Comparison of MEA Capture Cost for Low CO2 Emissions Sources in Australia Minh T. Ho1,3, Guy W. Allinson 1,3& Dianne E. Wiley2,3*
1.
School of Petroleum Engineering, The University of New South Wales, Australia
2.
School of Chemical Engineering, The University of New South Wales, Australia
3.
The Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC)
*
To whom correspondence should be addressed. Prof. Dianne Wiley, School of Engineering Engineering. The University of New South Wales. UNSW Sydney 2052 AUSTRALIA. Telephone: +61 (2) 938 59754. Facsimile: +61 (2) 938 55456. E-mail:
[email protected]
Abstract This paper estimates the cost of CO2 capture for three Australian industrial emission sources: iron and steel production, oil refineries and cement manufacturing. It also compares the estimated capture costs with those of post-combustion capture from a pulverised black coal power plant. The cost of capture in 2008 using MEA solvent absorption technology ranges from less than A$60 per tonne CO2 avoided for the iron and steel production to over A$70 per tonne CO2 avoided for cement manufacture and over A$100 per tonne CO2 avoided for oil refineries. The costs of capture for the iron and steel and cement industries are comparable to or less than that for post-combustion capture from a pulverised black coal power plant. This paper also investigates costs for converting low partial pressure CO2 streams from iron and steel production to a more concentrated stream using pressurisation and the water-gas shift reaction. In those cases, the costs were found to be similar to or less than the cost estimates without conversion. The analyses in this paper also show that estimated costs are highly dependent on the
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characteristics of the industrial emission source, the assumptions related to the type and price of energy used by the capture facilities and the economic parameters of the project such as the discount rate and capital costs.
Keywords CO2 capture, CCS, Economics, Sequestration, Cement, Iron and Steel, Oil refineries
List of Abbreviations CPRS CO2CRC COE FGD GHG IEA GHG IGCC IPCC MEA ppm SCR
Carbon Pollution Reduction Scheme The Australian Cooperative Research Centre for Greenhouse Gas Technologies Cost of electricity Flue Gas Desulphurisation Greenhouse Gas International Energy Agency Greenhouse Gas R&D Programme Integrated Gasification Combined Cycle Intergovernmental Panel on Climate Change Monoethanolamine Parts per million Selective Catalytic Reduction
Nomenclature Ki Oi d n
Real capital costs Real operating costs Real discount rate Total project life
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1
Introduction
In 2008, the Australian Government announced plans to establish a national emissions trading scheme. The aim of the Carbon Pollution Reduction Scheme (CPRS) proposed by the government is to introduce measures that will assist industry to reduce or cap current rates of CO2 emissions. The proposal is one of the strategies Australia will use to help meet its commitment to the Kyoto Protocol and greenhouse gas abatement.
In 2006, the Australian Department of Climate Change (DCC, 2006) reported that over 310 million tonnes of CO2 was emitted from stationary sources in Australia, of which 30 million tonnes was from industrial facilities not related to energy production or fuel use. These direct emissions included 10.8 million tonnes of CO2 from iron and steel production, 3.6 million tonnes from aluminium smelting plants and 5.8 million tonnes from minerals production. Other large emitters included cement manufacturers accounting for 3.5 million tonnes, refineries with 5.5 million and chemical production plants contributing over 1 million tonnes.
There are a number of options that businesses and industry can pursue in order to mitigate greenhouse gas emissions. One medium term option is to capture the CO2 at the point of atmospheric emission, transport it to and store it in a geological reservoir, otherwise referred to as carbon (dioxide) capture and storage (CCS). The advantage of CCS is that it can be retrofitted to existing process equipment and can be used in conjunction with other mitigation strategies such as improved energy efficiency and changing to alternative lower carbon intensity fuels. If the majority of Australia’s large
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scale emitters could deploy CCS, significant cuts would be observed in the nation’s carbon dioxide emissions.
In evaluating CCS as a possible mitigation option, it is important to understand the costs of establishing capture and storage infrastructure at existing or new CO2 emission sources. Numerous economic assessments have been carried out. The most recent collation of assessments appears in the IPCC Special Report on Carbon Dioxide Capture and Storage (IPCC, 2005). The reported economic studies focused on the capture costs for power generation, with a only few studies reported on the economic feasibility of CO2 capture from industrial processes such as iron and steel or cement manufacture (IEA-GHG, 2000a; IEA-GHG, 2000b; Farla et al., 1995; Hassan, 2005). The costs reported for industrial emission sources ranged from less than US$20 to over US$75 per tonne CO2 avoided, based on various feed gas compositions and international economic conditions. No studies were reported specifically for Australia.
This paper extends our earlier work in which we examined the cost of CO2 capture from Australian black coal power plants (Ho et al, 2008a; 2008b). Our objective in this paper is to assess the costs of retrofitting CO2 capture to major Australian industrial processes and compare these against costs for power generation. Costs are reported for a commercially available CO2 solvent separation technology. Although the economic and processing assumptions used reflect Australian conditions, the analysis could be applied to other locations. This paper is the first stage of a wider study estimating costs for Australian industrial emission sources. Further research will investigate costs using different capture technologies.
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2 2.1
Methodology Emission sources
This paper estimates the cost of CO2 capture for the following industrial applications in Australia:
1. Iron and steel production; 2. Boiler exhaust gas from oil refineries; and 3. Cement manufacture.
It reports the costs of capture, not the costs for a full CCS project which would include the costs of capture, transport and storage. For comparison, post-combustion capture of CO2 from a pulverised black coal power plant is included.
The industrial facilities are selected because they represent a significant share of the total stationary Australian emission sources. Other large energy-consuming industries such as aluminium smelting (involving the reduction of alumina to aluminium) and fermentation of biomass to ethanol also constitute a significant share of Australian’s industrial emissions but consideration of these processes is not included in this paper. For aluminium smelting, the direct (non-energy related) CO2 enriched exhaust gas from the primary process is currently diluted with air to concentrations of 2 to 5 percent. To facilitate the implementation of CO2 capture at these sites, a complete overhaul of the existing primary process design is required. This would make CO2 capture at these facilities economically unattractive (IEA-GHG, 2000c) and thus has been neglected in this paper. For CO2 capture from biomass fermentation, the costs of CCS will likely be
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for simple process modification, CO2 transport and storage and not for CO2 separation; consideration of this process has been excluded from this paper. Other industries also excluded from this paper are those for which separation of CO2 is an existing feature of the process e.g. natural gas processing and the production of hydrogen gas.
Table 1 gives the characteristics of the industrial CO2 emission sources examined in this
paper. The flowrate, composition and operating conditions were chosen to reflect typical values for Australian industrial emission sources. The compositions of these sources have been simplified to enable a preliminary analysis to be carried out. The objective of this paper is to assess the preliminary cost of CO2 capture, and the costs for treating trace impurities are not included. The effect and amount of trace impurities is site specific and would need to be examined in more detail at each site to assess the effect on costs. Factors that may affect the costs include adding extra processing units, modifying the processing design or changing the operating conditions of the capture process. This may alter the reported capture costs reported in this paper.
2.2
CO2 capture assumptions
As shown in Figure 1, this analysis is for ‘post-production’ capture of CO2 from the industrial emission source. This is equivalent to ‘post-combustion’ capture from a power plant. In this paper, we assume that CO2 ‘capture’ consists of gas pretreatment, CO2 separation and the initial compression of the CO2 ready for transport via pipeline to the storage site. Figure 1 illustrates the relationship between the industrial facility, the CO2 capture facility and the CO2 storage facility (i.e. transport and storage). The CO2
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separation efficiency is assumed to be 90% for all industrial emission sources. The separated CO2 is compressed to 100 bar for transport and storage (Allinson et al. 2006).
