To achieve climate change mitigation targets, defossilising the production of bulk chemicals like ethylene will be critical. These high-volume petrochemicals are typically produced from fossil-based feedstocks in industrial clusters, which are highly integrated in terms of mass and energy. Replacing fossil-based processes in interconnected industrial clusters can, therefore, impact such interactions and decrease performance or cause lock-in situations at the cluster level. This has, however, been overlooked in the literature. This paper addresses this knowledge gap by evaluating the impacts of replacing fossil-based ethylene production in an existing industrial cluster with processes that use Alternative Carbon Sources (ACS) such as biomass, CO2 and plastic waste. This study explicitly evaluates the performance of the ACS-based production routes at process and cluster levels by assessing changes in mass, energy, prices, CO2 emissions and water demand. The results show that due to the notable difference in product distribution, energy needs and waste generation, a complete re-wiring of the petrochemical cluster in terms of mass, energy and revenue will be required. The results also indicate that defossilising ethylene production in existing industrial clusters can result in a shifting of burden outside the cluster for byproduct production, which can lead to increasing fossil-fuel use outside the cluster. At process level, the main challenges to defossilise ethylene are access to large quantities of clean energy and the large investment costs. Under current market conditions, among the different options examined, plastic pyrolysis is the most competitive ACS-based technology with the lowest impact at the cluster level. However, this requires a large availability of plastic waste, which will be challenging given current recycling rates. Further improvements in waste valorisation and integration of renewable energy-based heating will also be required to make this technology environmentally appealing.

Steam-generating heat pumps show great potential for reducing carbon emissions in the industrial sector. However, predicting their performance is challenging, as the irreversibilities of components evolve differently with temperature lift and condenser temperature. With over seventy design improvements mentioned in the literature, selecting the most effective design improvement is cumbersome. In this study, energy and exergy-based methods were compared in their ability to identify favourable design changes to a single-stage subcritical heat pump for the generation of steam from hot condensate. The introduction of a sequential compressor with an intermediate cooler, based on the results of the energy analysis reduced the heat pump’s techno-economic performance. The results of exergy-based methods lead to the addition of either an internal heat exchanger or a flash vessel by and improved in both cases technoeconomic performance. The internal heat exchanger performed best and increased the coefficient of performance from 2.3 to 2.8 and reduced operational costs by 0.8 M€ after 5 years of operation. Additionally, the initial investment decreased by 135 k€, and the total costs of operation decreased from 10.3 M€ to 8.7 M€. These findings show that exergy-based methods are the way forward in identifying effective design improvements for steam generating heat pumps.

Reaching climate goals requires a rapid scale-up of clean energy technologies, which, in many cases, are still under development. Low-temperature CO₂ electrolysis (LT CO2E) is a promising pre-commercial technology (TRL 3 to 6) that can produce CO₂-based fuels and chemicals using electricity. To understand the future competitiveness of such novel technologies, techno-economic assessments (TEAs) are conducted using the best available knowledge at the time, ensuring that the highest-quality TEA information supports decision-making regarding future investments. As LT CO₂E advances, its techno-economic research must evolve toward more in-depth process designs, integrating the latest knowledge regarding the technology's development and any aspects essential to commercial implementation. To do so, it is important to understand the robustness and limitations of existing LT CO2E TEAs to identify areas for further improvement; for example, electricity and CO2 cost assumptions vary significantly between TEAs for syngas, accounting for 18–81% and up to 28% of the total operational expenditure, respectively. This review assessed the origins and justifications behind common assumptions used in TEAs of LT CO2E with three main findings: 1) the methodological justifications seem stuck in the past, relying on three key studies and mature electrolysis technologies from previous decades; 2) the latest advancements in electrolyzer modeling underscore the need to update existing LT CO₂E performance benchmarks, and 3) future LT CO₂E TEAs need to include pre-treatment of CO₂ and water, product separation steps, as well as heat integration, recycling, and waste valorization, to progress beyond the preliminary conceptual design phase.

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.

