Specification of future CCS technology configurations

Figure 4.17 illustrates the modeling approach for fossil power generation chains with CCS, as modeled in this study. The CCS part includes the separation of CO2 at the power plant, its transport to the reservoir where it is injected and finally stored. It also includes the complete infrastructure for transport and storage, i.e pipelines, compressors, and injection wells.

Coal mining &

Figure 4.17 Scheme of the hard coal chain for power generation including Carbon Capture and Storage.

4.3.4.1 Capture (including compression)³⁴ at power plant

The following power plant reference technologies are modeled in this study, chosen as the most likely ones to be implemented in large scale within the next 40 years:

- Post-combustion, for the technologies supercritical PC (hard coal and lignite) and NGCC; using amine solvent separation;

- Pre-combustion, for IGCC technology (hard coal and lignite); using physical/chemical absorption separation;

- Oxyfuel combustion of coal (hard coal and lignite).

Among the three different hard coal power plants modeled without CO2 capture (350 MWel, 600 MWel, 800 MWel), the 600 MWel unit was chosen as the one to be equipped with CO2

capture for post- and oxyfuel combustion systems. The key factors for LCI of the power plant operation with CO₂ capture are the power plant efficiency with and without capture, CO₂ capture rate, and material use for operation (mainly chemicals for CO2 separation). The electricity used for CO2 compression at the power plant is treated as auxiliary uses and consequently subtracted from the gross electricity generated. Therefore, the LCA boundary of the operation of power plants with CCS includes the separation and compression of the CO2. This means that the energy requirement for separation and compression of CO2 at the power plant is taken into account by a reduction of the power plant net efficiencies, mainly based on (Hendriks 2007). Efficiencies of CO2

separation differ for the three separation technologies considered – average values were extrapolated for the different time horizons and scenarios based on different sources (Hendriks 2007, Rubin et al. 2007, Fischedick et al. 2007). Table 4.46 summarizes the assumptions concerning reduction of power plant net efficiency and

34 Unless otherwise explicitly noticed, hereinafter the term capture is always meant to include compression.

CO2 capture efficiencies for the reference systems and the three different scenarios for the future time horizons (2025 and 2050). Net efficiencies of hard coal and lignite PC power plants are assumed to correspond in 2025 and 2050.

For what concerns the chemicals used for CO2 separation from the exhaust in post-combustion processes, using an amine-based solvent, the upper range of the values reported in (IPCC 2005) for amine (modeled with mono-ethanolamine as the only appropriate substance available in the background LCI database), NaOH, and active carbon (modeled with charcoal) have been assumed in the study. Additionally, the difference between the total chemical requirements for separation reported in (Rubin et al. 2007) and the total materials (2.76 kg/kWh) from (IPCC 2005) has been modeled with generic organic chemicals (again the only appropriate substance available in the background LCI database). These values have not been changed for the different scenarios, because no information was available on process modifications in the future. This aspect would deserve a follow-up LCA modeling activity. Furthermore, in this study material needs for oxyfuel combustion could not be modeled, but only the energy uses for O2 separation.

Concerning NOx and SOx emissions from PC plants, reductions along (Rubin et al.

2007, Andersson & Johnsson 2006) have been considered, but adjusting SO2

emission to 0.1 g/kWh thus assuming scrubber efficiency of about 99%, and using bound N content in the hard coal for oxyfuel combustion exhaust (giving <0.2 g/kWh).

The infrastructure of the power plants (construction and dismantling) with CO2 capture has been modeled the same way as for the units without CO₂ capture as first approximation. This simplification can be justified by the fact that although the infrastructure requirements for the capture plant are considerable, the construction materials do not contribute substantially to cumulative results (see chapter 5).

Table 4.46 Net efficiencies assumed for natural gas and coal power plants with and without CCS for the range of scenarios in year 2025 and 2050 defined in this study.

* Sc. = Technology scenario: Pe = pessimistic; RO = realistic-optimistic; VO = very optimistic.

** Efficiency penalty = reduction in power plant net efficiency due to electricity demand for CO2 capture and compression.

4.3.4.2 Transport of CO2

The following reference technology is modeled in this study, chosen as the most likely to be implemented in large scale within the next 40 years in Europe:

- Transport of CO2 by onshore pipeline, 200 km and 400 km.