Figure 2 shows the expanded process flow diagram for a generic ‘post-production’ CO2 capture system. It comprises three sections: pre-treatment, separation and compression. Depending on the composition of the emission source, pre-treatment may be necessary to produce a gas stream suitable for separation. When required, selective catalytic reduction (SCR) is used to reduce the concentration of NOx (primarily as NO2) to less than 20 ppm. Flue gas desulphurisation (FGD) is used as required to reduce the concentration of SOx to less than 20 ppm. Particulates and water can also be removed as required.
As shown in Table 1, we assume that the flue gases from the blast furnace, cement and refinery processes have a high concentration of SOx and NOx. Therefore, FGD and SCR pre-treatment facilities are required. The flue gas from Corex production is assumed to have SOx and NOx concentrations of less than 20 ppm and therefore does not require FGD or SCR facilities.
For the baseline economics, CO2 is assumed to be captured using a commercially available chemical solvent absorption technology, a monoethanolamine (MEA) solvent. MEA is chosen because it is used widely in industry for CO2 recovery from natural gas and synthesis gas. While it is likely that commercial scale capture will be deployed using new solvents, assuming MEA permits comparison with other published studies.
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This paper also investigates costs for converting low partial pressure CO2 streams to a more concentrated stream using pressurisation and the water-gas shift reaction. In those cases, capture using physical absorbent Selexol is employed.
To maintain consistency with other studies for industrial emission sources, this paper does not examine costs with waste heat integration. Having said that, current estimates of the effect of full heat integration between a capture plant and power plant indicates a potential reduction in the energy requirement of between 10 and 30 percent, with a resultant reduction in capture cost of between five and 15 percent (Ho et al., 2006). The capabilities and application of waste heat integration to power generation have been discussed in detail elsewhere (Gibbins and Crane, 2004; Harkin et al., 2008).
2.3
Simulation program
The process and economic calculations were completed using a techno-economic model developed by the University of New South Wales for the CO2CRC (Allinson et al., 2006). The process module of the techno-economic model calculates total energy consumption and equipment dimensions for all the unit operations shown in Figure 2. General mass and energy balances and correlations are used to estimate the power and sizes of the process equipment. These include the absorbers, steam reboiler, flue gas and CO2 compressors, expanders, pumps, dehydration unit and flue gas and solvent heat exchangers.
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2.4
2.4.1
Economic evaluation
Assumptions
The outputs of the UNSW process module link directly to the costing module which estimates the total capital and operating costs, and the specific cost of CO2 avoided. Capital and operating costs are estimated for pre-treatment, CO2 separation, and CO2 compression. The total capital cost includes all key process equipment items for the units shown in Figure 2, plus a general facilities cost. The general facilities cost includes ancillary equipment such as storage tanks, spare pumps, valves and the control system.
The operating cost includes fixed general maintenance costs comprising labour, nonincome government taxes and general insurance cost. The variable operating costs include costs for the flue gas desulphurisation, cooling water and materials replacement. The latter incorporate operating costs for the solvent absorption system and therefore include waste disposal as well as the SCR amongst other things. The costs of the energy for the capture facility are also part of the variable operating costs.
The economic indicator used in this paper to estimate the cost of capture is $ per tonne of CO2 avoided. The cost of capture ($ per tonne avoided) is the carbon credit per tonne avoided that would be required as income to match the present value of capital and operating costs for the capture project. The cost of CO2 avoided is calculated using a discounted cash flow analysis that takes into account the total project costs (capital and operating) and the net CO2 avoided –
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Cost of CO 2 avoided =
Present Value Project Costs Present Value CO 2 avoided n
=
K i + Oi
å (1 + d ) i =1
n
å i =1
i
(1)
(CO2 avioded )i (1 + d )i
where Ki and Oi are the real capital and operating costs ($ million) in ith year, d is the discount rate (% pa), n is the total project life and CO2 avoided is the annual amount of CO2 avoided in million tonnes. The capital and operating costs of CO2 capture are the incremental costs of building the capture plant at an existing industrial facility.
As discussed by Allinson and Nguyen (2002) and Allinson et al. (2006), this formulation has many advantages. These include the ability for capital expenditure to be incurred at any time throughout the project life. Similarly, operating costs and the amount of CO2 avoided can vary.
A number of simplifying assumptions are used in this paper. The capital cost is spread over 2 years with a breakdown of 40 and 60 percent. The operating cost and amount of CO2 avoided remains constant over the 25 year project life. Post operational (abandonment) costs for the capture plant such as site remediation and disassembly are assumed to be offset by the salvage value of the equipment. Therefore, the abandonment cost is assumed to be zero. Table 2 summarises the economic assumptions used. For comparison, the assumptions used by other researchers for capture of CO2 from industrial emission sources are also shown.
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The results presented in this paper are only for CO2 capture and are reported in terms of the capital cost (as $ million), the operating costs including the fixed, variable and energy costs (as $ million per year) and the energy penalty (as kJ per kg CO2 captured). The cost year of the analysis is 2008. All results are presented in Australian (A$) and US (US$) dollars. In determining the cost for each currency, where possible, the unit costs were obtained in both Australian and US dollars. The sources of equipment cost items include vendors, publications and industry contacts, and were escalated to 2008 dollars using the Chemical Engineering Cost Index. For items purchased from the US market, the procurement cost of the item is estimated using a translation factor that takes into account the exchange rate for purchased equipment, freight and local labour costs. An exchange rate of 1 Australian dollar to 75 US cents is used. The breakdown of total capital and operating costs is based on standard Chemical Engineering procedures as outlined in Peters et al. (2003). Table 3 shows the items in the capital cost calculations. These include the total equipment cost (items A and B) and set up costs (items C to I and K). Further details of our economic methodology can be found in our earlier published work (Allinson et al., 2006; Ho et al., 2008b).
The costs are estimated on a pre-tax basis. The impact of income tax, resource rent royalties and taxes, R&D tax concessions and financial subsidies available for the use of natural resources are neglected (NIEIR, 1996). Additionally, it is assumed that retrofitting the CO2 capture facility has no impact on the operating or capital cost of the existing process plant. The costs of modifying the existing plant are assumed to be included in the capital and operating costs of the capture facility. Equipment procurement costs have increased significantly in recent years because of the large
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increases in commodity prices. Therefore the costs presented in this paper are only indicative of 2008 costs and the actual costs of a CO2 capture plant will be different at the time of implementation.
2.4.2
External energy supply and prices for industrial emission sources
The energy required for the CO2 capture facility is provided by an external power source. For the baseline economics, it is assumed that the steam required for solvent regeneration and the electricity for compression and pumping comes from a natural gas combined heat and power (CHP) plant fitted with CCS (Figure 3). The price for the steam is estimated as the lost electricity from the natural gas power plant. The price of the external energy is assumed to be A$100 per MWh electrical equivalent. This value takes into account the costs for capital and for operation of the external natural gas power plant and associated CCS facilities. The wholesale cost of the natural gas is assumed to be A$3.5 per GJ. Natural gas was selected as the fuel for the baseline case because in Australia it is a readily available energy resource with a low emission intensity and has moderate wholesale prices of A$2.5 to A$4 per GJ (AER, 2008). An equivalent price of US$100 per MWh is assumed for the cost estimates in US dollars, based on a natural gas price of US$7 per GJ.
As shown in Figure 3, 90% of the CO2 in the flue gas of the external power plant is assumed to be captured with only a small portion being emitted. The emission intensity of this emission stream is assumed to be 0.045 tonne CO2 per MWh of external energy used.
