dioxide capture and storage
3.7 LIFE CYCLE INVENTORIES USED IN THE INTEGRATED ASSESSMENT
3.7.1 GENERAL APPROACH
Plant capacity, lifetime and capacity factor
Table 3.13 shows the main characteristics of the power plants. A lifetime of 30 years was assumed for all cases. The power plant location is North America and North American hard coal (Illinois n6) is used for operation. Please note that the energy density and carbon content of fossil fuels can vary regionally. We have chosen to model the North American supply chain in the foreground in order to increase comparability between interregional results. The influence of varying energy and carbon content associated with the fossil fuel supply chain is discussed by Bouman et al. (2015). All values, including efficiencies reported in this section, are based on HHV. Plant infrastructure, land use and financing costs are included in the inventory and grouped over different sectors in the EXIOBASE.
Coal transport
For the EXPC, SCPC and IGCC cases it is assumed the same coal transport unit process. Coal is assumed to be transported by rail over a distance of 330 km from the excavation site to the power plant (NETL, 2010a).
Coal transport data include the transport infrastructure (trains) and the energy required for transport (NETL, 2010a) and are modelled using ecoinvent processes. The rail tracks are assumed to be constructed and are not included in the inventory. During coal extraction and transport, it is assumed that no coal is lost. The main components of the diesel powered trains are aluminium, chromium steel and steel, and the environmental emissions associated with transport are mainly due to the combustion of diesel.
Allocation of water use and process emissions
Total water demand can be split up in raw water withdrawal and internally recycled water. For simplicity, it is assumed here that all consumed water is eventually evaporated for cooling duties. In this report, total water withdrawal is modelled distinguishing between process water discharge and water consumption. For simplicity, it is assumed that water is obtained from an unspecified natural origin, even though NETL specifies the water sources for the power plant.
1 kWh Electricity Plant
infrastrucure
Plant operation Fuel
transport
CO2 capture compressionand Fuel
extraction
Additionnal unit processes for CCS CO2 pipeline CO2 well
infrastructureCCS
TABLE 3.13
General power plant characteristics
EXPC SCPC IGCC NGCC
Net power output without CCS (MW) 550 550 629 555
Net power output with CCS (MW) 550 a 550 a 497 474
Capacity factor 0.85 0.85 0.80 0.85
Net plant efficiency (with CCS) 36.8% (26.2%) 39.3% (28.4%) 42.1 % (31.2%) 50.2% (42.8%)
CO2 capture efficiency 90% 90% 90% 90%
Flue gas desulfurization (FGD) efficiency 98% 98%b Sulfur captured in Selexol process
Low sulfur fuel
Selective catalytic reduction (SCR) efficiency
86% 86% N/A 90%
Particulate matter (PM) removal efficiency
99.8% 99.8% Particulate removal by
cyclone and barrier filter
N/A
Hg reduction efficiency 90% 90% 95% N/A
Source: NETL, 2010b
a: the nominal net output for the EXPC and SCPC cases was maintained at 550 MW for the cases with CCS. This is done by increasing the boiler and turbine/generator sizes to account for a larger auxiliary load due to the carbon dioxide capture process. For the IGCC and NGCC cases, the plant size was kept constant, leading to a lower net power output. b: the efficiency of the FGD is the same in both cases, however in the CCS case the flow from the FGD unit passes through an extra unit in order to reduce degradation of the solvent in the capture unit.
As noted previously in this chapter, the addition of CCS increases the water and fuel use of the power plant significantly, and subsequently the related emissions. However, water use and emissions data is only available for total operation, i.e., for the plant operation and CO2 operation unit processes (shown in Figure 3.28 together).
The breakdown between plant operation and CO2 operation was not reported because additional use or emissions due to CCS do not necessarily occur in the CO2 capture section but also in the power island. In order to allocate water use and emissions between plant operation and CO2 capture the following approach was carried out: as data is available for both the power plants without and with CCS system, the ratio between the plant efficiency of the power plant without and with CCS is used to calculate the plant emissions of the plant operation unit process for the plant with CCS, based on the emissions of the plant without CCS. The difference in the totals will be the emissions associated with the CO2 operation process. Water use allocation is done in a similar way. This disaggregation could lead to slight misrepresentation of separate contributions of the foreground processes plant operation and CCS operation, but does not affect total emissions.
