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Renewable-based green hydrogen is emerging as a viable solution for decarbonizing energy-intensive industries. However, the fluctuating and intermittent nature of renewable energy sources requires careful consideration of operational strategies to ensure the safe and economical use of green hydrogen in industrial applications. This study examines the influence of operational strategies for electrolyzers and downstream processes on the cost of solar-based green hydrogen. The results demonstrate that optimal operational strategies for electrolyzers significantly impact the sizes of batteries and electrolyzers, reducing the Levelized Cost of Hydrogen (LCOH) by an average of 5.3%. Case studies further demonstrate that decentralized end-user supply strategies and cooperation with downstream processes can reduce LCOH by up to 39.8% for fully distributed end-users and by 24.2% with the introduction of supply tolerance. Additionally, the study evaluates the impact of grid backup, revealing that grid utilization can reduce LCOH by 12.9% in Houston, underscoring the potential for further cost reductions through grid decarbonization. These findings highlight the importance of optimizing operational strategies to improve the economic performance and market viability of green hydrogen systems. • Analysis of operational strategies affect on the cost of solar-based green hydrogen. • A 6-hour minimum on-time for electrolyzers minimized LCOH by reducing shutdowns. • Decentralized end-users cut LCOH by 39.8%, mainly in areas with seasonal variation. • Grid backup cut LCOH by 13% in Houston, showing potential from grid decarbonization. [ABSTRACT FROM AUTHOR]

Manganese is one of the most consumed metals due to its use in iron and steel making, which generates between 7%–9% of all CO 2 emissions produced globally per annum. For the first time, this work explores the potential of a novel process concept to reduce CO 2 emissions, energy consumption, and decarbonization costs in manganese production, which involves integrating fuel-assisted solid oxide electrolysis cells (FASOECs) in a two-stage scheme for the reduction of raw manganese ores. In this scheme, higher oxides that are present in raw manganese ores (MnO 2 , Mn 2 O 3 , Mn 3 O 4) are pre-reduced using CO, yielding manganese monoxide (MnO) that is further reduced to Mn in a submerged arc furnace (SAF) using coke and electricity. In the proposed FASOEC integration concept, off-gas from the manganese ores after pre-reduction (a mixture of H 2 , CO, and CO 2) is supplied to the FASOECs' anode as fuel, in order to produce high-purity H 2 in the cathode that is directed to the first stage of manganese reduction. H 2 has enhanced reaction kinetics for reducing higher manganese oxides in comparison to CO; therefore, integrating FASOECs can improve manganese oxide conversion rates during pre-reduction, resulting in lower consumption rates of coke and energy in the SAF. The off-gas supplied to the FASOECs' anode also lowers the amount of energy required for H 2 production in the cathode (can also generate electricity, simultaneously) and produces anode exhaust gas containing only CO 2 and steam. Since steam can be easily condensed from this stream, the integration of FASOECs also enables efficient decarbonization of the manganese production process, thus eliminating the need for a designated CO 2 capture system. The techno-economic analysis performed herein demonstrates that directing the full supply of off-gas produced by the SAF to the FASOECs' anode at 800 °C reduces the overall energy consumption of manganese production by up to 18% in comparison to conventional processes. This results in decarbonization cost reductions by as much as 3%–15% and a corresponding decarbonization price range of $4-32 per ton of manganese product for plant capacities of 50 and 200 kt, respectively. • Integrates fuel-assisted solid oxide electrolysis cells (FASOECs) in Mn production. • Novel process concept reduces coke and electricity consumption dramatically. • FASOECs generate high-purity CO 2 to eliminate costly CO 2 capture systems. • Integration of FASOECs in Mn production reduces decarbonization costs by 15%. • FASOEC integration in Mn production reduces energy consumption by up to 18%. [ABSTRACT FROM AUTHOR]

