2.4 Preliminary cost estimates for CCS in India

2.4.1 Introduction

This part of the study develops cost flow sheets for key CO2 capture and storage (CCS) components for global and Indian conditions and estimates future cost developments for CCS technology. It also assesses the availability of key cost data for the development of more robust cost estimates in the future.

With almost all other sub-systems in the CCS chain being a mature market currently, capture sub-systems account for 60-80% of the CCS system costs for geological storage (Table 2.16). Their high costs are the major hurdle in CCS acceptability on commercial scales as a competitive CO2 sequestration option with respect to other near-zero CO2 emission technologies. Costs vary considerably in both absolute and relative terms across countries and type of capture systems. The costs of CCS in tandem with an IGCC or a combined cycle gas plant have higher uncertainty since they are not yet built on a full commercial scale. In the future, the costs of CCS are projected to be reduced by research and technological development, learning curves, and economies of scale.

Table 2.16 The current global cost ranges for CCS system components

CCS system components Cost range Remarks
Capture from a coal- or gas-fired power plant 15 - 60 US$/tCO2 net captured Net costs of captured CO2, compared to the same plant without capture
Capture from hydrogen and ammonia production or gas processing 5 - 50 US$/tCO2 net captured Applies to high-purity sources requiring simple drying and compression
Capture from other industrial sources 25 - 115 US$/tCO2 net captured Range reflects use of a number of different technologies and fuels
Transportation 1 - 8 US$/tCO2 transported Per 250 km pipeline or shipping for mass flow rates of 5 (high end) to 40 (low end) MtCO2/yr.
Geological storage 0.5 - 8 US$/tCO2 injected Excluding potential revenues from EOR or ECBM.
Geological storage: monitoring and verification 0.1 - 0.3 US$/tCO2 injected This covers pre-injection, injection, and post-injection monitoring, and depends on the regulatory requirements
Ocean storage 5 - 30 US$/tCO2 injected Including offshore transportation of 100 - 500 km, excluding monitoring and verification
Mineral carbonation 50 - 100 US$/tCO2 net mineralized Range for the best case studied. Includes additional energy use for carbonation

Source: Updated version of a similar table from IPCC, 2005

2.4.2 Cost components and plants - fuels covered

For the purpose of this report, we have analyzed the costs components of the three main modules of the CCS system, namely capture, transport and storage. The cost components are analyzed for both global and Indian conditions to enable cost comparisons and furthermore, to use the global cost data as basis for some of the Indian costs estimates.

The capture cost analysis includes the cost of capture from pulverized coal (PC), ultra super critical (USC), integrated gasification combined cycle (IGCC) coal power plants and also natural gas processing plants. The components analyzed are capture & compression capital costs, flue gas cleaning capital costs, capture & compression operation and maintenance (O&M) costs and flue gas cleaning O&M costs. Since technical data for Indian conditions are still limited, it was decided not to go into further detail with further disaggregated sub-components of capture costs at this point. The transport cost analysis includes the capital and O&M costs of on-shore and offshore pipelines with a range of different diameters. The storage cost analysis includes Enhanced Oil Recovery (EOR), Enhanced Coal Bed Methane (ECBM), depleted oil & gas reservoir and saline aquifer storage. All storage cost estimates are based on on-shore storage.

For all O&M costs the Net Present Value (NPV) is calculated. The NPV calculations use a discount rate of 8 per cent and a plant lifetime of 30 years. The total NPV of the different cost components are found by summing the overnight capital cost and the O&M NPV costs.

Future cost developments for the three main CCS modules are estimated up to 2030. The estimates are based on cost projections by the IEA and REN21 for other relevant and alternative energy technologies.

For cost data given in Indian Rupees a conversion factor of about 44 Rs/USD is used. For cost data given in Danish Crowns a conversion factor of about 5.6 Danish Crowns/USD is used. The cost data given in USD are from the late 1990s to early 2000s. Due to uncertainty in the cost data, no adjustments have been made to correct for exchange rate variations and inflation.

The numbers given in the tables have been rounded, taking into account the data uncertainties.

2.4.3 Flow sheets for estimates of global cost

The global cost estimates are based on data obtained mainly from American and European sources and reflect the going global market price for the different CCS components. Since more data on CCS systems exists on a global level, it is possible to use the global costs estimates to validate, and in some cases as basis for, the Indian cost analysis.

