Defossilizing feedstocks of industrial clusters has increasingly attracted attention due to potential impacts on climate change mitigation targets. However, the transition from fossil-based feedstocks to alternative carbon sources (ACS) presents both environmental and economic challenges in terms of performance and feasibility. One issue is the large uncertainties regarding the techno-economic feasibility in terms of investment decisions, which has been barely studied in the literature at cluster level. This study considers market price fluctuations of raw materials, products and energy over time to evaluate the profit and risk associated with individual plants for decision-making purposes. By adopting Modern Portfolio Theory (MPT), a portfolio optimization problem is defined to provide a risk-return-based guidance framework for transitioning to alternative carbon feedstocks. The proposed optimization model obtains investment portfolios and corresponding production capacity distributions based on the optimal constituents among fossil-based and ACS-based plants. The Port of Rotterdam, the Netherlands, is considered as a case study to assess the defossilization of feedstocks at the cluster level. The results show that integrating ACS-based plants into the cluster requires substantial capital investment, and reduces the Return on Investment (RoI) relative to the associated risk, making full defossilization economically challenging to achieve. However, applying a price-allocation method for re-costing ACS-based (by-)products considering governmental financial supports, the transition to alternative carbon sources can become attractive to investors at specific production capacities, as identified through optimal risk–return portfolios.

Ethylene production processes using alternative carbon sources like biomass or CO₂ could have great potential for the olefins industry. Comparing the benefits and pitfalls of different process routes is challenging due to the vastly different feedstocks and key conversion technologies involved. Here, we performed an ex-ante techno-economic and environmental assessment to explore potential trade-offs of three low technology readiness level ethylene production processes. The three routes were: 1) biobased syngas fermentation to ethanol followed by ethanol dehydration, 2) direct electrochemical conversion of CO₂, and 3) indirect CO₂ and H₂O electrolysis to form syngas followed by a Fischer-Tropsch step. This study found three main takeaways. Firstly, the biobased route significantly outperforms the direct and indirect routes in terms of techno-economic and carbon footprint performance. Secondly, the electrolyzer unit is the main factor limiting the techno-economic performance of the direct and indirect cases, reemphasizing the need for continued technological advancements and cost reductions by researchers in this domain. Finally, the indirect plant design, incorporating two electrolyzers and a Fischer-Tropsch step, is not techno-economically feasible for ethylene production, underscoring the need for further research on Fischer-Tropsch plant designs to advance the replacement of traditional fossil-based refineries.

Converting biogenic CO₂ into synthetic sustainable aviation fuel (e-SAF) requires significant amounts of renewable energy, and alignment between system elements and sizes. However, the optimal scale and configuration of CO₂ electrolysis remains unresolved. This study examines the economics of RFNBO-compliant e-SAF production from CO₂ electrolysis via Fischer–Tropsch synthesis in centralized and decentralized configurations in the Netherlands. A two-stage optimization framework sized the renewable generation, storage, and use of grid electricity for electrolysis plants (9–900 MW). The model projects scenarios from 2025 to 2050, including expected cost and efficiency improvements. The lowest near-term (2025) levelized cost of e-SAF (around 5230 EUR₂₀₁₉/tonne) is achieved for a centralized 90 MW electrolysis plant powered by onshore wind and photovoltaics. A 23 MW decentralized system yields comparable costs. While conversion investment costs are higher at smaller scales, they are counterbalanced by avoided grid fees, higher allowed grid mix electricity consumption, and lower CO₂ supply cost. By 2050, decentral e-SAF production costs are projected at 2750 EUR₂₀₁₉/tonne (a 35–70% premium over current SAF prices). These systems provide a near-term route for demonstration projects by co-locating renewable energy, e-SAF production, and regional airports. However, two fundamental caveats remain. First, the cost of CO₂ electrolysis–based fuels is incompatible with bulk fuel margins. Second, the limited production volumes from a decentralized configuration are misaligned with the high demand of the aviation sector. Therefore, CO₂ electrolysis appears best deployed in a high-value niche product or where high-quality renewable resources geographically overlap with distributed biogenic CO₂ streams.

The petrochemical industry must transition its material and energy sources from fossil-based sources to more sustainable alternatives. While decarbonizing the energy source is challenging, defossilization of the material feedstock is significantly more difficult. In this work, we present a superstructure-based, multi-period, multi-objective optimization framework to address this problem. This framework focuses on minimizing the use of fossil carbon and modifications to petrochemical clusters while explicitly controlling the order of appearance of new processes. The combination of process options becoming available to the solution space over time and the cluster being locked in a path-dependent transition allows the framework to capture realistic transformation pathways. We demonstrate the framework with a small-scale case study of 10 fossil-based and 6 alternative processes. The results demonstrate the ability of the framework to select optimal defossillization pathways while simultaneously considering the impacts on mass and energy flows across the cluster.