Energy storage is essential for on-demand electricity generation from renewable sources like wind and photovoltaics. Repurposing fossil-fired power plants with thermal energy storage (TES) offers a cost-effective solution for large-scale grid energy storage. This paper explores converting supercritical coal plants into flexible grid storage systems using adapted nitrate salt technology. State of the art TES systems are limited by their maximum operating temperatures at up to 560 °C, but higher temperatures cause nitrate salts to decompose. Supercritical steam power plants require steam temperatures above 600 °C for optimal efficiency. To address this, a closed gas handling system can keep gaseous decomposition products within the nitrate storage system, stabilizing the salt at temperatures up to 620 °C. This study presents the optimal design of such a gas system based on a techno-economic analysis and determines the overall electrical efficiency improvement of the supercritical power plant equipped with the adapted 620 °C storage compared to a subcritical power plant with 560 °C. The costs of repurposing power plants with two-tank and single-tank (thermocline) storage systems are evaluated, identifying potential cost savings of up to 18 % with the 620 °C single-tank system. The gas handling system costs are minimal. Compared to grid-scale lithium-ion batteries with a 10-h discharge duration, the levelized cost of storage (LCOS) for the proposed system is lower for low charging electricity costs. The 620 °C nitrate salt technology could further reduce LCOS in most cases worldwide. This paper demonstrates the economic feasibility of a 620 °C molten salt system, highlighting cost savings over conventional options like batteries. The research provides valuable insights into repurposing existing fossil fuel infrastructure for a sustainable and efficient renewable energy transition. [Display omitted] • Gas handling system elevates nitrate salt temperature limit up to 620 °C. • Round-trip efficiency of up to 47.4 % for supercritical power plants. • Up to 14 % cost savings with adapted 620 °C nitrate salt technology. • Using a 620 °C single tank concept can reduce costs by 18 %. • Molten salt system costs approximately 1/3 of lithium-ion battery costs. [ABSTRACT FROM AUTHOR]

One approach to reducing atmospheric carbon dioxide (CO 2) emissions is to adopt carbon capture utilization and storage (CCUS) strategies. This is particularly crucial for countries to achieve their net-zero goal. In this study, we investigate the techno-economic viability of a proposed CCUS process that utilizes geologically stored CO 2 , associated with hydrogen (H 2) production from fossil fuels, as a working fluid to extract geothermal energy from deep, large-scale, sedimentary storage formations. The process ensures permanent geological storage of all injected CO 2 while generating adaptable geothermal power through supercritical CO 2 turbine expansion, thus, bolstering revenue and reducing the final cost of blue hydrogen production. We simulate subsurface-wellbore fluid flow and heat transport for a representative 4-way closed anticlinal Arabian reservoir and optimize system power output, including a comprehensive and integrated economic analysis. We find that CO 2 captured from an equivalent blue H 2 production of ∼4.1 Mt./year can be injected at an annual rate of 0.92–1 million metric tons (Mt) per well, resulting in a cumulative sequestration of ∼1.15 gigatons (Gt) of CO 2 over 11.5 years. To mitigate the risks of reaching the formation parting pressure at the crest of the anticline and ensuring sufficient CO 2 saturation at the production wells, phased drilling schedules and pressure-controlled injection and production are essential. With horizontal production wells, our simulations generate an average geothermal net electricity of 164 MW. The base-case economic analysis reveals a Levelized Cost of Electricity (LCOE) of 77 $/MWh and a Net Present Value (NPV) of 480 million USD over 50 years. In contrast, vertical production wells double LCOE, and the project remains unprofitable throughout its life (negative NPV). Our economic sensitivity analysis further emphasizes how the capacity factor, electricity selling price, and drilling costs govern LCOE and NPV. On the other hand, discount rates and Opex fraction are influential yet uncertain parameters affecting the system's techno-economic outlook. Therefore, our study provides valuable insights into the benefits of geothermal energy production from over 1 Gt of stored CO 2 and the associated economic landscape. • A thorough techno-economic analysis of large-scale CO2-based geothermal systems is presented. • Phased drilling schedules and pressure-controlled development strategies offer power generation and economic advantages. • Projected LCOE is 77 $/MWh utilizing horizontal production wells, while vertical production wells double LCOE (infeasible). • A sensitivity analysis on the impact of economic parameters on LCOE and NPV is presented. • We emphasize a synergistic CCUS approach to achieve decarbonization goals, along with its limitations. [ABSTRACT FROM AUTHOR]

Developing low-carbon systems for the steel industry is increasingly considered necessary for contributing to the targets of CO 2 emission reduction requested by modern environmental policies. This work focuses on a process for decarbonizing primary steel production by integrating an MCFC system in a DRI production plant based on the Energiron ZR process configuration. An MCFC system can be used to remove CO 2 from the flue gases while producing electricity and reducing the net electric consumption of the DRI plant. The reference scenario, the carbon capture case, and an additional hydrogen-based H-DRI system using high temperature electrolysis are simulated using Aspen Plus to evaluate and compare their energy and environmental performance. The results show that even considering the additional power consumption of the complete carbon capture and separation system, the overall electrical consumption of the carbon capture case is decreased by 78 % and the direct CO 2 emissions by up to 95 %. Furthermore, reduced electricity consumption reduces scope 2 emissions, increasing the sustainability of the process in the steel industry. On the other hand, the H-DRI case decreases primary energy consumption by 24 % but significantly increase electricity requirement; thus, it represents a better future solution when cheap low-CO 2 electricity is available. The plant configurations are compared economically by retrieving investment and operational costs from the open literature to estimate the levelized cost of DRI and the cost of CO 2 avoided. The results show that installing the MCFC and the anode purification system increases the investment costs by 38 % compared to a conventional plant. However, the lower electricity consumption and carbon tax expenditure lead to a comparable final DRI product cost. Contrarily, due to the electrolyzer high investment and operational costs, the additional marginal DRI cost of the H-DRI case is 31 % higher. Finally, the sensitivity analysis on the main variable costs shows that, independently from the electricity and natural gas price, the carbon capture case is economically competitive to the reference scenario, considering a carbon tax of 60 €/t CO2 or higher. At the same time, the H-DRI solution requires low electricity prices to be competitive. In conclusion, even if, in the long term, the objective is to completely replace the use of fossil fuels with renewable energy, in the short term, the implementation of MCFC in the DRI plant can significantly reduce the environmental impact of primary steel production without significant economic penalization. • A novel system for the decarbonization of the steel industry featuring a MCFC is presented. • A techno-economic comparison of the decarbonization system with a reference case and future HDRI scenario is carried out. • The decarbonization system allows a reduction of 78 % of the electric consumption and 95 % of the direct CO2 emissions. • The proposed decarbonization system is competitive with the reference case from an economic point of view. • A sensitivity analysis shows how the economic performance of the cases are affected by different economic frameworks. [ABSTRACT FROM AUTHOR]

