Electrons to High-Value Chemicals

Abstract

The market for light olefins—ethylene and propylene—is forecast to nearly quadruple between 2025 and 2050, yet remains heavily dependent on fossil feedstocks. This work presents an alternative route to synthesis polymer-grade light olefins, based on the gasification of commercial bio-oil and the use of electrolytic hydrogen within the Dutch electricity context. The methodology comprises: (1) TOPSIS-based selection among ten bio-oil alternatives against twelve criteria spanning physical, chemical, and economic aspects; (2) synthesis-route selection on the basis of commercial maturity; (3) flowsheet development in Aspen Plus™ V14 under primarily financial-benefit-driven optimisation; (4) a pinch-analysis heat-integration strategy to minimise the total annualised capital and utility cost; (5) techno-economic assessment using selected key performance indicators; and (6) optimisation of hydrogen generation and storage in response to the dynamic Dutch electricity price. The biomass-conversion literature has suggested bio-oil as an attractive intermediate feedstock for higher-value product synthesis; process-systems modelling of light-olefin production from non-fossil resources, however, has not yet addressed commercially produced bio-oil. This work addresses that gap.

The TOPSIS analysis identifies the commercial bio-oil produced at the Aracruz plant in Brazil as the most suitable feedstock, with a relative closeness coefficient of 0.828. The conceptual plant gasifies 100 000 t/yr of this bio-oil under autothermal conditions; the syngas stoichiometric number is then adjusted with electrolytic hydrogen from a twelve-stack, 58 MW alkaline water electrolyser to synthesise 94 181 t/yr of grade-AA methanol, which is converted via the DMTO-III process to 20 387 t/yr of polymer-grade ethylene and 14 581 t/yr of polymer-grade propylene. The plant adopts two process features not yet found in commercial practice: the use of electrolytic hydrogen as a stripping agent to remove dissolved CO₂ from the raw methanol, and membrane separators for the C₂ and C₃ olefin–paraffin separations as an alternative to the incumbent cryogenic separation. Heat integration lowers the annual utility cost from almost €6 million to −€0.78 million.

The principal performance indicators are: a light-olefin mass yield of 35% relative to the bio-oil feed; a carbon conversion of 81%; a conversion of 35% of the hydrogen input into light olefins; and energy and exergy efficiencies of 47.1% and 49%, respectively. The plant requires €474.6 million in total capital investment and €125.7 million in annual operating cost, while its annual revenue covers only 44% of the annual cost, corresponding to an annual loss of €70.3 million. This loss has two distinct origins—upstream, the high cost of bio-oil and electricity; and downstream, the low revenue from ethylene and propylene sales.

Adopting an IRR of 10% as the threshold for financial feasibility, a sensitivity analysis shows that reducing the bio-oil and electricity prices simultaneously to zero—i.e. virtually free bio-oil and electricity—yields an IRR of only 7.59%, which renders the plant financially unattractive. On the product side, the ethylene and propylene prices would need to rise by 250% and 500%, respectively, to reach financial feasibility, implying a reliance on the price premium for non-fossil-derived products. Finally, equipping the plant with hydrogen storage to limit its exposure to high electricity prices, and optimising accordingly, sets the electrolyser and storage capacities to 62.6 MW and 3393 kg; this configuration nonetheless lowers the annual electricity cost by only 7%, insufficient to render the plant financially viable.