Industrial greenhouse gas emissions, primarily carbon dioxide, constitute about one-third of global emissions, and 75% are caused by the generation of heat from fossil fuels. Therefore, a key decarbonisation strategy is electrifying heat generation using renewable sources and power-to-heat technologies. This study explores the impact of the energy price on the optimal choice and sizing of power-to-heat and storage technologies in existing energy-intensive industries with a variable heat demand. A mixed integer linear program is used to determine the technology portfolio and size of the equipment that leads to the lowest total annual cost of the utility system while ensuring that heat demand is always fulfilled. The results of a case study in the Netherlands show that adding power-to-heat and storage technologies to a fossil fuel-based combined heat and power plant is economically viable under all explored scenarios. The mean and the variance of electricity prices significantly influence the sizing of heat pumps, electric boilers, and thermal energy storage. High and stable electricity prices lead to larger heat pump capacities compared to scenarios with low and more variable electricity prices. Electric boilers are primarily sized based on the variance of electricity prices and the capacity of thermal energy storage, which plays a crucial role in managing electricity price fluctuations. The study emphasises the potential for cost-effective electrification and provides valuable insights for reducing industrial CO₂ emissions.

Alternative carbon sources (ACS) are increasingly considered necessary for the defossilisation of fossil-based chemicals. However, the potential and impacts of integrating ACS-based processes in existing petrochemical clusters are often overlooked. This paper aims to systematically analyse key techno-economic and environmental indicators associated with producing bio-based isobutene as an option to defossilise the production of methyl-tert-butyl-ether (MTBE) in the Port of Rotterdam, the Netherlands. The assessment is conducted at process and cluster levels. For this, the bio-isobutene (bio-IBN) process (358 kt/y of product), along with the existing fossil-based processes involved in MTBE production (i.e. the MTBE cluster), were modelled in Aspen Plus v12. The results show that under current conditions, although bio-IBN production could defossilise the MTBE cluster by c.a. 80 %, it is not cost-competitive compared to the current fossil-based process. Furthermore, deploying the bio-IBN process would significantly change the structure of the existing MTBE cluster, increasing by a factor of two or larger electricity, cooling water and bare land requirements. These requirements would affect the economic and environmental performance of the full cluster. The results emphasise the critical role of strategic change of new processes within existing petrochemical clusters.

The electrification of utility systems in energy-intensive plants is a promising measure for decarbonising the chemical industry in the short term. However, with the increasing deployment of renewable energy sources, the variability of electricity prices will become a challenge for plants with continuous and constant energy demand. It is thus uncertain whether electrification can become financially viable. This work models the electrification of utility systems in combination with storage technologies for five chemical plants with existing fossil fuel-based utility generation and uses historical data as energy price scenarios. The results show that partial electrification is cost-effective when using electricity is cheaper than natural gas for more than 600 h. Regarding the portfolio of technologies, electric boilers are installed first, followed by thermal energy storage and batteries. Hydrogen is not cost-effective in any of the scenarios explored. This is independent of the type of plant, the available grid connection capacity, and the minimal load of existing fossil fuel-based utility generation. This work thus highlights the potential for electrifying industrial utility systems and the role that electric boilers and energy storage units can play in electrification.

The rising pressure to defossilize the chemical industry has driven research toward producing chemicals that use alternative carbon sources (ACS). However, the challenges and impacts of replacing already implemented processes and symbiotic relationships remain largely underexplored. This paper systematically assesses the impacts of defossilizing existing processes, both individually and simultaneously, in a propylene cluster in the Port of Rotterdam, the Netherlands. Nine fossil-based processes and three ACS-based processes (i.e., CO₂-based polyol, biopropylene glycol (bio-PG), and biomethyl-tert-butyl-ether (bio-MTBE)) were included in the assessment. Integrating a single ACS-based process enlarges the propylene cluster and results in an excess of upstream chemicals that are no longer required by the ACS processes. Still, relatively simple technologies can reduce total energy and water use, resulting in lower direct CO₂emissions and water consumption of the cluster. Deploying multiple processes in parallel can drive the full defossilization of the cluster, but it requires a complete overhaul. The results illustrate the extent to which combining ACS-based processes could change the layout of an existing petrochemical cluster, affecting its performance. The paper stresses the importance of assessing such deployments, considering the existing conditions in industrial clusters.