2.4.3.1 CAPTURE COSTS

The results from the capture cost analysis are shown in Table 2.17. The capture costs for PC, USC, IGCC and gas processing plants are broken down into capture & compression capital costs, flue gas cleaning capital costs, capture & compression O&M costs and flue gas cleaning O&M costs. In addition the NPV of the O&M costs are calculated.

The capture & compression capital cost for a PC plant is based on a capture system applied to a new-build, sub-critical bituminous coal-fired plant, with an efficiency of 39 per cent. The capture system is assumed to have a 95 percent capture efficiency using a MEA sorbent (IPCC, 2005). The annual O&M costs of the capture & compression system are assumed to be 4 per cent of the capital cost (Azar et al, 2006). The energy penalty of the capture & compression system is not included in the O&M costs, but is estimated to be a 40 per cent increase in input per KWh (IPCC, 2005). The capital cost of flue gas cleaning is based on data from The World Bank (2007). Since ESP systems are standard equipment in most new-build and existing power plants, their costs are assumed to be included in the plant capital cost. Therefore only the cost of flue gas desulphurization (FGD), low NOx burner and selective catalytic reduction (SCR) are included in the flue gas cleaning system required for a CCS system. Some of the cost numbers are from the mid/late 1990s and could therefore be expected to be slightly overestimated as the costs may have declined. However, The World Bank’s estimates vary by more than 100% and hence a mean cost is thought to be a good estimate of the costs in the beginning of the 21st century. The flue gas cleaning O&M costs are also based on data from The World Bank (2007). Since The World Bank gives the O&M costs in $/MWh, the costs have been converted to $/KW/yr by applying them to a hypothetical power plant with a capacity factor of 0.75.

The capture & compression capital cost for the USC plant is based on a capture system applied to a new-build, bituminous coal fired plant, with an efficiency of 41 per cent. The capture system is assumed to have a 90 percent capture efficiency using a MEA sorbent (IPCC, 2005). The annual capture & compression O&M cost is assumed to be 4 per cent of the capital cost similar to the PC plant (Azar, C. et al, 2006). The capture energy penalty is estimated to be a 31 per cent increase in input per KWh (IPCC, 2005). The cost of flue gas cleaning is assumed to be the same as for the PC plant.

The capture & compression capital cost for the IGCC plant is taken as an average of capture systems applied to new-build, bituminous coal fired IPCC plants, with efficiencies of 38-47 per cent. The capture technology used in all cases is Selexol (IPCC, 2005). The annual capture & compression O&M cost is assumed to be 4 per cent of the capital cost as for the plants above (Azar, C. et al, 2006). The capture energy penalty is estimated to be a 19 percent increase in input per KWh (IPCC, 2005). Since no significant flue gas cleaning is necessary for this plant type, this parameter has not been included.

The gas processing plant costs included in the global estimate are based on data from the In Salah project (Haddadji, R., 2006). Since the cost cannot be given in $/KW it is given for an injection capacity of 1, 0 Mt CO2/yr. The annual O&M cost is again assumed to be 4 per cent of the capital cost. No flue gas cleaning costs are included.

Table 2.17 Global capture system costs

Base plant Capital costs, Capture & compression Capital costs, Flue gas cleaning Capital costs, TOTAL O&M costs, Capture & compression O&M costs, Flue gas cleaning O&M costs TOTAL NPV O&M Costs NPV TOTAL
PC 1 100 $/KW 210 $/KW 1 310 $/KW 40 $/KW/yr 110 $/KW/yr 150 $/KW/yr 1 700 $/KW 3 000 $/KW
USC 730 $/KW 210 $/KW 940 $/KW 30 $/KW/yr 110 $/KW/yr 140 $/KW/yr 1 530 $/KW 2 470 $/KW
IGCC 500 $/KW - 500 $/KW 20 $/KW/yr - 20 $/KW/yr 230 $/KW 730 $/KW
Gas Processing plant, Capacity 1,0 Mt CO2/yr $ 100 mill - $100 mill 4,0 mill $/yr - 4,0 mill $/yr $ 45 mill $ 145 mill

2.4.3.2 TRANSPORT COSTS

The global transport costs are shown in Table 2.18. Since very little publicly available data exists on CO2 pipelines, the cost of natural gas pipelines can be used as a good estimate of CO2 pipeline costs (Heddle et al. 2003). However, cost of CO2 pipelines can be slightly higher than natural gas pipelines due to increased pipeline corrosion and, for on-shore pipelines, a need for thicker walls to handle pressures of 100-150 bar (Heddle et al. 2003). The on-shore costs are based on data from USA (Heddle et al. 2003), while the off-shore costs a based on European data (Hansen, T. H., personal communication). The off-shore pipeline costs are based on a 50 km pipeline and hence a shorter pipeline might have higher capital costs per km.