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The total amount of CO2 avoided is therefore calculated using -
CO2
avoided
= CO2 before capture - CO2
after capture
= CO2 before capture - ( CO2 emitted from capture plant + CO2 emitted from external power plant )
(2)
Using an external power plant with CCS to provide energy for the CO2 capture process reflects one practical option that may apply when retrofitting CCS to existing industrial facilities. However, it is also possible that the external power plant may not be fitted with CCS or it may use another fuel. Different energy supply options are therefore considered in this paper as part of the sensitivity analysis. The values of the fuel prices used for the sensitivity analysis are also shown in Table 2.
2.4.3
Comparison of effects of capture on cost of electricity at a coal fired power plant
In estimating the cost of CO2 capture from the pulverised black coal power plant, we calculate the difference in capital and operating costs between the power plant with capture and a power plant without capture. The net electricity output of both plants is held constant at 500 MW. Thus the total capacity of the new build power plant with CO2 capture is greater than 500 MW. Using this assumption, the calculated electricity cost for the pulverised black coal power plant without CCS is A$57 per MWh. The addition of CCS to the coal power plant increases the cost of generating electricity to A$120 per MWh.
To be consistent with our previous studies (Ho et al., 2008a; 2008b) and most other published studies (IPCC, 2005; Rubin et al., 2007) the energy needed by the capture
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facility located at the pulverised black coal power plant is assumed to be supplied by the coal power plant itself. This is different to the way in which the energy is assumed to be supplied to the capture facility located at the industrial plants in this paper. For industrial plants, the energy needed by the capture facility is supplied by an external power source (see the previous section). If the energy needed by the capture facility at the power plant is provided by an external natural gas CHP plant rather than by the power plant itself, the capture cost estimates for the coal fired power plant fall by approximately 10 percent.
2.4.4
Space requirements
One of the key challenges in capturing CO2 from industrial facilities such as iron and steel, oil refinery or cement plants is the complexity of the plant infrastructure. For industrial plants, CO2 emissions are often dispersed over a large area from many point sources. Two options are available for capturing the CO2. Firstly, the flue gases could be treated individually at each point source before being combined for transport. Alternatively, CO2 could be processed in a centralised location, and thus potentially yield economies of scale. The challenges of point source treatment are the availability of adequate space for each capture facility and the ability to supply energy to each facility. It is unlikely that this option would be employed. The challenge for a centralised solvent processing facility is that it may be difficult and costly to install long and large ducts that collect the flue gas at each point source and transport it to a centralised facility. An intermediate option could be decentralised solvent absorption at each point source and a centralised regeneration unit using solvent pipes. Chemical handling and safety pose one challenge for this option.
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In this paper it is assumed for simplicity that gases from the point sources are combined and the CO2 is separated at a centralised processing location. The assumed feed gas mixture for each industrial emission source reflects this. The cost for ducting and pipework required to deliver the emissions from the point sources to a centralised facility is assumed to be 20 percent of the total equipment cost (item D, Table 3). The analysis neglects the costs for land purchase and any shut-down of the processing facility that may be required to retrofit the capture plant. It is assumed that it may be possible to install the required pipe-work during regular plant shutdown. These assumptions are consistent with those of other researchers. Thus the results presented in this analysis may be at the upper end of potential cost savings.
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Results & Discussion
The capture costs for the industrial emission sources and for power stations are summarised in Table 4 and Figure 4.
For the processes that use MEA solvent capture, the capital costs account for approximately 20 to 30 percent of the total capture costs with 70 to 80 percent being the operating costs. The pre-treatment facilities (FGD, SCR and feed gas cooling) and the MEA absorption system together contribute over 70 percent of the total equipment costs or 6 to 15 percent of the total capture costs. As regards the operating costs, the largest component is the energy cost for CO2 capture, which accounts for 35 to 70 percent of the total capture cost. The materials replacement cost is also high (approximately 10 percent of the total capture cost).
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The separation equipment accounts for a large proportion of the total capture costs because each item of equipment is large and expensive. The significant contribution of the energy cost to the total capture cost arises because of the large energy penalty associated with capture. As discussed in our earlier papers (Ho et al, 2006b), significant cost reductions can be achieved by 1) using alternative or cheaper equipment to reduce capital cost and 2) by employing heat integration or low energy solvents to reduce the energy penalty and thus energy costs.
The following sections will describe in detail the cost estimates for each industrial emission source, the cost comparisons with CO2 capture from power plants and with other studies in the literature.
3.1
Capture costs for iron and steel production
BlueScope Steel, the largest manufacturer of iron and steel in Australia emitted over 10 million tonnes of CO2 equivalent from their processing plants in 2006 (DCC, 2006). The majority of these emissions were from the BlueScope Steel facility at Port Kembla, New South Wales. The large quantity of CO2 emitted from this single industrial site suggests that the application of CCS at such a facility may have benefits of economies of scale.
Steel production is a highly energy intensive process. It generates CO2 from the manufacture of iron and steel and indirectly through the use of electricity and gas for energy. CO2 is directly emitted in two key processes. These are 1) the blast furnace
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where coal and coke are used as a chemical reductant to extract pig iron from iron ore and 2) the basic-oxygen furnace where the pig iron is converted into crude steel.
In Australia, iron and steel is generally produced using conventional air-blown blast furnaces. The bulk (around 70%) of the total CO2 emitted from a plant with such technology is emitted from the blast furnace rather than from the other processes at the plant. Therefore we make estimates of the cost for capturing CO2 from the blast furnace flue gas only and adopt the compositions and operating conditions assumed by Farla et al. (1995). Figure 5 shows a schematic of the process for capturing CO2 from the flue gas of the combusted blast furnace.
Although iron and steel in Australia is generally produced using conventional technology, internationally there is an increase in the development of new iron production technologies, in particular smelt reduction of iron ore. These technologies use pure or enriched oxygen instead of air to reduce the iron ore into pig iron and conventional coal in place of coking coal. The resulting flue gas is a mixture that has a similar composition to the synthesis gas of an IGCC process. By using oxygen, the CO2 content of the flue gas increases from less than 20% to over 30% (Lampert and Ziebik, 2006). There is the possibility that future iron and steel production in Australia will utilise these new production techniques. Therefore, the cost of capturing CO2 from the flue gas of the advanced Corex process is also investigated in this paper. The Corex process was chosen as it is a commercially proven technology (Wingrove et al., 1999). It achieves the blast-furnace function in two separate reactors. In the first reactor, iron ore is reduced to a sponge-iron. In the second step, a smelting gasifier is used to melt the sponge iron and produce reducing gases. The main difference between the Corex
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and the traditional blast furnace flue gas is that the CO2 concentration is higher (up to 30% compared with 20%) and the concentrations of SOx, NOx and particulates are lower (Worrell et al., 2001). Figure 6 shows a simple schematic of CO2 capture from the Corex process.
3.2
Conventional blast furnace flue gas capture
The cost of capturing CO2 from a conventional blast furnace using current commercially available MEA is estimated to be A$74 or US$68. The results (Figure 4 and Table 4) show that CO2 capture from a blast furnace is less expensive than capturing from a pulverised coal power plant, by approximately A$15 per tonne. This reflects the higher CO2 concentration in the blast furnace gas, which results in smaller equipment and lower capital costs.
Farla et al. (1995) estimated the cost of capture from conventional blast furnaces to be US$35 per tonne CO2 avoided. In contrast, this paper estimates a higher cost (US$68 per tonne CO2 avoided) for the same industrial emission source. The difference in the estimates arises because of the different cost years of the analyses (1990 compared with 2008), the discount rate and the assumed price and type of the external energy. Another discrepancy is that our capital cost estimates include costs for the FGD and SCR whilst Farla et al. (1995) do not include these items. Additionally, their analysis considered MDEA in place of MEA solvent for the absorption process, thus resulting in the lower energy penalty reported for their study. MEA solvent has a higher CO2 regeneration energy penalty than MDEA and hence this paper has higher operating costs than Farla et al. (1995). Escalating the estimates of Farla et al. (1995) to 2008 values, their cost
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increases to over US$55 tonne CO2 avoided. Taking into account further differences in discount rate and energy type and prices, this paper reports a value that is within 10 percent of their value.
