• Energy Research

This study developed an integrated method to identify deployment pathways for greenhouse gas emissions reductions in an industrial plant. The approach distinguishes itself by assessing the techno-economic performance of combinations of mitigation options at the level of core processes of an industrial plant. Thus, synergies between mitigation options like economies of scale and negative interactions, such as overlap in emission reduction potential, are incorporated, resulting in more realistic insights into costs and associated risks. The method was successfully applied to a large petroleum refinery (similar to 4.1 MtCO(2)/y) in northwest Europe. The studied mitigation routes are: energy efficiency measures, carbon capture and storage, fast pyrolysis of woody biomass to produce infrastructure-ready transportation fuels, and gasification of torrefied wood pellets to produce electricity, hydrogen and/or Fischer-Tropsch fuels. Four deployment pathways were examined, all starting with energy efficiency measures and followed by (1) oxyfuel combustion capture, (2) post-combustion capture, (3) biomass gasification, or (4) biomass gasification with carbon capture and storage. Pathway 4 is most cost-effective under medium assumptions, regardless of the emissions reduction target, and allows for deep emissions reductions (6.3 MtCO(2)-eq/y; 154% reduction compared to the 2012 base case). For a 75% emissions reduction target, the average avoidance cost of pathway 4 is around -25 is an element of(2012)/tCO(2)-eq. In comparison, the second most cost-effective pathway (1) was evaluated at average avoidance cost of -5 is an element of(2012)/tCO(2).eq. However, the ranking of the pathways in terms of avoidance cost depends heavily on future energy prices.

This study developed a method to assess the techno-economic performance and spatial footprint of CO2 capture infrastructure configurations in industrial zones. The method has been successfully applied to a cluster of sixteen industrial plants in the Dutch industrial Botlek area (7.1 MtCO2/y) for 2020–2030. The configurations differ inter alia regarding capture technology (post-, pre-, oxyfuel combustion) and location of capture components (centralized vs. plant site). Results indicate that oxyfuel combustion with centralized oxygen production and decentralized CO2 compression is the most cost effective and realistic configuration when applying CO2 capture to all industrial plants (61€/tCO2; 5.8 MtCO2/y avoided), mainly due to relatively low energy costs compared to post- and pre-combustion. However, oxyfuel combustion at plant level is economically preferable when capturing CO2 from only the three largest industrial plants. For post-combustion, a separated absorber-stripper configuration (73€/tCO2; 7.1 MtCO2/y avoided) is preferable from a cost perspective, due to economic scale effects of capture equipment. The optimal pre-combustion configuration shows a slightly less favorable performance (81€/tCO2; 4.4 MtCO2/y avoided). Whereas many industrial plants have insufficient space available for capture equipment, centralized/hybrid configurations show no insurmountable space issues. The deployment of the most favorable configurations is addressed in Part B.

The costs of intermittent renewable energy systems (IRES) and power storage technologies are compared on a level playing field to those of natural gas combined cycle power plants with CO2 capture and storage (NGCC-CCS). To account for technological progress over time, an "experience curve" approach is used to project future levelised costs of electricity (LCOE) based on technology progress ratios and deployment rates in worldwide energy scenarios, together with European energy and technology cost estimates. Under base case assumptions, the LCOE in 2040 for baseload NGCC-CCS plants is estimated to be 71 €2012/MWh. In contrast, the LCOE for electricity generated intermittently from IRES is estimated at 68, 82, and 104 €2012/MWh for concentrated solar power, offshore wind, and photovoltaic systems, respectively. Considering uncertainties in costs, deployment rates and geographical conditions, LCOE ranges for IRES are wider than for NGCC-CCS. We also assess energy storage technologies versus NGCC-CCS as backup options for IRES. Here, for base case assumptions NGCC-CCS with an LCOE of 90 €2012/MWh in 2040 is more costly than pumped hydro storage (PHS) or compressed air and energy storage (CAES) with LCOEs of 57 and 88 €2012/MWh, respectively. Projected costs for battery backup are 78, 149, and 321 €2012/MWh for Zn-Br, ZEBRA, and Li-ion battery systems, respectively. Finally, we compare four stylised low-carbon systems on a common basis (including all ancillary costs for IRES). In the 2040 base case, the system employing only NGCC-CCS has the lowest LCOE and lowest cost of CO2 avoided with CO2 emissions of 45 kg/MWh. A zero CO2 emission system with IRES plus PHS as backup is 42% more expensive in terms of LCOE, and 13% more costly than a system with IRES plus NGCC-CCS backup with emissions of 23 kg CO2/MWh. Sensitivity results and study limitations are fully discussed within the paper.

Abstract The application of CO 2 capture and storage at industrial scales requires the development of a transport infrastructure which is suitable to transport millions of tons of CO 2 per year. Important offshore storage sites could be served by pipelines or vessels. The discrimination between these options is a crucial scientific task for the assessment of the potential of CCS and the design of a CO 2 transport infrastructure. In this research the analysis of vessel transport cost is refined by the optimization of vessel size in a fleet scheduling context. A cost model for a point-to-point CO 2 transport by vessel that includes liquefaction, intermediate storage, loading, vessel/fleet construction and storage has been derived from a comprehensive literature survey and has been optimized for vessel capacity. The cost savings potential of the optimization can reach up to 40%. A reliable cost estimation should therefore carefully account for the dimensioning of the vessels. The optimized vessel transport option was then compared to pipeline transport connections to offshore storage sites. In a compact graphical presentation it is shown that vessel transport can be advantageous compared to pipeline transport for long distances and small volumes. The breakeven distance of vessel transport becomes up to 40% greater due to optimized vessel size. The cost models were then applied to find the cost effective transport mode for a connection of the West Mediterranean region 1 (i.e. Spain, Portugal, and Morocco) to a European CO 2 transport infrastructure including the North Sea. Transport of CO 2 by vessel turns out to be cost-effective and could be profitable if CO 2 is used for Enhanced Oil Recovery (EOR).