Table 2.18 Global transport costs

Pipeline type Capital costs ($/Km) O&M costs ($/Km/yr) NPV O&M costs ($/Km) NPV TOTAL ($/Km)
On-shore 8 Inches 180 000 3 100 35 000 220 000
On-shore 16 Inches 280 000 3 100 35 000 320 000
On-shore 24 Inches 520 000 3 100 35 000 560 000
Off-shore 8 Inches 1 070 000 20 000 230 000 1 300 000
Off-shore 16 Inches 1 410 000 20 000 230 000 1 640 000
Off-shore 24 Inches 1 870 000 20 000 230 000 2 100 000

2.4.3.3 STORAGE COSTS

The global storage costs are shown in Table 2.19. For the sake of consistency all costs are given on a modular basis, since EOR and ECBM systems consist of modules of injection and production wells. All storage modules consist of 10 injection wells apart from the saline aquifer module, which only consists of one large well. It is important to note the large differences in CO2 injection capacity for the different modules. The injection rates and module costs are based on a report on CO2 storage by Heddle et al. (2003) and reflect American conditions. The costs of EOR and ECBM are given directly in the report while the costs for depleted oil and gas reservoirs are adjusted to a 10 well modular system using formulas given in the report. For the saline aquifer option the base case given in report is used (Heddle et al. 2003). For EOR, the CO2 injection effectiveness is estimated to be 170 scm CO2 per bbl enhanced oil while it for ECBM is estimated to be 2 scm CO2 per scm enhanced methane. In the EOR case CO2 recycling is needed since some CO2 is produced along with the enhanced oil. The storage costs are based on well depths of about 1200 m for EOR, 600 m for ECBM, 1500 m for depleted oil & gas reservoirs and 1200 for a saline aquifer (Heddle et al, 2003). In the storage cost estimates it is assumed that the CO2 has a pressure of at least 103 bar when it reaches the storage destination. For the EOR and ECBM processes, additional energy requirements are included in the O&M costs (Heddle et al. 2003).

Table 2.19 Global storage costs

Storage type Injection wells per module CO2 Injection per module (ton/day Injection & storage capital costs ($/module Injection & storage O&M costs ($/module/yr NPV O&M costs ($/module) NPV TOTAL ($/module)
Enhanced Oil Recovery (EOR) 10 130 3260 000 480 000 5430 000 8690 000
Enhanced Coal Bed Methane (ECBM) 10 530 6570 000 465 000 5240 000 11810 000
Depleted Oil Reservoir 10 1540 5470 000 530 000 5970 000 11440 000
Depleted Gas Reservoir 10 3520 5400 000 530 000 5960 000 11360 000
Saline Aquifer 1 7390 2150 000 100 000 1130 000 3280 000

2.4.4 Flow sheets for estimation of Indian costs

The Indian cost estimates are based on technical data from India combined with data on global CCS costs. Currently, only limited data exists for Indian conditions and hence it has in some cases been necessary to make a more general cost estimate.

2.4.4.1 INDIAN CAPTURE COSTS

The estimates of Indian capture costs are shown in Table 2.20. As in the global cost analysis, the capture costs for PC, USC, IGCC and gas processing plants are estimated. Since no capture system has been applied to an Indian power plant to date, costs estimates are derived from the capital costs of new Indian power plants given by the Indian National Thermal Power Corporation (NTPC) combined with global capture cost estimates from IPCC.

For capture systems applied to an Indian PC plant, a plant capital cost of $900/KW is used as basis (Sonde 2006, 2007). The capture system cost is then found assuming that the capture system applied to a PC plant has a capital cost of 87 percent of the power plant cost (IPCC 2005). The annual capture system O&M cost is estimated to be 4 percent of the capital cost as in the global case. The energy penalty of the capture system is as for the global case estimated to be a 40 percent increase in input per KWh (IPCC 2005). The flue gas cleaning costs are like the global estimates based on data from The World Bank.

