in turn affected by the chosen capture technology. The financial comparison, therefore, cannot be restricted to the CO2 extraction alone but must include the entire energy-generation process.

In traditional power plants increasing power production per tonne of fuel consumed indirectly leads to a drop in CO2 emissions per kw/hr produced. Postcombustion CO2 capture appears as a complementary operation, similar to flue-gas treatment. The most mature technology in this area uses an amine absorption column. This technology, which requires prior treatment to reduce sulfur oxides that destroy amines, is practically the only one usable on existing units, provided there is sufficient space to install the new equipment.

IFP and Alstom2 estimate the investment cost for a power plant with postcombustion capture will be in the region of $2,860/kw. Currently therefore, the additional investment cost for a traditional coal-fired power plant would be about $1,300/kw.

The International Energy Agency3 estimates a fairly wide range for total investment cost of a power plant with postcombustion capture—$2,210-3,185/kw—yielding an extra cost difficult to express precisely but likely in the region of $1,300/kw. Wide-ranging investment parameters explain the extent of the range. IEA expects the extra cost of carbon capture to drop by about 20% by 2020-30, due to learning and increased standardization.

For production of heat and electricity the flue gases discharged contain only water and CO2, which can be separated by condensing of the water. This technique could be used by existing units but would require installation of a cryogenic distillation unit, for the production of pure oxygen, and specific burners. If an existing installation is retrofitted, the higher combustion temperature must also be compatible with the furnaces used.

These reasons have so far prevented commercial coal-fired power plants from operating in oxycombustion mode and any investment-cost estimates must therefore be treated with caution. IFP and Alstom2 estimate the cost of an oxycombustion coal-fired power plant with CO2 capture at $3,055/kw, slightly higher than a power plant equipped with postcombustion capture. IEA3 estimates oxycombustion total investment at $2,600-3,120/kw.

Precombustion treatment modifies the fuel, for example coal, through prior gasification to produce a hydrogen-rich gas mixture containing CO2. In the few existing installations (integrated gasification combined cycle), the gaseous mixture then burns in the turbine of a traditional cycle (combined cycle) plant. The major advantage is the ability to extract the CO2 produced during gasification from the stream of fuel gas before injection in the turbine. The hydrogen-rich gas burned allows clean, CO2-free combustion. The key problem lies with the hydrogen turbine, still under development.

The process, however, is similar to techniques currently used in chemistry, fertilizer, and oil refining for producing syngas or hydrogen. The plant produces CO and H2 by steam reforming or partial combustion of the fuel, then if required reacts the CO with steam in the water-gas shift reaction to maximize hydrogen production.

The capture cost uses the investment and performance assumptions summarized in Table 2 and includes installation for CO2 compression before transport to the storage site. Numerous studies use a pressure of 110 bar. Taking the energy expenditure related to capture and compression into account via a penalty estimated on the global efficiency of the power plant simplifies the process (Table 2).

The power cost calculated does not include either amortization of the transport pipeline or the storage cost. Cost estimates include:

• Investments, Table 2, accuracy ±30% at best.

• 10% provision on investment for inaccuracies, unexpected events.

• Capital cost annuity, 15% of investment cost.

• Annual operating costs, fixed and equal to 4.5% of the investment cost.

• Energy costs, varying from about $1.5-3.5/MMbtu.

Fig. 3 illustrates the electricity production cost, the additional cost associated with capture, and the cost per tonne of CO2 avoided in the case of postcombustion treatment for a modern coal-fired power plant.

Inaccuracies concerning investment estimation, however, have a large effect on costs, which generally bear a substantial share of the capital charge. The effect of capture on the cost of electricity produced is likewise not negligible, about $39-52/Mw hr, or about 35% of the total cost of electricity delivered.

The capture cost per tonne of CO2 avoided lies between $65-78/tonne for postcombustion coal CCS technology. The cost per tonne of CO2 avoided varies only moderately with the price of fuels because the capital share is very high in the cost per tonne of CO2. For gas technologies the share of energy spent per tonne of CO2 avoided is larger due to the higher price of the natural gas btu and the higher dilution of CO2 in flue gases from natural gas power plants. The cost of electricity produced includes the CO2 capture and compression costs but not the transport and storage costs.