Hydrogen is seen as a key energy carrier to reduce CO 2 emissions. Two main production options for hydrogen with low CO 2 intensity are water electrolysis and natural gas reforming with Carbon Capture and Storage, known as green and blue hydrogen. Northern Norway has a surplus of renewable energy and natural gas availability from the Barents Sea, which can be used to produce hydrogen. However, exports are challenging due to the large distances to markets and lack of energy infrastructure. This study explores the profitability of hydrogen exports from this Arctic region. It considers necessary investments in hydrogen technology and capacity expansions of wind farms and the power grid. Various scenarios are investigated with different assumptions for investment decisions. The critical question is how exogenous factors shape future regional hydrogen production and export. The results show that production for global export may be profitable above 90 €/MWh, excluding costs for storage and transport, with blue hydrogen being cheaper than green. Depending on the assumptions, a combination of liquid hydrogen and ammonia export might be optimal for seaborne transport. Exports to Sweden can be profitable at prices above 60 €/MWh, transported by pipelines. Expanding power generation capacity can be crucial, and electricity and hydrogen exports are unlikely to co-exist. • Hydrogen prices above 60–90 €/MWh necessary for profitable production. • Northern Norway can remain an energy export region in the future. • Availability of wind power crucial for any hydrogen exports. • Developing hydrogen hubs depends on price and available electricity. [ABSTRACT FROM AUTHOR]

This study reports a comprehensive techno-economic and environmental assessment of a realistic pathway for decarbonizing the urea industry. The proposed green urea synthesis plant utilizes hydroelectricity-powered electrolysis process and carbon capture from cement flue gas to create sustainable and environmentally friendly production process. Utilizing Aspen Plus and MATLAB, this study first, models the electrolysis, air separation, ammonia synthesis, carbon capture and urea synthesis units, and then evaluates the economic and environmental parameters of the synthesis process. Furthermore, the study highlights the transformative impacts of carbon credit and the renewable energy prices on the profitability metrics of the green urea plant. For the proposed 220 kt/year urea plant, the total energy consumption is 8.18 × 106 GJ/year with the electrolysis unit accounting for half of the energy demand. The estimated total capital investment for the urea plant is 510.79 million USD, with an annual operating expenditure of 156.02 million USD. The urea synthesis unit accounted for half of the total capital expenditure, while electricity contributed to the largest proportion (73%) of the operating expenses. The levelized cost for urea (LCOU) is estimated to be 570.96 USD/t which is approximately 62.2% higher than the urea obtained from conventional process. The electrolyzer unit contributed to 34.4% of the total LCOU. Sensitivity analysis showed that 30% decrease in the electricity price from the base case could lower the LCOU by 27%. The global warming potential of the proposed green urea process is 326.11 kg CO 2 /t of urea. Lower hydroelectricity prices and carbon credit opportunities significantly improve the economic viability of the green urea production process. [Display omitted] • Detailed techno-economic and environmental assessment for green urea production. • Electricity price alone contributes 73% of total production cost. • LCOU of green urea is 571 USD/t. • GWP analysis of green urea production process is 326 kg of CO 2 /t of urea. • Lower electricity prices and carbon credits improve plant profitability. [ABSTRACT FROM AUTHOR]