3.3
Oxygen blown Corex flue gas capture
The cost of capturing CO2 from the flue gas of an advanced iron production process such as the Corex process is estimated to be A$56 or US$52. Figure 4 and Table 4 show that the cost to capture CO2 from a Corex process is less than for capture from a pulverised black coal power plant and from a conventional blast furnace. The significantly lower cost arises because 1) the higher CO2 concentration in the Corex flue gas reduces the energy penalty and requires smaller less expensive separation units and 2) Corex flue gas capture does not require pre-treatment (FGD and SCR) facilities, which reduces the total equipment, set up, fixed and materials operating costs.
As suggested by Gielen (2003), the partial pressure of the CO2 in the Corex flue gas is moderate (approximately 0.85 bar) and there exists a potential to increase this partial pressure by increasing the pressure of the flue gas. If the partial pressure of the CO2 in the feed gas increases to above 5 bar, there is a potential to use less energy intensive physical solvent absorption which would reduce the energy penalty associated with capture. This alternative operating scheme will be explored here.
If the flue gas of the Corex process is compressed to 20 bar and CO2 is recovered using physical absorption with Selexol solvent, the estimated cost is A$60 or US$51 per tonne CO2 avoided. This value is similar to the estimate of capture cost for Corex flue gas
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using MEA solvent. Although the energy penalty for solvent regeneration of the physical absorption system is less than for the chemical absorption (95 kJth per kg CO2 captured compared with 4,400 kJth per kg CO2 captured), this alternative operating scheme requires an additional feed gas compressor. This adds considerable capital costs, as well as consuming more electrical energy (1,000 kWe per kg CO2 captured compared to 300 kWe per kg CO2 captured). The increase in capital cost and higher electricity usage outweighs any cost reduction gained from the lower regeneration energy, suggesting that this alternate operating scheme does not offer any benefits from an economic perspective.
For this operating scheme, Gielen (2003) estimated a cost of US$18.4 per tonne CO2 avoided. This is a significantly lower estimate than in this paper. The cost difference arises primarily because of the different cost year (2001). Furthermore, Gielen (2003) assumes that part of the energy for feed gas pressurisation is offset by the expanded waste gas leaving the separation unit, which this paper does not. Additionally, he assumes a much lower energy cost for the external power of US$15 per MWh. Using similar processing and economic assumptions to Gielen (2003), the cost of CO2 capture for this alternate operating scheme is estimated to be less than US$20 per tonne CO2 avoided. The energy penalty is estimated to be 510 kJ per kg CO2 captured. These values are similar to those estimated by Gielen (2003).
3.4
Shift conversion of CO to CO2
In addition to pressurisation of the feed gas, another possibility for reducing the energy penalty of CO2 capture from iron and production flue gases may be to convert the CO
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present in the blast furnace flue gas mixture into CO2 in order to concentrate the stream. By concentrating the CO2, lower energy penalty materials such as physical solvents could be used. As shown in Figure 7 conversion of the CO in the flue gas stream to CO2 can be accomplished using the water-gas shift reaction where steam is reacted with the flue gas under high temperature and high pressure (20 bar). Similar to other high pressure gas streams, the CO2 capture process that follows the water-gas shift conversion uses physical absorption solvent Selexol. The following analysis assumes that in the water gas shift reaction, all of the CO is converted to CO2, and that the H2 composition increases by the stoichiometric value. The conversion of CO is assumed to be carried out using 50 percent excess water. The temperature of the exiting synthesis gas is cooled to 313 K or 40 oC by using it to heat the incoming blast furnace flue gas. The cost analysis assumes that there is a benefit of producing hydrogen electricity as a by-product from the lean CO2 gas as proposed by Gielen (2003). For simplicity it is assumed that the hydrogen electricity from the lean gas offsets 0.28 GJ per tonne of CO2 captured. The analysis includes the costs for all the additional equipment including the flue gas compressor, the water-gas shift reactor and heat exchanger, as well as the CO2 capture and compression system. The capital cost for the hydrogen turbine is estimated as US$170 per kW or A$225 per kW.
The results in Figure 4 and Table 4 show that the capture costs for converting CO to CO2 followed by CO2 capture is A$74 and A$39 per tonne CO2 avoided for the blast furnace and Corex flue gases respectively. These compare with A$74 and A$56 per tonne for the costs without shift conversion.
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For the conventional blast furnace flue gas, converting the CO to CO2 does not reduce the overall capture cost. There is a reduction in the energy penalty from over 1,500 to 1,080 kJ per kg CO2 captured because of the more concentrated and higher pressure feed gas. However, the capital cost increases from $430m to $1,800m because of the requirement for a feed gas compressor, water-gas shift reactor and H2 turbine. The higher capital cost offsets any gains from the reduced energy penalty.
For Corex flue gas, converting the CO to CO2 does have economic benefit. Although the capital cost increases significantly from A$200m to over $2,000m, the energy penalty falls by almost a third (from over 1,400 to 550 kJ per kg CO2 captured). This reduction in energy penalty), significantly reduces the operating costs per tonne of CO2 captured. Thus, for Corex flue gases, CO conversion is economically advantageous.
Additionally, conversion of CO to CO2 for the Corex flue gas is more advantageous than for the blast furnace flue gas because of the higher initial CO concentration in the Corex flue gas. Firstly, this reduces the size of the water shift reactor. Secondly, it generates more CO2 per unit of feed gas. Thus, the amount of CO2 avoided is also much higher.
In the study by Gielen (2003), the estimated CO2 capture cost for a converted blast furnace using Selexol solvent is US$18 to US$19 per tonne CO2 avoided. This compares with a value of US$60 per tonne CO2 avoided in this paper. The lower value reported by Gielen (2003) rests on his assumption that the water-gas shift reaction occurs in a membrane reactor with negligible cost compared with the CO2 separation
21
unit. If a similar assumption is adopted in this paper, along with the same economic parameters, the capture cost is US$20 per tonne CO2 avoided. The detailed evaluation of novel separation technologies including membrane reactors is beyond the scope of this paper and will be investigated in subsequent work.
3.5
Capture costs for oil refineries
In Australia, over 5.5 million tonnes of CO2 is emitted from oil refineries throughout the country (DCC, 2006). A typical facility in Australia emits approximately 1 million tonnes per year. The emissions are primarily the result of combustion in heaters, accounting for approximately 30 to 60 percent of the total onsite emissions. The remainder comes from utilities and onsite power generators (20-50%), the catalytic cracker (20-35%) and the hydrogen plant (5-20%) (van Straelen et al. 2008). According to the IEA GHG (2000a) study examining CO2 capture from oil refineries, the CO2 emission profile from a hydro-cracking refinery is very similar to that for a fluidised catalytic cracking (FCC) refinery. Thus the CO2 capture technology required would be similar for both types of refineries.
This paper reports the cost of capturing CO2 from the process heater flue gas of an oil refinery, where the typical CO2 concentration is 9 percent (Figure 8). This stream is chosen as it represents the largest point source within the oil refinery and is therefore the most likely place where CO2 capture would be initially implemented. The composition and operating conditions of the process exhaust gas flue gas are taken from the IEA GHG study (2000a).
22
The cost of capturing CO2 from the process heater exhaust gas of a typical oil refinery in Australia is A$102 and US$87 per tonne CO2 avoided (Figure 4 and Table 4). These costs are higher than the costs of capturing CO2 from sub-critical pulverised coal power plants. The costs are higher firstly because of the lower CO2 concentration in the oil refinery exhaust flue gas (9% compared with 13%), which results in larger more expensive equipment. Secondly, the smaller scale of the capture project (1 million tonnes of CO2 captured at the refinery compared with over 3 million tonnes captured at the power plant) means that there are greater economies of scale for the power plant.