IEA3 estimates the current cost of the IGCC coal-fired power plant (with capture at $2,340-2,795/kw) fairly close to a coal-fired postproduction capture plant given estimation uncertainties. IEA expects long-term cost improvements of 15-20% as the technology continues to advance.

Industrial capture

Some industrial processes emit streams with high CO2 concentrations, for example production of ethylene oxide or ammonia and direct reduction of iron, allowing CO2 capture at a cost much less than observed in power production. These processes, however, only account for a very small percentage of total emissions from the industrial sector (Fig. 4).

Flows emitted from other processes such as blast furnaces and cement furnaces are more concentrated in CO2 than those from thermal power plants, but the comparatively limited volume of these emissions balances any advantage of concentration.

Metallurgy (ferrous metals) represents about 22% of emissions from the industrial sector, excluding power production. Capture solutions have yet to be fully demonstrated for blast furnaces in steelworks. Table 1 shows costs of $58-71/tonne CO2 captured, but some experts estimate costs of $26-32/tonne CO2 can eventually be reached.

The cement industry accounts for about 32% of worldwide emissions from the industrial sector excluding power production, two-thirds coming from decomposition (calcination) of lime into clinker and CO2. Capture is technically feasible at an estimated cost of $78-104/tonne CO2 captured, ranging as high as $182/tonne CO2 captured, depending on sources (Table 1). CO2 capture would cause cement production costs to increase dramatically.

Thermal power plants are the largest source of CO2 emission in the petrochemical industry, apart from ethylene oxide and ammonia production, for which capture costs are reduced by the high CO2 concentration. The capture technology for these plants is similar to commercial power plants, but since the combustion installations are much smaller (and dispersed), the capture cost will be much higher.

Numerous diffuse CO2 sources complicate capture in the oil refining industry. CO2 concentration in flue gases also varies between 3% and 13%, depending on combustion installations.

Thermoelectric power plants and the largest furnaces in refineries could theoretically connect to a flue-gas capture system. A 2003 study of a UK refining-petrochemical complex cited by the IEA yielded the following information:3

• CO2 collected, 2 million tonnes/year.

• Energy consumption for capture, 6.2 gigajoule/tonne CO2.

• Estimated investment, $238/tonne CO2.

• Operating costs, mainly energy expenditures, which depend on refinery marginal fuel (usually natural gas) prices.

Capture and compression represent about 45% of total expenditures, the rest being distributed between flue gas collection (8%), treatment of NOx and SO2, before CO2 absorption (16%), and general installation (31%).

These estimates, however, established before 2003, do not reflect the very sharp price increase in the cost of equipment and services since and therefore now likely underestimate actual costs.

Revaluing the investment cost data up by 60% and considering a capital recovery rate of 15%/year, fixed operating costs of 4%, and an energy cost of $7.80/MMbtu, the cost per tonne of CO2 captured, based on a simplified calculation, equals $105 (Table 3).

Transferring the flue gases to the CO2 absorption unit along with flue-gas treatment and compression contribute to high proportional cost of energy.

Transportation costs

Captured CO2 travels in liquid or supercritical state either by pipeline or cryogenic ship.

Truck and train transport occur in some storage demonstrators but are not considered practical for large-scale development.

CO2 transportation technology is already fairly well established, and the cost bases are not likely to undergo major changes, except possibly for long-distance transport by ship.

CO2 transport by pipeline has occurred for more than 30 years in the US, where CO2 is used for enhanced oil recovery.

Transport pressure generally remains greater than the critical point (74 bar; about 1,073 psi) to increase fluid density and reduce volumes transported. If the CO2 needs to be transported over long distances, intermediate booster stations keep the flow above critical pressure.

Pipeline transport generally occurs at ambient temperature, since CO2 refrigeration is much more expensive than pressurization, even though refrigeration would allow a reduction in transportation pressures and hence WT.

Transport costs/kilometer depend largely on the CO2 flow rate and local conditions along the pipeline route. Fig. 5 illustrates cost trends/tonne transported/100 km in both a simple case and a high-population density case in the Netherlands.4

For a route with no special difficulties, the cost of transport/tonne/100 km for a mass flow rate of 10 million tonnes CO2/year is about $0.65-1.30, a figure relatively low in comparison with capture costs. Unit costs increase for lower flow rates and are also more variable. A flow rate of 5,000 tonnes/day, for example, would have cost of $2.00-5.00/tonne CO2.