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 petrochemical industry is composed of several interconnected processes that use fossil-based feedstock for producing chemicals. These processes are typically geographically clustered and often belong to different parties. Reducing the environmental impacts of the petrochemical industry is not straightforward due to, on the one hand, their reliance on fossil fuels for energy and as a feedstock and, on the other hand, the significant level of interconnected energy and material flows among processes. Current methods for analyzing changes to existing processes cannot capture the multitude and level of interactions. The goal of this paper is to create a model of a petrochemical cluster and analyze its physical characteristics and performance. This paper addresses this goal by developing an assessment method that combines process simulations, multiplex graph analysis, and key performance indicators. The method is applied to a case study based on the petrochemical cluster in the Port of Rotterdam, resulting in a uniquely highly detailed model of a petrochemical cluster. The network analysis results show that only some of the processes are very interconnected. From the performance analysis, it can be observed that the olefins process is the most carbon-intense and has high CO2 emissions. Additionally, the results showed the importance of considering existing interconnections when assessing the current performance of existing petrochemical clusters or the performance due to future changes to chemical processes. For instance, some changes would occur to an industrial cluster by introducing alternative carbon sources, such as biomass or CO2.

CO2 electroreduction driven by renewable energy is a promising technology for defossilizing the chemical industry, but intermittency challenges its operation. This work aims to understand the impacts of intermittency on the design, volume flexibility, and scheduling of a microbial electrosynthesis (MES) plant that converts CO2 to hexanoic acid. A battery and a storage tank were considered to buffer the intermittency. Explorative case studies showed that batteries were economically unfavorable. Restricted by the downstream processing (DSP) flexibility, a storage tank with optimized size combined with optimal scheduling, under the assumed conditions in this work, improved the plant’s volume flexibility only by 10%. The carbon footprint became 3 times lower when switching from grid to renewable electricity, but the levelized production cost of hexanoic acid increased. Hence, coupling with renewable electricity was not economically but environmentally favorable. Developing more flexible DSP technologies or synthesizing higher-purity chemicals are needed to enhance MES’s attractiveness.

This research uses system optimization to assess short, medium, and long-term scenarios to achieve the committed CO₂-emission goals of Ecopetrol while minimizing potential adverse impacts such as incremental operational costs and utility demand. Two Colombian refineries are used as a case study: a medium-complexity and a high-complexity refinery. The study explores whether the level of complexity plays a significant role in the results. Potential technologies were ranked using a multi-criteria decision analysis. The system analysis and optimization were done in Linny-R, a mixed integer linear programming software package developed by TU Delft. In the short-term (2030) scenario, the selected technologies include low-carbon H₂ produced from Steam Methane Reformer units with carbon capture and storage and H₂ produced from renewable electricity sources. The medium and long-term (2050) scenario also included biomass gasification, naphtha reforming, and the cracking unit, all with carbon capture and storage. The refineries were modelled using on-site company data. The results indicate that using low-carbon H₂ and carbon capture and storage to flue gases would allow to reach the net zero target. Furthermore, the results show that the level of complexity in a refinery significantly impacts the decarbonization deployment pathways. The high-complexity refineries benefited from using low-carbon H₂ as feedstock while the medium-complexity refinery relied on a combination of carbon capture and low-carbon H₂ as an alternative fuel. This research highlights the potential to achieve substantial CO₂ emissions reductions with less impact on the total operational cost by using the amount of excess refinery gas generated when H₂ is used as fuel in boilers and process furnaces. A significant challenge remains in identifying suitable applications for surplus refinery fuel gas beyond its conventional use in combustion within boilers and furnaces.

Heat pumps are a promising option to decarbonize the industrial sector. However, their performance at a plant-level can be affected by other process changes. In this work, process changes that improve the heat pump's performance have been identified using Process Change Analysis (PCA), where the background pinch point is used as a reference point for appropriate placement. The effects of the process changes on the heat pump's work requirements are studies by introducing exergy to PCA to form the split exergy grand composite curve. This graph shows the work potential of the streams connected to the heat pump and therefore its work targets. The framework is demonstrated in two case studies. In a biodiesel production plant, it allowed to identify technologies that enhance heat pump performance while reducing overall heating requirements. Here, a heat pump transfers 1.9 MW with a COP of 4.2 but incurs a 40 kW penalty for transferring heat above the background process's pinch temperature. Replacing the wet water washer with a membrane separation unit avoided this penalty, while drastically reducing energy requirements from 0.9 MW to 0.3 MW. in a vinyl chloride monomer-purification process, PCA showed how the extraction of heat by the heat pump impacted the formation of the background pinch, from which an implementation strategy was derived that increased the heat pump's plant-level performance by 6.5% with respect to standard implementation.