Hybrid photovoltaic (PV) - wind power plants (HyPPs), i.e., where the PV and wind systems are co-located and share the Point of Interconnection (POI) with the grid, have recently attracted more attention. This trend is driven by the expected reduced capital and operational expenditures achieved through, e.g., shared land and POI infrastructure for HyPPs compared to two individual PV and wind installations. However, if the POI is underdimensioned relative to the PV and wind capacities, the generation from either or both of the assets must at times be curtailed, unless mitigated by solutions like energy storage. This curtailment might lead to income losses. Moreover, as HyPPs typically are designed using wind and PV generation data on hourly resolution, the actual curtailment losses can be underestimated. This might in turn lead to HyPP designs which are techno-economically sub-optimal. In this study, a comparative analysis is conducted to analyze how the curtailment and income loss estimations for HyPPs, as well as the techno-economic optimal HyPP topologies, are impacted by varying the input data time resolution. One year of site measured PV and wind power generation data on 5 s resolution from an existing HyPP located in Eastern Germany are used as basis for the study. For a HyPP topology with an undersized POI, where the installed capacities of the POI, PV, and wind systems are all equal, the curtailment losses are estimated to be 1.45%, 1.43% and 1.09% using the 5 s, 1 min and 1 h resolution datasets, respectively. Moreover, using the 1 h instead of the 1 min dataset leads to a 1.86% overestimation of the total Net Present Value (NPV) for this HyPP topology. As the shares of the PV and wind systems increase relative to the POI capacity, the differences in the estimation of the curtailment losses and NPVs between the high- and low-resolution datasets become more significant. [Display omitted] • High-resolution time series data from an existing PV–wind hybrid plant is analyzed. • The effects of data resolution on curtailment losses are demonstrated. • Hourly data underestimates losses for systems oversized relative to grid connection. • The data resolution is not found to greatly affect the optimal system topology. • Hourly data overestimates the net present values of the optimized topologies. [ABSTRACT FROM AUTHOR]

Italy's architectural heritage boasts numerous historic buildings, which are an integral part of the country's cultural fabric and public assets. However, these structures inevitably deteriorate over time and require various types of intervention, particularly to mitigate energy dissipation. Yet, retrofitting historic buildings poses a challenge as preserving their historical features requires non-invasive strategies. To address this challenge, the present study introduces the incorporation of an innovative geothermal system tailored for the energy retrofit of an Italian historic building. This innovative system respects the building's landscape and constraints due to the archeological status of the building. It consists of a hybrid heat pump connected to a gas boiler, interfacing with a geothermal field to leverage it as either a heat source or sink. An in-depth analysis of this system was conducted, first in a specialized laboratory to assess its performance and then following its installation inside the historic building, thus interfacing it with a historical context and a real geothermal field. Notably, the comparative evaluation of the Coefficient of Performance (COP) between laboratory simulations and real-world deployment revealed striking similarity, affirming the system's consistent performance across contexts. Moreover, for a comprehensive analysis of the system, a techno-economic evaluation was carried out, which highlighted the many advantages of this installation. • A new energy retrofit strategy is proposed for a historic Italian building • A hybrid heat pump connected to a geothermal field is analyzed • Detailed analysis of the heat pump: in-lab and in-field (installed in the building) • Techno-economic analysis of the proposed system [ABSTRACT FROM AUTHOR]

Solar photovoltaic generation has become the dominant global method of producing renewable electricity around the globe. However, solar PV farms require a considerable amount of land. Agrivoltaics has been a promising field of interest recently as this system maximizes the land's utilization by producing crops beneath the photovoltaics panels. This paper proposes a new agrivoltaics system that simultaneously produces crops and electrical power by installing PV panels on agricultural land in such a way that the production of regular crops does not get curtailed and can still grow around and beneath the panels, avoiding any reduction in crop yield. The architectural design of the proposed mounting structure and the installation method are discussed, ensuring full utilization of the land area under the panel with no crop limitations. Bangladesh is considered a case study location as its economy is mostly dependent on agriculture. The country started allocating enormous amounts of farmland for solar photovoltaic farms to mitigate the energy crisis. After a preliminary survey, an agrivoltaics system was designed, developed and installed in the Chuadanga District of Bangladesh. Then a detailed techno-economic analysis was performed to evaluate the feasibility and economic viability of the implemented agrivoltaics project. A comparative analysis of seven different scenarios is demonstrated in terms of equity payback, internal rate of return, modified internal rate of return, net present value, annual life cycle savings, and benefit-cost ratio to determine the optimum agrivoltaics approach as well as to showcase the superiority of the proposed system. The results demonstrate that the proposed agrivoltaics system achieves full land utilization, by producing crops along with electricity generation with the lowest payback period, highest profit margin, and highest benefit-cost ratio over the project lifetime. • An innovative Agrivoltaic (AV) approach for simultaneous food and energy production on the same land. • A technique to minimise the shading effect on the crop yield ensures full farmland utilization. • A quantitative techno-economic analysis for evaluating profit margin and energy balance. • Reduced payback period (3 years) compared to typical PV system (5–6 Years). [ABSTRACT FROM AUTHOR]