These costs include both investment expenditures and operating costs. The key factors in pipeline investment costs are length, diameter, operating pressure, steel quality, and type of region crossed (semiurban, flat clear land, hilly or mountainous land, waterways crossings, etc.).

A detailed evaluation must consider, for determination of investment costs:

• Pipe manufacturing cost.

• Pipelay cost.

• Intermediate booster stations costs (for lines longer than 200 km).

And for operating costs:

• Pipeline operation, maintenance.

• Pump station operation, maintenance.

• Pump station energy consumption.

With no intermediate booster station, which should be the case for most of the first networks developed, capital expenditures represent about 95% of average cost/tonne transported. Eventually, CO2 will not be transported simply by a single dedicated pipeline between the capture site and storage site, as is the case with planned pilot installations. In the event of widespread development, establishment of a collection system with several capture units as well as a common distribution system to several storage sites will likely occur, reducing the average cost of transport.

Maritime transport

The two solutions considered for CO2 maritime transport are subsea pipelines and ship transport. Ships of 1,000 cu m capacity currently transport CO2 by sea for carbonated beverage production. CO2 requires both refrigeration and pressurization to be transported in a liquid a liquid phase, unlike LNG which requires only cooling.

Cryogenic transport alone is impossible, since at atmospheric pressure CO2 changes directly from gaseous to solid state and at ambient temperature CO2 is liquid at 60 bar. A combination of refrigeration and pressurization (e.g., –30° C. and 15 bar or –50° C. and 7 bar), however, will keep CO2 liquid and therefore suitable for maritime transport.

Maritime transportation cost estimates must therefore include preparation for transport, storage, and unloading. The marginal cost/kilometer for transport by ship decreases with distance and several companies are working on projects to build large-scale CO2 transport vessels.

The cost of maritime transport by pipeline, however, is directly proportional to distance and is about 20-40% greater than land transport in easy regions, due to increased pipelay and routing costs. Transport by ship may therefore become competitive with pipeline over long distances, beginning even as low as 500 km for an offshore pipeline.

Storage costs

Several geological storage solutions are viable:

• Deep saline aquifers.

• Depleted or nearly depleted oil and gas fields (EOR).

• Unmined coal veins.

Other CO2 storage options include CO2 mineral storage, which is still undergoing research, and ocean CO2 sequestration, on which the international community has declared a moratorium.

Storage costs total about 20% of the overall CCS-chain cost according to the recent McKinsey report.5 Storage costs include reservoir reconnaissance, characterization and modeling costs, injection costs, and monitoring costs.

Injection cost highly depends on drilling cost, which depends in turn on the number of holes to be drilled for a given flow rate (and therefore on formation injectivity) and on the depth and complexity of these holes. Although relatively well known, these costs may nevertheless vary by site (Fig. 6).

Storage may generate a profit if the CO2 is used in an enhanced oil recovery or enhanced coalbed methane.

A substantial difference exists between offshore and onshore storage costs (Table 4)5 due mainly to the higher equipment, exploration, and closure costs at sea. McKinsey also distinguishes between storage in a saline aquifer and storage in a depleted hydrocarbon reservoir, the first generally being more expensive due to higher exploration and characterization costs.

The cost/tonne of CO2 storage consists 70-90% of capital costs. Increasing CO2 pressure for injection, however, is included in operating costs.


CO2 captured in power plants or other industrial installations can be used in enhanced oil recovery. In suitable geographic regions (for example the US) development of the EOR market could facilitate capture projects, especially from coal-fired power plants.

The additional cost of CO2 capture in power generation could eventually stabilize at $32-42/Mw hr for coal-fired technologies, assuming technological progress and excluding pipeline amortization and storage costs.

Using CO2 for enhanced recovery, however, can substantially reduce the extra cost of the CCS chain. Using a ratio of 0.6-0.7 tonne CO2 captured/net Mw hr produced and assuming a CO2 buy-back price ex-plant of $20/tonne for enhanced recovery yield a gain of about $13/Mw hr (Fig. 7). The gain is even greater considering transport and storage costs are no longer charged against electricity production. CO2's value for enhanced recovery, however, depends greatly on the price of oil.

Cost trends

The 2008 McKinsey study estimated costs trends of the CCS chain using as reference a new 900-Mw power plant fueled by coal or lignite in 2020, when the first commercial projects are expected to be built.5 The reference example also used an ultrasupercritical 700° C. technology for boilers, offering efficiency near 50%, excluding capture-compression.