Previous research by Farla et al. (1995), Slater et al. (2002) and the IEA-GHG (2000a) examining CO2 capture at these facilities reported capture costs in the range US$27 to US$47 per tonne CO2 avoided. Our estimate of US$87 per tonne CO2 avoided lies above the highest previously estimated values, which reflects the age of these previous studies. After accounting for annual cost increases and the different economic assumptions used (discount rate and energy prices), our cost falls within the range of the previous cost estimates.
However, a new study by van Straelen et al. (2008) estimates the cost of capture CO2 from an oil refinery stack gas to be €90 per tonne CO2 avoided, or approximately A$140 per tonne CO2 captured. The higher estimate by van Straelen et al. (2008) compared to this study may arise from different assumptions. The values for the assumptions relating to set up costs, ducting and pipework and external energy were not specified in their paper to enable a direct comparison to be undertaken.
23
3.6
Capture costs in the cement industry
The cement industry in Australia is small by global standards, producing approximately 8.5 million tonnes of cement for the Australian market in 2005 (CIF 2006). There are three major cement producers with four large point sources that each emits approximately 1 million tonnes of CO2 per year. The CO2 emitted in the flue gas from these cement production sources comes directly from 1) the calcination of the limestone to produce the cement clinker and 2) the combustion of fossil fuels that provides energy for the calcination. Approximately half of the CO2 originates from the combustion of the fossil fuels and the other half originates from conversion of the raw materials. This paper reports the cost to capture CO2 from the flue gas of cement stacks where typical CO2 concentrations range from 14 to 33 percent (Figure 9). The composition of the flue gas is based on the paper by Hassan (2005), where the concentration of the CO2 in the flue gas is representative of the combined CO2 emissions from the calcination process and the combustion of fossil fuels.
The results in Figure 4 and Table 4 show that the cost of CO2 capture from a 1 million tonne year cement flue gas in Australia is approximately A$76 and US$68 per tonne CO2 avoided. The cost of capturing CO2 from cement flue gas is less than the cost of capture from pulverised coal power plants by approximately A$10 per tonne CO2 avoided. Although both flue gases are at similar operating conditions, the higher CO2 concentration in the cement flue gas (20%) compared with that for the power plant (13%) results in smaller equipment and lower costs. This reduces the overall estimated capture costs.
24
Hassan (2005) estimated the cost for capturing CO2 from a Canadian Portland cement flue gas, at US$49 per tonne CO2 captured. In contrast, this paper estimates a higher cost of US$68 per tonne CO2 avoided or US$66 per tonne captured. Instead of the external energy being supplied by an NGCC plant with CCS priced at US$100 per MWh, Hassan (2005) uses a pulverised coal power plant without CCS at a price of US$60 per MWh. Using the same external energy supply and price as Hassan (2005), the capture cost is estimated to be US$50 per tonne captured, which is similar to the value obtained by Hassan (2005). Hassan (2005) did not provide the energy penalty associated with CO2 capture so a comparison of costs of CO2 avoided cannot be made.
In the IEA Greenhouse R&D study of cement flue gas (IEA-GHG, 2008), the cost of capture using post-combustion solvent absorption was estimated as €107 per tonne CO2 avoided (approximately A$165 per tonne CO2 avoided). That cost is significantly higher than that estimated in this paper. The cost difference is due to the following differences in assumptions: 1. The energy for capture in the IEA GHG study (2008) is supplied by a new onsite black coal combined heat and power plant with capture. The coal is available at a price of €2.51 per GJ. In comparison, this paper assumes that the external energy for capture is supplied by a natural gas combined heat and power plant with CCS, with a natural gas fuel price of A$3.5 per GJ. 2. The discount rate is 10% compared with 7% assumed in this paper. 3. The cost of CO2 avoided is calculated using a different method in the IEA GHG study. The IEA GHG study estimates costs based on annuity while this study uses a net present value calculation.
25
If this paper adopts the same accounting method and economic assumptions as the IEA GHG study, the cost of the external energy supply is estimated to be €120 per MWh (with a CO2 emission intensity of 0.1 ton per MWh). The capture cost for cement flue gas is €$105 per tonne CO2 avoided which is similar to the value obtained by the IEA GHG (2008).
4
Regional impacts and cost uncertainties
4.1
Impact of different prices and fuel for the external energy supply
In this paper, the baseline capture costs are obtained by assuming that the external energy used to power the capture facility is provided by a natural gas combined heat and power plant fitted with CCS at a price of $100 per MWh. The following sensitivity analysis examines the changes to the estimated baseline costs for the different emission sources if different external energy prices and fuels are used. The analysis considers:
Part A (Figure 10) ·
The price of the external natural gas power plant with CCS increases to A$175 per MWh (AI) or decreases to A$80 per MWh (AII). The emission intensity is 0.045 tonne CO2 per MWh.
·
The external natural gas combined heat and plant power plant does not have CCS and has an emission intensity of 0.4 tonnes per MWh. Three energy prices are considered; A$60 per MWh (AIII), A$120 per MWh (AIV) and A$50 per MWh (AV).
26
Part B (Figure 11) ·
The external energy is supplied by a pulverised black coal power plant with CCS where the CO2 emission intensity is 0.1 tonnes CO2 per MWh. Two prices are examined, A$100 per MWh (BI) and A$85 per MWh (BII).
·
The external pulverised black coal power plant does not have CCS and the CO2 emission intensity is 0.9 tonnes CO2 per MWh. Two prices are examined, A$55 per MWh (BIII) and A$45 per MWh (BIV).
Changes in economic conditions or in global supply and demand can cause significant fluctuations in the price of fuels such as natural gas or coal. This in turn will affect the price of the energy provided by the external power plant. In the baseline analysis, we estimated an energy price of A$100 per MWh using a natural gas price of A$3.5 per GJ. If the price of natural gas increases to A$10 per GJ, the external energy price exceeds A$175 per MWh. A decrease in the gas price to A$2 per GJ reduces the energy price to less than A$80 per MWh. The energy price may also reduce if the external power plant adopts advanced boiler or capture technology or if the capital costs reduce significantly (e.g. due to technology learning curves).
Figure 10 shows that increasing the price of the external energy by 75 percent to A$175 per MWh increases the capture cost for all the emission sources by approximately A$30 per tonne CO2 avoided (Case AI). The percentage increase is approximately 35 percent for oil refinery exhaust flue gas, 40 percent for blast furnace and cement flue gases, with the highest increase of 55 percent for the Corex flue gas.
27
Figure 10 shows that decreasing the price of the external energy by 20 percent to A$80 per MWh reduces the capture costs for all emission sources by approximately A$10 per tonne CO2 avoided or 10 to 15 percent (Case AII).
Due to various constraints such as space, operating restrictions or cost, it may not always be technically or economically feasible to fit the external energy supply with CCS. If capture facilities are not fitted, the price of the external energy will decrease because the capital and operating costs are lower. However, the amount of CO2 avoided would also be lower. Using natural gas fuel with a price of A$3.5, A$10 and A$2 per GJ, the prices for the external energy supply without CCS are A$60 (Case AIII), A$120 (Case AIV) and A$50 per MWh (Case AV) respectively. For an external NGCC power plant without CCS, the capture cost decreases by an average of A$2 (3%) for oil refinery exhaust flue, A$7 (8%) for blast furnace and cement flue gases, and, up to A$10 per tonne CO2 avoided (16%) for Corex flue gas.