The development of biomass faces challenges due to its low energy density and wide dispersion, particularly in the case of agricultural straw, resulting in high supply chain costs. To address these challenges, a comprehensive approach that combines spatial planning with techno-economic analysis (TEA) and life cycle assessment (LCA) was employed to establish an economically sustainable and low-carbon biomass supply chain (BSC) system. The approach encompassed the integration of straw resource and road network data into a Geographic Information System (GIS), which was subsequently utilized to devise TEA and LCA calculation methods leveraging the GIS data. Scenario analysis was performed by adjusting the service radius of the pretreatment center to identify the optimal location of the bioenergy plant, minimize the BSC cost, and reduce the carbon footprint. The results indicated that implementing a service radius of 3–4 km achieved an optimized BSC scenario in the study area, resulting in BSC costs of 375 CNY/t and carbon emissions of 125 kgCO 2 /t. Overall, this work offers a promising modeling framework for the efficient, economical, and sustainable utilization of bioenergy. • The spatial LCA method was established based on a geographic information system • Coupling spatial LCA and TEA build a low-carbon and economical biomass supply chain • Service radius analysis mapped out the optimal plant location and transport routes • The optimized scenario achieved a cost of 375 CNY/t and GWP of 125 kgCO 2 /t [ABSTRACT FROM AUTHOR]

This work provides a comprehensive techno-economic assessment of high-temperature direct air capture (HTDAC) integrated with Fischer–Tropsch synthesis (FTS) for producing renewable jet fuel on a scale of approximately 25 t/h. Specifically, the HTDAC is based on calcium looping employing calcination in a hydrogen-based atmosphere to enable simultaneous RWGS reaction. A detailed description of the Aspen Plus model for HTDAC, alkaline and solid oxide electrolysis systems, RWGS reactor and the FTS is provided for future reference. Five system configurations are analysed, comparing the energy efficiency effects of hydrogen oxy-fuel combustion and electric calcination in a hydrogen-based atmosphere. In this regard, the potential omission of the RWGS reactor is examined, considering that 62 to 78 % of the CO 2 is already converted into CO in the calciner, with the highest conversion rates achieved through electric calcination. Moreover, the study investigates the impact of alkaline electrolysis and solid oxide electrolysis on the system's energy efficiency. Overall carbon efficiencies of more than 50 % in the jet fuel are achieved, with system energy efficiencies ranging from 30.6 to 39.0 % corresponding to fuel-specific energy consumption in the range of 122 to 156 MJ/kg Jet fuel. Net present value (NPV) analysis reveals a projected minimum fuel selling price (MFSP) in the range of 4.45 to 6.32 €/L, which is significantly higher than previous literature estimates based on more optimistic cost assumptions. Uncertainties in cost parameters are addressed through a Monte Carlo analysis which shows the potential of a significant decrease in the MFSP provided that some of the cost estimates will be cheaper than the conservative initial estimate. Conclusively, this study highlights the significance of developing a financially feasible electrically heated calciner that can effectively handle high-temperature hydrogen. Furthermore, maximising the yield of jet fuel emerges as a critical factor for unlocking the future potential of the process, as it substantially reduces the cost of fuel production. Lastly, the reduction of hydrogen production costs is identified as the most crucial aspect in enhancing the economic viability of the process, as it serves as the biggest contributor to the high minimum fuel selling price. • Comparison of 5 integrated direct air capture, Fischer–Tropsch, and electrolysis systems. • Potential integration of H 2 -fired calciner and RWGS in single component is discussed. • Jet fuel energy efficiency up to 39 %; potential for 47 % with lights and waxes. • Minimum jet fuel selling price: 3.5–6.5 €/L with H 2 as main cost contributor. • Electric calcination in H 2 reduces the minimum jet fuel selling price with ∼ 0.6 €/L. [ABSTRACT FROM AUTHOR]