Carbon dioxide capture, transport, and storage (CCS) is essential in achieving the net-zero target. Despite this increasing recognition, current CCS deployments are far behind targeted ambitions. A key reason is that CCS is often perceived as too expensive. While assessments of the costs of CCS have traditionally looked at impact at the plant level, the present study seeks to understand the costs and environmental benefits that will be passed to consumers via end-products and services. In particular, nine end-products/services (bridge construction, electricity from onshore wind power, electricity from offshore wind power, transport of a container via ship, a magazine, the production and transport of an avocado, a beer can, waste treatment via waste-to-energy, and long-distance air travel) connected to ten potential areas of application for CCS (cement production, iron and steel production, oil and gas production, natural gas processing, refining, ship propulsion engines, pulp and paper production, urea production, waste-to-energy, and direct air capture). The evaluations highlight that significant emission reductions (beyond 50%) could be achieved at marginal costs for end-users in six end-products/services: bridge construction, electricity from onshore wind power, electricity from offshore wind power, transport by ship, magazine, and waste treatment. Moderate emission reductions (between 11 and 37%) could be achieved in two cases at virtually no cost (increase below 1%): beer can and avocado production. Finally, only the case of using direct air capture to compensate for emissions from air travel was found to raise the cost for end-users significantly. Although more research is still needed in this area, this work broadens our understanding of the real cost and benefits of CCS and provides useful insights for decision-makers and society.

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.

The petrochemical industry needs to reduce the use of fossil fuel as carbon feedstock to reduce its CO2 emissions. Several alternative carbon sources (ACSs), such as biomass, CO2 and plastic waste are being proposed to replace fossil carbon. As each of these ACS process routes has its tradeoffs, it is essential to identify the defossilization pathways that will have the most significant impact. In this work, a superstructure-based optimization approach is presented that can be used to assess defossilization pathways in existing petrochemical clusters. The small case study shows that CO₂ is a promising ACS to replace fossil fuel as the main carbon source but requires a large amount of green hydrogen and significant modifications to the existing cluster.

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.

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.

Microbial electrosynthesis (MES) is a novel carbon utilisation technology aiming to contribute to a circular economy by converting CO₂ and renewable electricity into value-added chemicals. This study presents a cradle-to-gate life cycle assessment (LCA) of hexanoic acid (C6A) production using MES, comparing this production with alternative technologies. It also includes a cradle-to-grave LCA for potentially converting C6A into a neat sustainable aviation fuel (SAF). On a cradle-to-gate basis, MES-based C6A exhibits a carbon footprint at 5.5 t CO₂eq/tC6A, similar to fermentation- and plant-based C6A. However, its direct land use is more than one order of magnitude lower than plant-based C6A. On a cradle-to-grave basis, MES-based neat SAF emits 325 g CO₂eq/MJ neat SAF, which is significantly higher than the counterparts from currently certified routes and conventional petroleum-derived jet fuel. However, its negligible indirect land use change emissions might potentially make it competitive against neat SAFs originating from first-generation biomass.

Electrifying the utility supply of existing petrochemical processes is a potential measure for CO₂ emission reduction in the chemical industry. With an increasing share of variable renewable energy sources in the electricity grid, electricity price fluctuations will become more frequent. However, most existing petrochemical processes operate continuously and, therefore, require a constant supply of utilities. In this paper, we model an electrified utility system that includes different types of storage units to explore how a constant utility demand could be supplied under fluctuating electricity prices. To achieve this, we model a utility system that provides electricity and heat to an olefins plant in the Port of Rotterdam and use mathematical optimisation to capture optimal hourly operations of the plant under fluctuating prices. We find that the cost-optimal utility system consists of electric boilers, integrated thermal energy storage, and technologies for storing and using hydrogen produced on-site. With data for prices of the Dutch electricity grid in 2022, the electrified utility system results in higher costs than a fossil-based system. Increasing price fluctuation levels would lead to lower operational costs as the system's flexibility enables shifting the electricity consumption to the hours with the lowest electricity prices.