The choice of a specific technology (e.g., post, oxy, or precombustion) does not affect total capture cost in the demonstration phase. After the demonstration phase, however, commercial-scale developments will allow much more detailed assessment of the technical and economic performance of the respective processes in specific applications.

Table 5 estimates the long-term capture costs (by 2020) and their distribution/tonne of CO2 avoided. Investment costs represent more than 50% of capture costs. McKinsey chose an actualization rate of 8% and a lifetime of 40 years to calculate capital costs. The capture investment amount lies between $1,040 and $1,560/kw and total investment cost (power plant plus capture) at $3,510-4,160/kw.

McKinsey also proposes an estimation of the capture costs for the entire CCS chain (Table 6). These costs, ranging between $45 and $65/tonne CO2, are much lower than those of the demonstration projects ($78-117/tonne CO2) which could be operational by 2012-2015 to evaluate available technologies. The capture cost is the primary driver behind the higher costs.

Cost variability

Several factors explain the variability in the announced costs of the CCS chain:

• Estimation of the investment costs, which in the studies conducted includes an uncertainty margin of at least ±30%.

• Assumption of unit-cost reduction obtained from demonstration projects (scale effect, learning curve).

• Actualization rate (r) or capital recovery factor. Since a high rate accounts for a larger risk factor (on investment), it affects calculated cost.

• Installation utilization rate, the percentage of time the installation is used to full capacity. Depending on the type of industry or process, this factor may fluctuate between 80% and 90%.

• Estimation of fixed operating costs, often calculated as a percent of investment. The rate generally ranges between 2.5% and 4%.

• Estimation of energy expenditures, especially in the capture phase. Studies report an energy penalty expressed, for example, as a global reduction in energy efficiency of 3-12 points without being sufficiently precise regarding how this reduction was calculated.

• Energy resource costs (coal, gas, biomass, etc.).

Investment cost estimations may be 30% undervalued, especially since the total perimeter of investments required is not always well defined, leading to a 20-25% effect on the estimated cost of CO2 avoided for a coal-fired power plant.

The uncertainty of costs regarding reservoir characterization and long-term monitoring of CO2 storage is also likely to induce high variability in total cost estimates.

Existing applications

The estimations described so far apply to new installations that have reached commercial development. They cannot be applied to existing installations, even for implementation of the postcombustion technology and even if the installations are not far from the CO2 transport facilities.

Capture may not even be technically feasible on some existing installations (major modifications required on flue gas circuits, possible lack of space on the industrial site near the emission sources, etc.) and is hindered economically on others by:

• A roughly 30% greater investment cost/tonne of CO2 avoided than for implementation on new installations.

• A shorter lifetime, since the residual lifetime of the existing combustion units is taken into account, affecting average cost.

• An energy efficiency lower than announced for installations planned for 2020, increasing the energy penalty.

• Downtime during the period required to make the internal modifications and connections to the capture unit.


1. Broutin, P., "IFP—Presentation du projet CapCO2," Colloque ANR/CO2, Rueil-Malmaison, June 10-11, 2009.

2. Bouillon, P.A., Hennes, S., and Mahieux, C., "ECO2: Postcombustion or Oxyfuel-A, Comparison between Coal Power Plants with Integrated CO2 Capture," Energy Procedia, Vol. 1, No. 1, pp. 4,015-22, February 2009.

3. International Energy Agency, "CO2 Capture and Storage—a Key Carbon Abatement Option," ISBN 978-92-64-04140-0, 2008.

4. Hendricks, C., "Carbon Capture and Storage," 2007.

5. "Carbon Capture & Storage: Assessing the Economics," McKinsey & Co., 2008.

The author

Didier Favreau ([email protected]) is a senior analyst with IFP Energies nouvelles, Rueil-Malmaison, France. He was formerly a project leader in the consulting branch of IFP Energies nouvelles, in charge of feasibility studies, market reviews, and economic analyses in the oil and gas sector. Didier Favreau has more than 32 years' experience as a project consultant for major oil and gas companies. He was graduated engineer from the Ecole Nationale Superieure des Mines de Saint-Etienne, France, in 1971. He is an active contributor to CEDIGAZ, an international association dedicated to natural gas information.

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