Sometimes it may be preferable to use another fuel such as a black coal instead of natural gas in the external power plant. At the same energy price of A$100 per MWh and with CCS, Figure 11 shows that the capture costs for all the emission sources increase by A$2 to A$3 per tonne CO2 avoided or 2 to 3 percent (Case BI). The costs are higher because of the higher emission intensity of the coal power plant compared with that for the natural gas plant (0.1 compared with 0.05 tonnes CO2 per MWh). As was the case for the external natural gas power plant with CCS (Case AII), if the energy price for the coal power plant with capture decreases to A$80 per MWh, the capture costs decrease (Case BII). However, the costs only fall by A$7 per tonne CO2 avoided
28
or an average of 10 percent. Again, the slightly higher emission intensity of the external coal power plant with capture reduces the overall amount of CO2 avoided, driving up the capture costs.
Figure 11 also shows that if the external energy is supplied by a coal power plant which does not have CCS (Cases BIII and BIV), then the capture cost estimates for the industrial emission sources increases compared with 1) the NGCC power plant without CCS (Case AIII) and 2) the equivalent coal power plant with CCS (Cases BI and BII). The higher CO2 emission intensity of the coal power plant without CCS (0.9 tonne CO2 per MWh) reduces the amount of CO2 avoided and thus increases the capture costs in terms of $/tonne CO2 avoided estimated for the industrial emission sources. Compared with using an external coal power plant with CCS (Case BI and BII), the average cost increase for Cases BIII and BIV is less than A$5 (2%) for the Corex flue gas, approximately A$10 (15%) for the blast furnace and cement flue gases and close to A$30 per tonne CO2 avoided (30%) for the oil refinery exhaust flue gas. The increase in cost is most significant for the oil refinery exhaust flue gas. This is because of the very high energy penalty for this emission source.
Several conclusions can be drawn from the sensitivity analyses in Figures 10 and 11.
Firstly, if natural gas is used for the external energy plant, it is cheaper to provide the energy without CCS. This is because the emission intensity of the natural gas power plants without CCS is relatively low (0.4 tonnes CO2 per MWh). In comparison, although the external power plant with CCS has an emission intensity of 0.05 tonnes
29
CO2 per MWh, the energy price is on average almost 50 percent more expensive at each relative natural gas price. Using an external power plant with CCS increases the overall amount of CO2 avoided because of the lower CO2 emission intensity. However, because of the higher energy price, the operating costs are significantly larger and thus the capture costs per tonne avoided are also higher. This is particularly true for industrial sources that have low energy penalty associated with capture such as the Corex flue gas. However the difference is less significant for cases where the capture energy penalty is high, such as for oil refinery exhaust flue gas.
Secondly, if the external energy supply is cheap, this will reduce the capture costs for the industrial emission sources. This is obvious. However, for the energy price of the external power plant with CCS to be low (approximately A$80 per MWh or less), reductions in the energy penalty or capital and operating costs are required. This might be achieved, for example, through improved power plant design (such as higher efficiency boilers), waste heat integration, improvements in solvent regeneration or use of novel materials of construction.
Thirdly, in general, the capture cost estimates are higher when using an external coal power plant without CCS than when the external energy supply (either coal or natural gas) has CCS. This is true for blast furnace, cement and oil refinery exhaust flue gases. However, there is an exception for the Corex flue gases when the energy price is low (A$45 per MWh or less). This is because a low energy price coupled with the low capture energy penalty for this emission source results in relatively low energy operating costs. Although the CO2 emission intensity of the coal power plant without
30
CCS is higher (0.9 tonne compared with 0.05 or 0.01 CO2 emitted per MWh) and results in a lower amount of CO2 avoided, the decrease in energy costs is proportionally larger, thus resulting in the overall lower capture cost.
Fourthly, at an equivalent energy price, use of natural gas rather than coal as the fuel results in lower capture cost estimates. This is because of the lower emission intensity of this fuel.
4.2
Cost sensitivities
Figure 12 shows the cost variations for CO2 capture from blast furnace flue gas as a function of changes in the capital costs, operating capacity of the capture plant, project life and the discount rate. Sensitivity analyses for the other technologies discussed in this paper show a similar pattern.
The results show that the parameter that has the most significant effect on the capture cost is the uncertainty in capital cost estimates. The other significant parameter is the discount rate. Although the length of the expected project life and plant operating factor do impact the capture cost, they are not significant. Doubling the project life or changing number of plant operating hours by 10 percent changes the capture cost by less than 5 percent. The project life only has a significant impact on cost if it is quite short (less than 10 years), in which case costs increase by up to 25 percent. Similar trends were observed for the other industrial emission sources.
31
4.3
Deployment opportunities for selected industrial emission sources
The costs in Figure 4 suggest that if a carbon trading regime is established and if carbon prices increase over time and if decisions are made purely on a market basis, then we might expect different timelines for implementing CCS for different industry sectors. Based on the costs considered in this paper, iron and steel manufacturers using Corex technology might be early adopters of CCS. As the carbon price increases or CCS technologies are incrementally improved, CO2 capture could be then implemented in the cement industry or at blast furnaces in iron production facilities. The power sector and the oil refining industry might be the last to implement CCS. Based on these assumptions, if CO2 capture is to be implemented at an earlier stage by these latter industries, process improvement and breakthrough innovations in technology would be required for CCS to be economically attractive. Previous studies (Ho et al., 2006, 2008a; 2008b; Harkin et al, 2008) indicate that this can be achieved by using more advanced low regeneration energy solvents or by reducing the energy consumption through process heat integration. Further, coupling of the process improvements with technology innovations and equipment cost reductions could see capture cost fall by up to 40 percent.
5
Conclusion
This paper presents preliminary estimates of CO2 capture costs for three Australian industries: iron and steel production, oil refineries and cement manufacturers.
If the capture of CO2 using the processes described in this paper could be implemented across all of these industrial emission sources, Australia’s total annual CO2 emissions
32
would reduce by up to 20 million tonnes. At a carbon price of less than A$60 per tonne CO2 avoided, the moderate cost of CO2 capture from iron production facilities, and the likely economies of scale that may be obtained in Australia suggests that this industry may be able deploy CCS at an early stage. The higher capture costs for cement manufacture suggest that further technological improvements or increases in the carbon price are required before CCS is applied. The much higher capture costs for oil refineries and the complex nature of the facilities suggests that financial incentives or further technological improvements are required before CCS is applied.
The results presented in this paper show that relative costs of post combustion CO2 capture for these industrial emission sources may be lower or similar to that of a black coal pulverised coal power plant. The lower costs reflect the higher CO2 concentrations of flue gases from the iron and cement industries. However, these estimates are only indicative. They have not taken into account site specific details such as trace component treatment, land acquisitions or process modification, which may significantly affect the costs estimates.
The capture costs presented in this paper have been estimated for small to medium scale industrial emission sources in Australia. Although the cost estimates take into account the smaller gas flowrates for these sources compared to pulverised coal power plants by estimating higher unit costs for capital equipment as A$ per tonne of CO2 captured, the results may be at the higher end of potential cost savings.
33
This paper only considers the costs for the capture of the CO2 for a limited range of industrial processes. Future work will evaluate the costs for the entire CCS network comprising capture, transport and storage for a wide range of industrial emission sources. A full assessment of CCS deployment opportunities at an industrial facility would also be influenced by factors such as the proximity to suitable geological storage facilities. Furthermore, when an emissions trading scheme is implemented, variables such as emissions caps, the offsets allowable and the value and number of permits offered will undoubtedly influence the cost of CCS. Future evaluation of the economic costs of capture and/or storage should attempt to include these parameters. It would also be valuable to assess the individual characteristics of each industrial emission source alongside opportunities for heat and technology integration in order to provide a more accurate estimate of the CCS costs for specific cases. Given the very large GHG reductions possible in the power and industrial sectors, the priority given to investment in large-scale demonstration projects by the G8 and the support being provided through the Australian government initiative the Global Carbon Capture and Storage Institute (GCCSI) (G8 Energy Ministers, 2009) is justified.