Green hydrogen emerges as a vital solution for mitigating the variability of renewable energy sources, acting as a stable buffer to their unpredictable nature. This study concentrates on developing an optimal green hydrogen system, tailored to manage fluctuations in renewable energy production and diverse hydrogen demand patterns. Our comprehensive model integrates inputs from wind turbines and photovoltaic systems with proton exchange membrane (PEM) water electrolysis, and includes energy storage options like batteries and hydrogen storage tanks. Analyzing data on renewable energy availability, equipment costs, and operational efficiencies yields crucial indicators for assessing economic viability and reliability: the Levelized Cost of Hydrogen (LCOH) and the Loss of Hydrogen Probability (LOHP). These indicators serve as dual objectives in our multi-objective optimization framework, which seeks to determine the most effective system configuration and size. The simulation results illustrate the impact of varying demand scenarios on economics and reliability, highlighting the necessity of combining renewable sources with adequate energy buffering to achieve LOHP below 2%. The optimization outcomes reveal a trade-off between cost and reliability, indicating that configurations incorporating both wind and solar can achieve an LCOH under 10 USD/kg while maintaining nearly zero LOHP. Our findings from the multi-objective optimization by demand scenario provide comparative economic insights for each renewable energy source, guiding optimal combinations according to desired reliability levels. [Display omitted] • Multi-objective optimization framework for balancing the economics and demand satisfaction reliability within green hydrogen systems. • Examination of the optimal system size across diverse hydrogen supply and demand scenarios • Identification of the trade-off between economics and reliability • Elucidation of the impacts of batteries and hydrogen storage tanks • Confirmation of the effects of renewable energy types and demand patterns [ABSTRACT FROM AUTHOR]

Redox Flow Batteries (RFBs) are a versatile and durable type of electrochemical storage and a promising option for large-scale stationary energy storage. Aqueous Organic Redox Flow Batteries (AORFBs) are an innovative category of RFBs that utilize organic species as active molecules in aqueous electrolytes. These species allow for customization of their properties to achieve high technical performance and reduce battery cost. This study presents a comprehensive techno-economic analysis of AORFBs, evaluating their cost metrics and their associated uncertainties. The work modeled both capital cost and Levelized Cost of Storage (LCOS) for RFBs. The model was validated on the Vanadium Redox Flow Battery (VRFB), and it was employed to evaluate the costs for a generic AORFB, using a Monte Carlo technique to incorporate the uncertainty related to the value of critical parameters. Through stochastic analysis, AORFBs are estimated to have an average specific capital cost of 674 €/kWh for 4 h, and 398 €/kWh for 8 h batteries, and probabilities between 16.9% and 29.6% of having lower capital costs compared to VRFBs. AORFBs are estimated to have a current levelized cost, calculated including only the cost of energy lost in the storage due to irreversibility, of about 530 €/MWh for 4 h, and 411 €/MWh for 8 h batteries. The levelized costs of storage, calculated including the total cost of energy charged into the storage, have average values of 663 €/MWh for 4 h, and 543 €/MWh for 8 h batteries. AORFBs have less than 1% probability of having lower LCOS than VRFBs. Current AORFB systems have higher costs compared to state-of-the-art VRFBs, even assuming a low fabrication cost for available organic molecules. This is caused primarily by the AORFBs' low energy and power densities and high degradation rates. To ensure cost competitiveness with VRFBs, it is essential to identify better-performing organic redox pairs, which should exhibit high open circuit voltage (≥ 1.1 V), should maintain reasonable round-trip efficiency (≥ 71%) while operating at a high current density (≥ 55 mA/cm 2 ). Furthermore, new organic species should have low degradation rates (≤ 0.4 %/day). • Redox Flow Batteries' (RFB) capital and levelized cost of storage (LCOS) models. • Cyclic and calendar capacity fade rates included in the levelized cost model. • Stochastic analysis based on available experimental data for organic redox species. • AORFBs exhibit average capital costs of 674 €/kWh for 4 h and 398 €/kWh for 8 h. • AORFBs exhibit average levelized costs of 530 €/MWh for 4 h and 411 €/MWh for 8 h. [ABSTRACT FROM AUTHOR]

Hydrogen is one of the potential candidates to replace fossil fuels to meet net zero emissions target. This study reports a detailed techno-economic and environmental assessment of hydrogen production through ammonia decomposition. The case study is based on a multiple catalytic packed bed reactor with intermediate heating system. Aspen plus® and MATLAB® were linked to evaluate economic and environmental impact of the process. The process parameter like furnace temperature, flue gas recirculation, ammonia decomposition temperature, market ammonia supply pressure, ammonia decomposition pressure, hydrogen purification unit's pressure and equivalence ratio, and economic parameters of capital expenditure (CAPEX) and operating expenditure (OPEX) were considered. The overall thermal efficiency of the developed process is found to be 79%. The levelized cost of hydrogen (LCOH) is estimated and found to be 6.05 USD/kg of H 2 based on CAPEX and OPEX. A major contribution of up to 62.2% to LCOH comes from the price of feed Ammonia. Based on 25-year plant life with 10% discounted rate the plant is economically viable, with a return on investment of 23.7%, in a payback period of 3.58 years. Global warming potential of the process is also carried out. [Display omitted] • Techno-economic and environmental assessment on ammonia decomposition was carried out. • Overall thermal efficiency of H 2 production from NH 3 decomposition process is 79%. • LCOH of H 2 production from NH 3 decomposition process is 6.05 USD/kg of H 2. • Ammonia price alone contributes up to 62.2% of LCOH. • GWP analysis of H 2 production from NH 3 decomposition process is 0.66 kg of CO 2 /kg of H 2. [ABSTRACT FROM AUTHOR]