For capture systems applied to an Indian USC power plant, a plant capital cost of $1140/KW is used (Sonde 2006). The capture system cost is then found assuming that the capture system applied to an USC plant has a capital cost of 61 percent of the power plant cost (IPCC 2005). The annual capture system O&M cost is again estimated to be 4 percent of the capital costs. The capture energy requirement is like in the global case estimated to be a 31 percent increase in input per KWh (IPCC, 2005). The flue gas cleaning costs are also equivalent to the global estimate.

For capture systems applied to an Indian IGCC plant, a plant capital cost of $1400/KW is used (Sonde 2006). The capture system cost is then estimated assuming that the capture system applied to an IGCC plant has a capital cost of 37 percent of the power plant cost (IPCC 2005). The annual capture system O&M cost is again estimated to be 4 percent of the capital costs. The capture energy requirement is as for the global case estimated to be a 19 percent increase in input per KWh (IPCC 2005). No flue gas cleaning costs are included.

The capture costs of an Indian gas processing plant are based on a planned EOR facility at the Hazira Plant operated by the Oil and Natural Gas Corporation (ONGC). The plant has a capture capacity of about 0.4 Mt CO2/yr and is expected to operate for 30-35 years (Kumar et al. 2007). The capital cost consists of capture costs, compression & dehydration costs and chemicals costs and is estimated to about $62.5 million for the whole plant. The annual O&M costs are as for the earlier estimates assumed to be 4 percent of the capital costs. No flue gas cleaning equipment is included.

Table 2.20 Indian capture system costs

Base plant Capital costs, Capture & compression Capital costs, Flue gas cleaning Capital costs, TOTAL O&M costs, Capture & compression O&M costs, Flue gas cleaning O&M costs TOTAL NPV O&M Costs NPV TOTAL
PC 890 $/KW 210 $/KW 1 100 $/KW 35 $/KW/yr 110 $/KW/yr 145 $/KW/yr 1 600 $/KW 2 700 $/KW
USC 820 $/KW 210 $/KW 1 030 $/KW 30 $/KW/yr 110 $/KW/yr 140 $/KW/yr 1 560 $/KW 2 600 $/KW
IGCC 520 $/KW - 520 $/KW 20 $/KW/yr - 20 $/KW/yr 240 $/KW 760 $/KW
Gas Processing plant, capacity 0,4 Mt CO2/yr $ 62,5 mill - $ 62,5 mill 2,5 mill $/yr - 2,5 mill $/yr $ 28 mill$ 90 mill

2.4.4.2 INDIAN TRANSPORT COSTS

The Indian transport costs are shown in Table 2.21. The on-shore pipeline cost estimates are based on the cost of the CO2 pipeline at the Hazira Plant (16 inches) and natural gas pipelines from the Indian Infraline Database (30, 42 & 48 inches), (Kumar et al. 2007; Infraline Database 2007; Dhar 2006). The annual on-shore O&M costs are estimated based on the global numbers. The off-shore capital costs are found using a global pipeline model for a 50 Km off-shore pipeline under Indian conditions (Hansen 2007). The off-shore O&M costs are assumed to be 90 per cent of the global costs, since global and Indian costs are expected to be almost equal.

Table 2.21 Indian transport costs

Pipeline type Capital costs ($/Km) O&M costs ($/Km/yr) NPV O&M costs ($/Km) NPV TOTAL ($/Km)
On-shore 16 Inches 230 000 2 500 30 000 260 000
On-shore 30 Inches 820 000 3 500 40 000 860 000
On-shore 42 Inches 1 090 000 5 000 60 000 1 150 000
On-shore 48 Inches 1 140 000 5 000 60 000 1 200 000
Off-shore 8 Inches 940 000 18 000 200 000 1 150 000
Off-shore 16 Inches 1 230 000 18 000 200 000 1 430 000
Off-shore 24 Inches 1 550 000 18 000 200 000 1 750 000

2.4.4.3 INDIAN STORAGE COSTS

The Indian storage costs are shown in Table 2.22. As for the global estimates, the costs are given on a modular basis. The EOR costs are based on data from the EOR system at the Hazira Plant, with an estimated CO2 injection capacity of about 98 tonne/day/well for a 12 well module (Kumar et al. 2007). The O&M costs for the EOR system is assumed to be about $25000/well/year and this level is used for all Indian storage options. The EOR facility is planned to be in operation for about 30 years and during this period it is expected that 5 Mt oil will be recovered (Kumar et al., 2007). The cost of ECBM is not included in this study due to high uncertainty in its costs and application data in India (Singh 2007).