6
Acknowledgements
The authors would like to acknowledge the Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) for their financial support. We thank our reviewers from the CO2CRC, Mr Barry Hooper and Dr Dennis Van Puyvelde for their comments and feedback.
34
7
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AER (2008). State of the energy market 2007, Australian Energy Regulator. Available at
http://www.aer.gov.au/content/index.phtml/itemId/656023 Allinson, G., Ho, M. T., Neal, P. N., Wiley, D. E. (2006). The methodology used for estimating the costs of CCS. In Proceedings of Eighth International Conference on Greenhouse Gas Technologies (GHGT-8), Trondheim, Norway. Allinson, G., Nguyen, D. (2002). CO2 geological storage economics. Sixth International Conference on Greenhouse Gas Control Technologies (GHGT-6), Kyoto, Japan. Dave, N. G., Duffy, G. J., Edwards, H.,Lowe, A. (2000). Evaluation of the options for recovery and disposal of CO2 from Australian black coal-fired power stations, ACARP Report C7051, Australia CSIRO Energy Technology. DCC (2006). Department of Climate Change (Australian Greenhouse Office). National Greenhouse Gas Inventory 2006. Accessed Dec 2008. Available at
http://www.climatechange.gov.au/inventory/ CIF (2006). Cement Industry Federation website. Accessed Dec 2008. Available at
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http://www.g8energy2009.it/pdf/Session_I_+EC.pdf Gielen, D. (2003). CO2 removal in the iron and steel industry. Energy Conversion and Management 44(7): 1027-1037. Gibbins, J. R.,Crane, R. I. (2004). Potential for improvements in power generation with postcombustion capture of CO2 . Seventh International Conference on Greenhouse Gas Control Technologies (GHGT-7), Vancouver, Canada. Hassan, S. M. N. (2005). Techno-economic study of CO2 capture process for cement plants. Chemical Engineering. Waterloo, Ontario, Canada, University of Waterloo. Harkin, T., Hoadley, A., Hooper, B. (2008) Process integration analysis of a brown coal-fired power station with CO2 capture and storage and liquid drying. In Proceedings of Ninth International Conference on Greenhouse Gas Technologies (GHGT-9). Washington DC, USA. Ho, M. T., Allinson, G. W.,Wiley, D. E. (2008a). Reducing the Cost of CO2 Capture from Flue Gases Using Membrane Technology. Ind. Eng. Chem. Res. 47(5): 1562-1568. Ho, M. T., Allinson, G. W.,Wiley, D. E. (2008b). Reducing the Cost of CO2 Capture from Flue Gases Using Pressure Swing Adsorption. Ind. Eng. Chem. Res. 47(8): 4883-4890.
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Ho, M. T., Wiley, D. E.,Allinson, G. (2006). Reducing the cost of post-combustion CO2 capture. In Proceedings of Eighth International Conference on Greenhouse Gas Technologies (GHGT-8), Trondheim, Norway. Hu, C., Han, X., Li, Z.,Zhang, C. (2009). Comparison of CO2 emission between COREX and blast furnace iron-making system. Journal of Environmental Sciences 21(Supplement 1): S116-S120. IEA-GHG (2000a). CO2 abatement in oil refineries: fired heaters. Report No. IEA/CON/99/61, Cheltenham, UK, IEA Greenhouse Gas R&D Programme. IEA-GHG (2000b). Greenhouse gas emissions from major industrial sources - Iron and steel production. Report No. PH3/30, Cheltenham, UK, IEA Greenhouse Gas R&D Programme. IEA-GHG (2000c). Greenhouse gas emissions from major industrial sources IV - The aluminium industry. Cheltenham, UK, IEA Greenhouse Gas R&D Programme. IEA-GHG (2008). CO2 capture in the cement industry. Report No. 2008/3, Cheltenham, UK, International Energy Agency Greenhouse Gas R&D Programme. IPCC (2005). IPCC Special Report on Carbon Dioxide Capture and Storage. Cambridge, England, Intergovernmental Panel Climate Change. Lampert, K.,Ziebik, A. (2006). Comparative analysis of energy requirements of CO2 removal from metallurgical fuel gases. Energy 32(4): 521-527. NIEIR (1996). Subsidies to the use of natural resources, National Institute of Economic and Industry Research. Report to the Department of Environment, Sport and Territories, Commonwealth of Australia. Peters, M. S., Timmerhaus, K. D.,West, R. S. (2003). Plant design and economics for chemical engineers. New York, McGraw-Hill. Rubin, E. S., Chen, C.,Rao, A. B. (2007). Cost and performance of fossil fuel power plants with CO2 capture and storage. Energy Policy 35(9): 4444-4454. Slater, M., West, E.,Mariz, C. L. (2002). Carbon dioxide capture from multiple flue gas sources. In Proceedings of Sixth International Conference on Greenhouse Gas Control Technologies (GHGT-6), Kyoto, Japan. van Straelen, J., Geuzebroek, F., Goodchild, N., Protopapas, G., Mahony, L. (2008) CO2 capture for refineries, a practical approach. In Proceedings of the 9th International Conference on Greenhouse Gas Control Technologies (GHGT-9), 2008, Washington DC, USA Wingrove, G. Satchell, D., Keenan, B, van Aswegen, C. (1999) Developments in iron making and opportunities for power generation. In Proceedings of Gasification Technologies Conference, San Francisco, VSA Worrell, E., Price, L.,Martin, N. (2001). Energy efficiency and carbon dioxide emissions reduction opportunities in the US iron and steel sector. Energy 26(5): 513-536.
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List of Figures Figure 1 CO2 separation and capture viewed as part of an entire industrial process 39 Figure 2 Typical layout of post-processing CO2 capture involving pretreatment, separation and compression for chemical solvent based capture 40 Figure 3 Schematic of an industrial facility with CO2 capture, where energy is supplied externally 41 Figure 4 Capture costs for industrial flue gases using solvent absorption. The type of solvent used for each gas is indicated in the brackets 42 Figure 5 Schematic of CO2 capture from blast furnace flue gas
43
Figure 6 Schematic of CO2 capture from Corex iron production
44
Figure 7 Process flow diagram of CO2 capture by converting a conventional blast furnace flue gas using a water gas shift reaction 45 Figure 8 Schematic of CO2 capture from oil refineries
46
Figure 9 Schematic of the for CO2 capture from cement production
47
Figure 10 Changes in capture costs using a natural gas external power plant with and without CCS at different energy prices. 48 Figure 11 Changes in capture cost using a black coal external power plant with and without CCS at different energy prices. 49 Figure 12 Sensitivity of capture cost to processing and economic assumptions; discount rate plant operating capacity capital cost and project life 50
37
8
Figures
Waste gas
Feed gas Industrial facility
Source
Pretreatment
CO2 separation and compression
Capture
Transport pipeline
Injection and storage
Storage
Figure 1 CO2 separation and capture viewed as part of an entire industrial process
38
FGD
Particulates
SCR
Feed Gas
Lean gas to atmosphere
Blower or compressor Capture Heat Exchanger
100 bar CO2 to storage
Pretreatment
CO2 Compressor Separation
Compression
Figure 2 Typical layout of post-processing CO2 capture involving pretreatment, separation and compression for chemical solvent based capture
39
0.045 ton CO2 /MWeh to a tmosphere
CO2 + flue to atmosphere
CO2 ca pture
Industria l fa cility
Energy
Flue ga s
CO2 to stora ge
External power fa cility with
CO2 to stora ge
Figure 3 Schematic of an industrial facility with CO2 capture, where energy is supplied externally
40
$100 $90 Fixed Opex
$80
A$/t CO2 2008
$70
Set up costs General equipment
Materials replacement
$60
Compression Separation Pretreatment
$50 $40 $30
Energy Opex
$20 $10 $0
Oil refinery
PCC
Cement
MEA solvent
BF
Corex
Shifted BF
Shifted Corex
Selexol solvent
Figure 4 Capture costs for industrial flue gases using solvent absorption. The type of solvent used for each gas is indicated in the brackets
41
Blast furnace flue gas Waste gas
Hot air Capture facility sinter + coke
Blast furnace
CO2
M olten steel
Figure 5 Schematic of CO2 capture from blast furnace flue gas
42
Corex flue gas Waste gas
O2 Capture facility raw materials
Corex
CO2
M olten steel
Figure 6 Schematic of CO2 capture from Corex iron production
43
Electricity N2/H2 for further processing
BF flue gas 1 bar Blast furnace 293 K (BF)
BF flue gas 20 bar Water shift 308 K reactor
CO2/N2/H2 19 bar 313 K
Compressed CO2 100 bar CO2 Capture
Water Steam
Figure 6 Process flow diagram of CO2 capture by converting a conventional blast furnace flue gas using a water gas shift reaction
44
Combustion furnace
Exhaust gas Waste gas Combined flue gases
Capture facility
CO2
Combustion furnace Exhaust gas
Figure 7 Schematic of CO2 capture from oil refineries
45
Prepared raw material
Exhaust gas from combustion Preheater
Waste gas
Capture facility
CO2
Kiln Exhaust gas from calcination
To the clinker
Figure 8 Schematic of the for CO2 capture from cement production
46
$160 NGCC + CCS (A$175/MWh) - A I NGCC no CCS (A$120/MWh) - A IV
NGCC + CCS (A$80/MWh) - A II NGCC no CCS (A$50/MWh) - A V
$140
$/t CO2 (2008 AUS)
$120
NGCC + CCS (A$100/MWh) - Baseline NGCC no CCS (A$60/MWh) - A III
$100 $80 $60 $40 $20 $0 Corex
Blast furnace
Cement
Refineries
Figure 9 Changes in capture costs using a natural gas external power plant with and without CCS at different energy prices.