This study reports a systematic techno-economic assessment of the cost-optimal transmission for air as the heat transfer fluid at temperatures of up to 1200 °C, at scales of 1 to 1000 MW and at distances of up to 10 km. It employs a steady state heat transfer analysis, with energy balances, to assess the effect of scale, temperature and insulation on the heat losses and efficiency of the thermal transmission system, following by a techno-economic assessment. The sensitivity of the Levelised Cost of Heat, LCO H tr , to variations in thermal scale, operating temperature, distance, refractory and insulation thickness, ratio of the thickness of refractory and insulation, cost of any supplementary heat and lifetime is reported. The results show that LCO H tr decreases with an increase in thermal scale, as expected. The role of insulation is much more complex, since increasing the thickness of thermal barrier increases both cost and efficiency of the transmission, requiring an economic optimum to be determined for each of the various conditions assessed. Parameters are also coupled because a higher cost of supplied energy/ heat justifies the use of more insulation material. For a large GW scale thermal system, we estimate that it is possible to achieve a minimum overall LCO H tr , min of 0.16–0.36 USD/GJ/km of the length of the thermal transmission system, excluding additional location-specific costs such as land-access and local construction costs. These estimated costs are sufficiently attractive to justify ongoing development of systems to transport renewable heat to industry from sources such as concentrated solar thermal energy. • A thermal transmission for air up to 1200 °C, 1GW and 10 km. • Efficiency and LCOH of the transmission were reported for cost-optimal situations. • The cost-optimised efficiency is strongly dependent on the cost of energy. • Cost-optimised efficiency can be above 98% for thermal transmission system >100 MW. • The cost of GW scale thermal transmission <1% of the cost of energy being transmitted. [ABSTRACT FROM AUTHOR]

In recent years, ammonia has gained traction as a clean fuel alternative and a promising energy carrier. In this study, a trigeneration system fuelled by ammonia has been conceptualised, integrating a solid oxide fuel cell stack for power generation, a hot water unit for heating, and an NH 3 -H 2 O absorption chiller for cooling. The main objective of this study is to conduct a comprehensive techno-economic feasibility assessment of the proposed trigeneration system. The system's performance was analysed for a UK supermarket requiring electricity, heating, and cooling. A detailed sensitivity analysis was performed to investigate the influence of significant operating parameters, including current density, fuel utilisation factor, and cell temperature, on the system's performance. The system can deliver maximum power, heating, and cooling outputs of 357.6 kW, 257.9 kW, and 46.99 kW, respectively. The trigeneration system is projected to achieve its highest exergy efficiency at 60.94%, with a maximum fuel energy saving ratio of 47.67%. The lowest levelised cost of energy (LCOE) is estimated to be £0.1232 per kWh. This study's objective is also aligned with United Nations Sustainable Development Goal (SDG) No. 7, which aims to achieve "Affordable and Clean Energy". [Display omitted] • Techno-economic assessment of a trigeneration system fuelled by green ammonia. • Trigeneration system's highest exergy efficiency is projected to be 60.94%. • Lowest levelized cost of energy (LCOE) calculated to be £0.1232 per kWh. • The system produces maximum power, heating, and cooling: 357.6 kW, 257.9 kW, and 46.99 kW. • System has potential to meet UK supermarkets' energy needs while mitigating GHG emissions. [ABSTRACT FROM AUTHOR]

• A generalizable sorbent-focused economic model of direct air capture. • Estimating the maximum allowable price for sorbents described in the literature. • Sorbent cycle duration and sorbent degradation strongly affect cost of air capture. • Developed a tool for cost-optimization in a multi-parameter system. Direct air capture, the removal of carbon dioxide from air, requires special sorbents, with high capture capacity, fast kinetics and long lifetime. Beyond that they also need to be affordable. However, since air capture is still in an early development stage, costs are still uncertain. We present a techno-economic model to value a sorbent based on the CO 2 market price and the most important sorbent characteristics: cycle time, loading capacity, and rate of degradation. The model gives a net present value equation for any air capture sorbent, whether it uses a moisture swing, pressure swing or thermal swing for regeneration and makes it possible to estimate the maximum allowable budget for any air capture sorbent, i.e., the sorbent value. The analysis aims to focus the rapidly growing field of air capture sorbent development onto the most important parameters. The value of a sorbent is dramatically affected by its longevity. To be economically viable, the typical sorbent must survive tens if not hundreds of thousands of loading and unloading cycles. The model can also be used to investigate the interactions between different sorbent parameters. For example, the correlation between loading capacity and cycle time makes it possible to determine the cycle time that optimizes the economics of an air capture device. Our analysis highlights the significance of some neglected parameters in air capture cost analysis such as cycle duration and stability of the sorbent. Finally, the analysis can also be adapted to post-combustion flue gas sorbents. [ABSTRACT FROM AUTHOR]