Transport by ship is not modeled because of disadvantageous economics for average distances and capacities likely to occur in Europe until 2050.

The key factors for LCI are the pipeline capacity, the pressure, and the average distance for CO₂ transmission to storage sites in Europe (i.e. whether intermediate pumping stations are necessary or not). The modeling of the CO₂ transport in supercritical state has been conducted on the basis of an engineering bottom-up modeling approach (Wildbolz 2007, Doka 2007).

The transport is assumed to occur by pipeline with mass flow of 250 kg/s, which would correspond to roughly three hard coal power plants with carbon capture of the 500 MW class, as modeled in this study. Two transport distances have been considered, 200 km and 400 km, the first without intermediate recompression, the second with one recompression (approximately 30 bar) unit after the first 200 km as illustrated in Figure 4.18. The UCTE electricity mix (at medium voltage level) is used for recompression of CO2

(0.0389 kWh/tkm). The modeling of the pipeline infrastructure is extrapolated based on (Faist Emmenegger et al. 2004), considering the specific mass flow and pressure of supercritical CO2. Leaking of CO2 in the order of 0.26 g/tkm is taken into account.

H

_injection

H

Pump

200 km

200 km

Recompression System Boundary Transport

H

recompression

H

_injection

H

Pump

200 km

200 km

Recompression System Boundary Transport

H

recompression

Figure 4.18 Schematic of the recompression for the transport process (Wildbolz 2007).

4.3.4.3 Storage of CO2

Two different generic reference storage facilities are considered, being the options most likely to be realized in Europe until 2050:

- A saline aquifer at a depth of 800 m (for storage of CO2 separated at hard coal and lignite power plants³⁵);

35 It is assumed that the most economic and realistically implemented option for storage of CO2 separated at natural gas power plants will be the “re-pumping” into exploited gasfields, relying on already used routes of gas pipelines and infrastructure relatively easy to be installed at already developed sites for natural gas production.

Additionally the CO2 to be injected can be used for increasing the production volumes of the gas reservoirs.

- A depleted gas reservoir at a depth of 2500 m (for storage of CO2 separated at hard coal, lignite and natural gas power plants).

Capacity for un-mineable coal beds is of lesser importance for Europe (see Table 4.45) but it could still be an option for economical reasons, especially at local scale.

The key factors for LCI are the average depth for drilling, the power required for injection of CO₂ which in turn depends on the depth of the reservoir, and potential long-term leakages. It is assumed that the reservoirs are 100% imperviously, since this leakage rate of zero, guaranteed by tests and monitoring, can be assumed to be a prerequisite for any legal framework still to be established for storage of CO₂. The modeling of the CO₂ storage has been conducted on the basis of an engineering bottom-up modeling approach (Wildbolz 2007, Doka 2007). The number of wells required for a storage project will depend on various factors, like total injection rate, permeability and thickness of the geological formation, maximum injection pressure and availability of land-surface area for the injection wells (IPCC 2005). Taking into account the given boundaries – a mass flow of CO2 of 250 kg/s correspoding to 7.9 Mt(CO₂) per year this results in the requirement of two injection wells for the modelled case (Wildbolz 2007). The hydrostatic pressure at the two reservoirs is assumed to be 78.4 bar and 171.5 bar (for the aquifer and the depleted gasfield, respectively). The required overpressure for the CO₂ injection of 30 bar results in an associated electricity demand of 0.0371 kWh/kg(CO₂) for the aquifer at 800 m depth and 0.1127 kWh/kg(CO₂) for the depleted gasfield at 2500 m depth (Wildbolz 2007, Doka 2007). Figure 4.19 illustrates the various pressure levels occuring within CO2 transport and storage.

pressure reservoir pressure

overpressure (30 bar) injection pressure

²p for injection

pipeline

pump

reservoir

Figure 4.19 Illustration of different pressure levels for transport, injection and storage of CO2 (Doka 2007).

Potential safety and risk issues associated with CCS technologies like accidents during CO₂ transport or injection, risks for humans and the environment due to spontaneous or gradual leakage of the reservoirs (IPCC 2005, UBA 2006b, Fischedick et al. 2007, Radgen et al.

2005) are not taken into account in this LCA study. Considering such issues would require alternative assessment methods.

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