The Indian costs of depleted oil/gas reservoir and saline aquifer storage are based on global costs, since no reliable cost data are available. The Indian cost of depleted oil/gas reservoir storage is estimated to about 80 per cent of the global cost while the cost of saline aquifer storage is estimated to about 90 per cent of global cost.

Table 2.22 Indian storage costs

Storage type Injection wells per module CO2 injection per module (ton/day) Injection & storage capital costs ($/module) Injection & storage O&M costs ($/module/yr) NPV O&M costs ($/module) NPV TOTAL ($/module)
Enhanced Oil Recovery (EOR) 12 1 180 34 090 000 300 000 3 380 000 37 470 000
Depleted Oil/Gas Reservoir 10 2 500 4 350 000 300 000 3 380 000 7 730 000
Saline Aquifer 1 7 400 1 940 000 75 000 850 000 2 790 000

2.4.4.4 FUTURE COST CURVE ESTIMATES

The future cost development of CCS technologies is estimated in this section. The cost estimates are based on cost projections of other alternative energy technologies (Christensen et al. 2006 & IEA 2005). As shown in Figure 2.8 and 2.9, the future cost projections of alternative technologies vary significantly, and the expected cost reductions are strongly dependent on the maturity of the technology. While the costs of solar thermal and biomass technology are expected to decrease by 20 percent until 2030, the cost of solar PV is expected to decrease by 60 percent and fuel cell vehicles by as much as 80 per cent.

Figure 2.11 Future cost development of renewable energy technologies

Sources: Christensen et al., 2006 as derived and compiled from EWEA, 2003; Renewable Hydrogen Forum, 2003 (http://www.ases.org/hydrogen_forum03/Forum_report_c_9_24_03.pdf); http://europa.eu.int/comm/energy_transport/atlas/htmlu/rover31.html; and http://www.ucsusa.org/clean_energy/renewable_energy/page.cfm?pageID=100;

Figure 2.12 Future cost development of fuel cell vehicles, source IEA 2005

Because the three main modules of the CCS system are at different technology maturity levels, their cost projections vary greatly. The capture system is still at an early research, development and demonstration phase and hence major cost reductions are expected to be achievable in the future. The transport costs are not expected to decrease considerably since pipeline transport is used all over the world and is a mature technology. Even though geological storage of CO2 is only taking place at a very limited scale at this point, many of the technologies are similar to those currently used in the oil and gas industry. Therefore the storage cost decrease is not expected to be as high as for the capture technology. However since capture costs constitute the major cost components in the CCS chain, their cost reduction will greatly influence the overall cost curve of CCS technology. Figure 2.10 shows the expected future cost development for the capture, transport and storage systems.

As can be seen in Figure 2.9 large cost reductions can be expected for immature technologies such as fuel cell vehicles. Since capture technologies are still relatively immature, large cost reductions might be achieved in the future. Therefore the projection shown in Figure 2.10 is relatively conservative. The speed of their maturity would also depend upon the level of RD&D investments coming in this area, which in turn would depend upon the signals sent by global GHG mitigation regimes (IPCC 2007).

Figure 2.13 Future cost development of capture, transport & storage technologies. Sources: Expert judgement and based on Dooley et al., 2004; Friedmann et al., 2006; Riahi et al., 2004 ; Wildenborg et al., 2004; IEA, 2005; IPCC, 2007; and Christensen et al., 2006.

2.4.4.5 CONCLUSION

CCS has moved centre-stage in the last 5-6 years as a major alternative for large scale CO2 emission mitigation. However CCS is currently associated with around a 25% energy penalty due to the additional energy required for capture, transport and storage of CO2. This increases the costs of CCS. Capture cost reduction is the technological crux as it contributes around 60-80% to the CCS system chain costs, especially for penetrating the Indian markets (Shahi 2007). Many research initiatives are currently ongoing globally in this direction. Finding better and more energy efficient adsorbents is a focus area for research. Global research thrust is gradually moving to pre-combustion capture with potentially higher cost reduction possibilities.

This study has estimated the CO2 capture and storage costs for global and Indian conditions and made an approximation of future cost developments. Although much technical data exists on the global level, data for Indian conditions is still limited. Therefore the estimates made in this report should only be seen as an initial investigation of Indian CCS costs on which to build future studies.