47
$160 Coal + CCS (A$100/MWh) - B I Coal no CCS (A$55/MWh) - BIII
$140
Coal + CCS (A$85/MWh) - B II Coal no CCS (A$45/MWh) - BIV
$/t CO2 (2008 AUS)
$120 NGCC + CCS (A$100/MWh) - Baseline NGCC no CCS (A$60/MWh) - A III
$100 $80 $60 $40 $20 $0 Corex
Blast furnace
Cement
Refineries
Figure 10 Changes in capture cost using a black coal external power plant with and without CCS at different energy prices.
48
$100
Blast furnace flue gas Capex
A$/t CO2 avoided
$90
Discount rate $80
Project life $70
Operating hours
$60
$50
0%
50%
100%
150%
200%
250%
300%
Relativity to baseline assumption
Figure 11 Sensitivity of capture cost to processing and economic assumptions; discount rate plant operating capacity capital cost and project life
49
List of Tables Table 1 Industrial flue gas characteristics
52
Table 2 Summary of processing conditions, inputs and results for this paper and previous studies
53
Table 3 Itemised capital cost factors
54
Table 4 Summary of results for CO2 capture using solvent absorption
55
50
9
Tables
Table 1 Industrial flue gas characteristics
Comments
Steel (Hu et Steel Refinery Cement al., 2009, (Farla et al., (IEA-GHG, (Hassan, Wingrove et 1995) 2000a) 2005) al. 1999) Typical ConventO2 blown – Boiler Portland ional blast Corex exhaust gas cement furnace process
Pulverised coal power plant (Dave et al., 2000)
393
215
11
70
630
311 12.9 1
58 7.8 3.5
15 8.3 1.01
81 2.3 1
705 21.28 1.01
20
40
180
160
110
20 50 --3 21
24 – 30 5 – 12 -1 17 44 2 85 (%) CO2 captured Variable (MtCO2/yr) CO2 compression 100 (bar)
90 2.8 110
90
Slater et IEA-GHG Farla et Hassan al. (2000a) al. (2005) (2002) (1995)
IEA-GHG (2008)
Petro- Petro- Petrochemical chemical chemical Cement Cement s s s MEA MEA MEA MEA MEA solvent solvent solvent solvent solvent 90
Unknow 1.26 n Unknow Unknow n n
90
90
90
85
1
1.8
0.66
1.07
100
110
1
110
25
25
20
25
10
5
7
10
US
US
US
US
1999
1990 Unknow n
2005
2005
90
90
Coal
Coal
Coal
Coal
50
50
60
Internal CHP costing
Economics Project life (years) Discount rate (%) Currency
25
25
25
7
5
12
US
US
AUD and US 2008
Unknow n Unknow n US
1990 2001 2001 Cost year Plant operating Unknow Unknow Unknow Variable capacity (%) n n n External power plant Natural Unknow Coal Coal fuel gas n 100; External power price 100 (US$/MWh; A$/MWh) Baseline fuel price 7; (US$/GJ; A$/GJ) 3 Range of fuel price for sensitivity analysis (A$/GJ) 2 – 10 Natural gas Coal Capital cost for capture facility (US$million) Energy penalty (kJe/kg captured CO2) Capture cost (US$/tonne CO2 avoided)
50
15
Unknow n
90
Unknow Unknow Unknow n n n
Unknow Unknow n n
€2.5
0.8 – 1.1 TBD
372
--
145
145
252
35
€295
TBD
~1150
590
--
2340
1420
--
1970
TBD
35
18
40-45
27
46
49 /tonne captured
€107
52
Table 3 Itemised capital cost factors
Equipment A costs B Set up costs
C D E F G H I J K
Capital cost elements Process Equipment Cost (PEC) General facilities
Nominal value Sum of all process equipment 10-20% PEC
Total Equipment Cost (TEC) Instrumentation Piping Electrical Total Installed Cost Start-up costs Engineering Owners costs Engineering, procurement, construction and owner’s cost (EPCO) Project Contingency TOTAL CAPITAL COST (CAPEX)
A+B 15% TEC 20% TEC 7 % TEC A + B+ C+ D +E 8% TIC 5% TIC 7% (F + G + H) F+G+H+I 10% EPCO =J+K
53
Table 4 Summary of results for CO2 capture using solvent absorption
Feed gas Solvent system CO2 emitted before capture (MtCO2/yr*) CO2 captured (MtCO2/yr) CO2 avoided (MtCO2/yr) Energy penalty (kJe/kg captured CO2) Capital costs (A$ million) (US$ million) Operating costs (A$million/yr) (US$million/yr) DCOE (A$/MWh) A$/t CO2 avoided US$/t CO2 avoided
Pulverised coal power plant (500MW) MEA
Blast furnace flue gas
Corex iron production flue gas
Shifted Blast Furnace flue gas
Shifted Corex flue gas
Oil refinery exhaust flue gas
Cement flue gas
MEA
MEA
Selexol
Selexol
MEA
MEA
3.01
3.05
2.22
6.26a
11.01 a
0.89
0.86
3.92
2.75
2.00
5.65 a
9.91 a
0.88
0.77
2.57
2.69
1.96
5.57 a
9.87 a
0.78
0.75
1,550
1,506
1,406
1,080
550
1,590
1,500
1,250 b 900 b
430 315
200 145
1,838c 1,339 c
2,036 c 1,642 c
253 176
131 91
130 b 110 b
162 153
91 88
252 215
206 170
57 52
46 43
62
¾
¾
¾
¾
¾
¾
88
74
56
74
39
102
76
70
68
52
60
32
87
68
* Million tonnes per year a) Including the conversion of CO to CO2 b) Including the capital and operating costs for the upgraded power plant c) Including costs for the feed gas compressor, water-gas shift reactor and larger absorption system
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