Syngas production via high-temperature co-electrolysis of CO₂ (CO₂E) shows great potential to reduce the reliance on fossil fuels within the chemical industry. This paper presents an optimization model (MILP) to investigate syngas production from CO₂ in the European chemical sector. The model assesses the economic performance of CO₂E in prospective supply chains and explores alternative supply chain configurations under different syngas market sizes. The results reveal that the optimal placement of the CO₂ electrolysis plant in the supply chain is co-located or decentralized at the product location. This configuration reduces the need for syngas transportation by delivering CO₂ to the demand site, which is typically more cost-effective. At a syngas market fulfillment of 2 %, the lowest levelized cost of syngas is achieved at 673 EUR₂₀₁₈/tonne, with electrolysis plants averaging a production capacity of 100 ktonne syngas/year. This levelized cost is between 1.5 and 4 times higher than the fossil-based reference.

Combining intermittent renewable electricity (IRE) with carbon capture and utilisation is urgently needed in the chemical sector. In this context, microbial electrosynthesis (MES) has gained attention. It can electrochemically produce hexanoic acid, a value-added chemical, from CO₂. However, there is a lack of understanding regarding how the intermittency of renewable electricity could impact the design of a MES plant. We studied this using Aspen Plus models. A MES plant that was powered by constant grid electricity could operate from 100% down to 70% of its nominal capacity, at which point the heat exchangers and the internal geometrical design of the distillation towers became bottlenecks. The levelised production cost of hexanoic acid (LPC_C6A) was estimated at 4.0 €/kg. Switching to IRE supply increased LPC_C6A to 5.3 €/kg (for wind electricity) and 4.7 €/kg (for hybrid renewable electricity). A battery energy storage system (BESS) was deployed. The lowest LPC_C6A was found at a BESS installation of 29 GJ/h for wind electricity (5.1 €/kg) and at 12 GJ/h for hybrid renewable electricity (4.7 €/kg). In both situations, the volume flexibility of the MES plant was not improved. At the investigated market and operating conditions, coupling IRE to the MES plant was economically infeasible.

This paper evaluates the potential impacts of introducing low-carbon intensity hydrogen technologies in two oil refineries with different complexity levels, emphasizing the role of hydrogen production in reducing CO₂ emissions. The novelty of this work lies in three key aspects: Comprehensive system analysis of refinery complexity using real site data, integration of low-carbon Hydrogen technologies, long-term and short-term strategies. Two Colombian refineries serve as case studies, with technological solutions adapted to their complexity levels. The methodology involves evaluating different options for hydrogen production, accounting for improvement in technological efficiency over time. The refinery systems were evaluated in a cost-optimization model built in Linny-r. Three different scenarios were considered, Business-As-Usual (BAU), high, and low-ambitions decarbonization scenarios, focusing on the time horizons of 2030 and 2050. When comparing the two case studies, the preferred decarbonization strategy for both facilities involves the substitution of SMR technology with water electrolyzers powered by renewable electricity. Post-2030, biomass-based hydrogen technology is still a costly alternative; however, to achieve CO₂ neutrality, negative emissions storage of biogenic CO₂ emerges as an achievable alternative. Our results indicate the achievability of CO₂ reduction objectives in both refineries. Our results show that achieving long-term CO₂ neutrality requires both refineries to increase renewable electricity production by 5 to 6 times for powering water electrolyzers, steam production by 2 to 2.5 times for CO₂ capture, and supply of dry biomass by 2.6 to 4.5 kt/d. The two most significant factors influencing the refining net margin in the decarbonization scenarios are primarily the CO₂ and the renewable electricity prices. The short-term horizon emerges as the pivotal period, particularly within the high-ambition decarbonization scenarios. In this context, the medium complexity refinery demonstrates economic viability until a CO₂ price of 140 €/t CO₂, while the high complexity refinery endures up to 205 €/t CO₂. The high complexity refinery is better prepared to face the challenges of decarbonization and the impacts generated on the refining margin. Compared to the BAU scenario, the high complexity refinery shows a negative impact on the net margin that corresponds to a 40 % and 5 % reduction in the short and long term, respectively. Meanwhile, for the medium complexity refinery, the impact on net margin amounts to a 52 % reduction in the short term and a 27 % improvement in the long term. Furthermore, our research highlights the significant potential for reducing CO₂ emissions by fully eliminating the use of refinery gas as fuel, providing alternative applications for it beyond combustion.

Different alternative carbon sources like CO₂, biomass and plastic waste, can be used to replace fossil carbon as feedstock in the production of methanol. Based on current literature, the plastic-based methanol route is the most competitive one among the three based on price indicator, but there is still a lack of comprehensive understanding of the techno-economic differences between alternative feedstock technologies. In this study, three technologies from each alternative feedstock were assessed to evaluate the techno-economic trade-offs between them. The research shows that even though currently the plastic-based route is comparatively cost competitive with the conventional route of producing methanol, the CO₂-based methanol route can also be competitive with green hydrogen prices in the range of 1400-1100 EUR/t. While the biomass-based route showed superior energy performance compared to the other two.