Decarbonisation Technology August 2022 issue

Carbon utilisation technologies KBC performed a techno-economic evaluation of the nine CU technologies listed in Table 1 . Table 1 also includes the feeds, other than CO₂, and the operating temperature of the CU paths. For most of the feed and product pricing, KBC relied on third-party market intelligence from Argus Media. The Fischer-Tropsch (FT) and Oxo synthesis configurations considered in the referenced articles consume CO rather than CO₂. Therefore, a reverse water gas shift (RWGS) step is included upstream to convert the CO 2 into CO. The RWGS step includes CO₂ capture to recycle the unconverted CO₂. The methanation process considered uses CO₂, not syngas (CO). However, due to low CO₂ conversion per reactor pass, a CO₂ capture/ recycle step is required, too. Four of the nine CU technologies were simulated partially or entirely using KBC’s Petro-SIM software. Figure 2 shows the Petro- SIM simulation model of the Oxo process. The technologies were simulated when a process flow diagram was missing, or the assumed process heat integration was incomplete or unrealistic. Operating cost Many CU technologies require significant amounts of hydrogen. In the upcoming Part 2 article, we will demonstrate that the hydrogen used for this study should have a very low carbon intensity. The cost of the green hydrogen used and the revenue generated from utilising CO₂ will significantly impact CU technology economics. Two price scenarios were considered (see Table 2 ). The 2030 scenario employs a high price of green hydrogen and a low price of CO₂ . The 2050 scenario adopts a much lower price of green hydrogen and a much higher price of carbon emissions. The price sets correspond with possible carbon and hydrogen pricing in 2030 and 2050. These are semi-arbitrary and based on price scenario trends, not on an in-depth analysis of current and upcoming legislation, carbon markets, and green hydrogen project pipeline. The primary purpose is to demonstrate the sensitivity of the CU economics with carbon and hydrogen pricing. The 2030 and 2050 price estimates have been established with a more rigorous market analysis

2030 Scenario 2050 Scenario

Green hydrogen

USD 4000 /t

USD 1500 /t USD 200 /t

CO 2 utilisation revenue

USD 50 /t

by Argus Media for the other feeds (propylene, PO) and the CU products. Yokogawa and KBC established price estimates for the carbonation feeds and PPC products. The estimates are based on price data before third-quarter 2021 inflation rates hit, when natural gas prices wavered around USD 40/MWh rather than surpassing USD 100/MWh. Figures 3 and 4 show the operating cost/ revenue breakdown for the different CU technologies under the two H₂/CO₂ pricing scenarios. Hydrogen, other utilities (electricity, fuel, steam), and fixed operating cost are shown on the debit side of the graph, below the zero axis. Revenue streams generated by the product/ feed differential and CO₂ utilisation are shown as positive bars in the chart. The resulting operating cost/revenue balance (EBITDA) is plotted in Figures 5 and 6 . The charts demonstrate that hydrogen is the key driver of operational costs for many of these technologies. These technologies will only become economically profitable if green hydrogen costs drop significantly, although product pricing can play a decisive role, too. The following sections discuss the operating cost Table 2 Green hydrogen and CO₂ price scenarios based on pre-inflation 2021 prices

H/CO price: 4000/50 $/t








Oxo (butanal)



Feed/product value addition Electricity/fuel/steam

H cost

CO revenue

Fixed Opex

Figure 3 Operating cost/revenue breakdown - 2030 scenario


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