Due to the heavy dependence on fossil-fuels as raw materials, the defossilization of feedstocks in the petrochemical industry represents a challenge. A large number of possible process routes that use alternative carbon sources (ACS) like CO2, biomass, and waste are being developed for the feedstock replacement. For instance, to produce ethylene, more than 40 ACS process routes were identified. These multiple options make the selection of the promising process route a complex task. By replacing feedstocks, a process can change significantly and the impacts related to these changes in a highly interconnected industrial cluster can create cascading effects due to system interdependencies. This work aims to understand the cascading impacts in carbon flows and prices of implementing an ACS production process in an ethylene cluster. The results show that PVC will be the highest impacted and defossilizing one value-chain can have cascading effect on other value-chains as observed for PET.

Steam generating heat pumps show great potential for reducing carbon emissions in the industrial sector. However, predicting their performance is challenging as the exergy destruction of e.g., compressors and expansion valves increases with the temperature lift and condenser temperature. With over seventy design improvements mentioned in the literature, selecting the most effective design improvements is crucial. In this study, energy and exergy-based methods were compared in their ability to identify design improvements for a single stage subcritical heat pump to produce steam from hot condensate. The energy-based method suggested the addition of a sequential compressor with an intermediate cooler; however, this design did not improve the heat pump's techno-economic performance. The suggestion of adding either an internal heat exchanger or a flash vessel by exergy-based methods did lead in both cases to improved techno-economic performance. The internal heat exchanger performed best and increased the coefficient of performance from 2.3 to 2.8 and reduced operational costs by 0.8 M€ after 5 years of operation. Additionally, the initial investment decreased by 135 k€, and the total costs of operation decreased from 10.3 M€ to 8.7 M€. These findings show that exergy-based methods are the way forward in identifying effective design improvements for steam generating heat pumps.

Negative emission technologies such as biomass with carbon capture and storage (bioCCS) may become an important instrument to limit global warming. Currently, estimates of CO2 avoidance cost for bioCCS vary widely. Using a case study of a cement plant, this paper illustrates how this variance is partially attributable to the system boundary choices made by modellers. The estimated avoidance cost for the bioCCS-in-cement plant ranged from 48-321€2017/t CO2(eq) and the net CO2(eq) from -660 to 16 kg CO2(eq)/t cement, without any change in the technological model, equipment and input costs, or lifecycle emissions, but by changing the system boundaries used for cost and emission accounting, reflecting the different boundaries seen in bioCCS literature. To allow for more comparable bioCCS cost estimates, studies should always account for costs and emissions of both biomass production and the full chain of carbon capture, transport, and permanent storage, as both are fundamental to the role of bioCCS as a potential “negative emission technology”. We also advocate for clear decomposition of metrics, separation of “avoided emissions” from physical flows of greenhouse gases; and explicit consideration of the temporality of the bioCCS system. With these guidelines, the range of avoidance cost of the bioCCS-in-cement plant shrinks to 157-193€2017/t CO2(eq) for near-term estimates and to 89-107€2017/t CO2(eq) for longer-term estimates.

Using alternative carbon sources (ACS) to produce downstream derivatives (DDs) is a promising option for defossilising the chemical industry. However, the potential consequences of using ACS in interconnected petrochemical clusters are generally overlooked. This paper aims to develop a methodological approach for systematically analysing defossilisation impacts at the value chain level. For this, a single value chain for producing methyl-tert-butyl-ether (MTBE) was used as a case study. The individual components of the value chain were modelled in Aspen Plus v12. Both ACS- and fossil-based value chains were compared in terms of (i) changes in the structure of the value chain and (ii) the magnitude of the impacts. The results show that the defossilisation of a single value chain causes additional impacts at the cluster level.