138
CHAPTER 3
FOSSIL FUELS AND CARBON DIOXIDE CAPTURE AND STORAGE
TABLE 3.14
Inventory for the subcritical pulverized coal (EXPC) plant operation unit process EXPC Plant
operation
without
CCS with CCS Unit Reference
INPUTS Activated carbon 6.50 ·10-5 kg/kWh (NETL, 2010b)
Ammonia 5.36 ·10-3 7.56 ·10-3 kg/kWh (NETL, 2010b)
Chemicalsa 4.10 ·10-4 7.10 ·10-4 US$/kWh (NETL, 2010b)
Coal transport 3.61 ·10-1 5.07 ·10-1 kg/kWh (NETL, 2010b)
Discharge process water 5.02 ·10-1 1.08 ·100 kg/kWh (NETL, 2010b)
Limestone 3.58 ·10-2 5.16 ·10-2 kg/kWh (NETL, 2010b)
Monoethanolamine 2.33 ·10-3 kg/kWh (Veltman et al., 2010)
Sodium hydroxide 5.42 ·10-4 kg/kWh (NETL, 2010b)
Sulfuric acid 5.18 ·10-4 kg/kWh (NETL, 2010b)
Waterb 1.93 ·10-3 3.56 ·10-3 m3/kWh (NETL, 2010b)
OUTPUTS Ammonia 2.00 ·10 -7 2.90 ·10-7 kg/kWh NETL, 2010e
Carbon dioxide 8.56 ·10-1 1.16 ·10-1 kg/kWh (NETL, 2010b)
Ash disposal 3.50 ·10-2 4.91 ·10-2 kg/kWh (NETL, 2010b)
Disposal of hazardous waste 3.47 ·10-3 kg/kWh (Singh, 2011b)
Carbon monoxide 1.00 ·10-4 1.40 ·10-4 kg/kWh (NETL, 2010c)
Lead 5.90 ·10-9 8.40 ·10-9 kg/kWh (NETL, 2010c)
Mercury 4.54 ·10-9 5.53 ·10-9 kg/kWh (NETL, 2010c)
Methane 1.10 ·10-5 1.50 ·10-5 kg/kWh (NETL, 2010c)
Monoethanolamine 6.59 ·10-5 kg/kWh (Veltman, 2010)
Nitrogen oxide 2.78 ·10-4 3.39 ·10-4 kg/kWh (NETL, 2010e)
Nitrous oxide 1.60 ·10-5 2.30 ·10-5 kg/kWh (NETL, 2010e)
Particulates 5.20 ·10-5 6.30 ·10-5 kg/kWh (NETL, 2010e)
Sulfur dioxide 3.41 ·10-4 7.60 ·10-6 kg/kWh (NETL, 2010e)
Sulfur hexafluoride 2.60 ·10-10 2.60 ·10-10 kg/kWh (NETL, 2010e)
VOC 1.20 ·10-5 1.70 ·10-5 kg/kWh (NETL, 2010e)
Waste heat 6.18 ·100 1.02 ·101 MJ/kWh
-Water-to-air 1.93 ·100 3.56 ·100 kg/kWh (NETL, 2010b)
(Bouman et al., 2015)
a: The chemicals listed here consist of a non-specified mix of makeup and waste/water treatment chemicals and catalyst as accounted for in the operating costs of the plants (NETL, 2010b). The process ‘manufacture of chemicals and chemical products’ from the EXIOPOL background is used as a proxy.
b: This is water used directly from natural resources, and corresponds with the water consumption. An equivalent amount of water is emitted to air in the outputs (please note the difference in unit). Process water discharge (to river) is separately modelled using an ecoinvent process. Together, these two processes form the total raw water withdrawal.
TABLE 3.15
Inventory for the supercritical pulverized coal (SCPC) plant operation unit process SCPC Plant
operation
Without
CCS With CCS Unit Reference
INPUTS Activated carbon 5.98 ·10-5 kg/kWh (NETL, 2010b)
Ammonia 5.03 ·10-3 7.00 ·10-3 kg/kWh (NETL, 2010b)
Chemicals 3.90 ·10-4 6.50 ·10-4 US$/kWh (NETL, 2010b)
Coal transport 3.38 ·10-1 4.68 ·10-1 kg/kWh (NETL, 2010b)
Discharge process water 4.48 ·10-1 9.70 ·10-1 kg/kWh (NETL, 2010b)
Limestone 3.35 ·10-2 4.72 ·10-2 kg/kWh (NET,L 2010b)
Monoethanolamine 2.15 ·10-3 kg/kWh (Veltman, 2010)
Sodium hydroxide 9.98 ·10-4 kg/kWh (NETL, 2010b)
Sulfuric acid 4.76 ·10-4 kg/kWh (NETL, 2010b)
Watera 1.75 ·10-3 3.20 ·10-3 m3/kWh (NETL, 2010b)
OUTPUTS Ammonia 2.56 ·10-6 1.95 ·10-4 kg/kWh NETL, 2010a; Koornneef, 2008
Ash disposal 3.27 ·10-2 4.53 ·10-2 kg/kWh (NETL, 2010b)
Disposal of hazardous waste 3.20 ·10-3 kg/kWh (Singh, 2011b)
Carbon dioxide 8.02 ·10-1 1.11 ·10-1 kg/kWh (NETL, 2010e)
Carbon monoxide 3.18 ·10-7 4.06 ·10-7 kg/kWh (NETL, 2010a)
Lead 4.79 ·10-8 4.79 ·10-8 kg/kWh (NETL, 2010a)
Mercury 4.27 ·10-9 5.16 ·10-9 kg/kWh (NETL, 2010b)
Methane 8.72 ·10-9 7.59 ·10-7 kg/kWh (NETL, 2010a)
Monoethanolamine 6.08 ·10-5 kg/kWh (Veltman, 2010)
Nitrogen oxide 2.61 ·10-4 3.16 ·10-4 kg/kWh (NETL, 2010b)
Nitrous oxide 2.43 ·10-9 3.66 ·10-9 kg/kWh (NETL, 2010a)
Particulates 4.90 ·10-5 5.90 ·10-5 kg/kWh (NETL, 2010b)
Sulfur dioxide 3.20 ·10-4 7.00 ·10-6 kg/kWh (NETL, 2010b)
Sulfur hexafluoride 3.53 ·10-10 3.53 ·10-10 kg/kWh (NETL, 2010a)
VOC 2.08 ·10-8 2.13 ·10-8 kg/kWh (NETL, 2010a)
Waste heat 5.56 ·100 9.08 ·100 MJ/kWh
-Water-to-air 1.75 ·100 3.20 ·100 kg/kWh (NETL, 2010b)
(Bouman et al., 2015)
a: This is water used directly from natural resources, and corresponds with the water consumption. An equivalent amount of water is emitted to air in the outputs (please note the difference in unit). Process water discharge (to river) is separately modelled using an ecoinvent process. Together, these two processes form the total raw water withdrawal.
140
CHAPTER 3
FOSSIL FUELS AND CARBON DIOXIDE CAPTURE AND STORAGE