• A conceptual framework was designed for a bioenergy system for rural India. • Agro waste potential was estimated through survey. • Techno-economic analysis of an integrated system was conducted. • Uncertainty was assessed through Monte-Carlo simulation. This paper presents a holistic approach to promote bioenergy in India by designing a conceptual framework that combines resource, technology and market. The proposed concept is an attempt to integrate pelletization and gasification technology for bioenergy system development through an end-to-end approach. The potential of bioenergy resource (i.e. agro waste) was estimated based on survey. The study further assessed the economic feasibility of agro waste pelletization. The economic evaluation was made using indicators such as net present value (NPV), internal rate of return (IRR), discounted payback period (DPBP) etc. Pellet plant capacity of 0.5 ton h−1 showed acceptable economics and the NPV , IRR and DPBP were ₹9.35 million ($0.13 million), 41% and 2.8 years, respectively. Moreover, the larger capacity plants (>2 ton h−1) were subjected to more risk under low pellet prices (< ₹5 kg−1 or $71.4 ton−1). The cash flow statement showed a strong debt paying ability for the project. Pellet price was the most sensitive factor followed by annual operating days on pellet plant economics. Monte Carlo simulation predicted an average NPV of ₹9.3 ± 2.0 million ($133.2 ± 29.1 thousand). The economics of fuel pellets utilization in a gasifier for energy applications was also evaluated. The pellet fed gasifier system appeared to be cost competitive with commercial liquefied petroleum gas (LPG) and wood at a pellet price range of ₹6.3–8.8 kg−1 ($90–126 ton−1) in a select scenario. Overall, the designed framework appears to reduce over-dependency on wood or fossil sources, and facilitate bioenergy promotion in rural areas. [ABSTRACT FROM AUTHOR]

Highlights • Reviews of power system security planning considering large PV power injection. • Techno-economic investment model for voltage collapse-susceptible grid. • Voltage stability-constrained AC-OPF formulation with utility-scale PV. • Consideration of costs of PV intermittency and grid infrastructure enhancement. Abstract Energy sector of developing nations is faced with myriads of problems ranging from insufficient generation to poor grid infrastructure. Introducing variable renewable energy sources (VREs) has been identified as a way to meeting the rapidly increasing energy demand of these nations. Intermittency is one of the major shortfalls of VREs which has a direct influence on the voltage stability and the overall power system security. Hence, a cost-effective investment plan which considers the effect of PV output intermittency on the overall grid security at different level of PV power penetration is essential. In this study, a review of the approach for large-scale solar PV injection into weak grids and its effects on voltage stability is presented. A multi-objective optimal techno-economic assessment, for three different levels of PV power penetration on the Nigerian 28 bus grid, was investigated using the particle swarm optimization algorithm. The net present cost per hour of system components and the loss of supply probability are the two objectives considered. Cost of PV intermittency and grid enhancement is introduced as a function of the average power injection by the PV system using the site's capacity factor approach. PV penetration level of about 35% of the total load demand is considered safe for the investigated Nigerian power system. The designed approach can be adequately adopted for power systems of other developing nations. [ABSTRACT FROM AUTHOR]

• Techno-economic analysis of battery storage systems providing frequency control. • A stochastic, data-driven optimisation algorithm to optimise the battery controller. • Use of frequency data and detailed, yet computationally efficient battery models. • Case study of Germany shows the highest margins for a battery rated at 1.6 MW/1.6 MWh. • Calendar ageing drives battery degradation, while cycle ageing has less impact. Optimal investment in battery energy storage systems, taking into account degradation, sizing and control, is crucial for the deployment of battery storage, of which providing frequency control is one of the major applications. In this paper, we present a holistic, data-driven framework to determine the optimal investment, size and controller of a battery storage system providing frequency control. We optimised the controller towards minimum degradation and electricity costs over its lifetime, while ensuring the delivery of frequency control services compliant with regulatory requirements. We adopted a detailed battery model, considering the dynamics and degradation when exposed to actual frequency data. Further, we used a stochastic optimisation objective while constraining the probability on unavailability to deliver the frequency control service. Through a thorough analysis, we were able to decrease the amount of data needed and thereby decrease the execution time while keeping the approximation error within limits. Using the proposed framework, we performed a techno-economic analysis of a battery providing 1 MW capacity in the German primary frequency control market. Results showed that a battery rated at 1.6 MW, 1.6 MWh has the highest net present value, yet this configuration is only profitable if costs are low enough or in case future frequency control prices do not decline too much. It transpires that calendar ageing drives battery degradation, whereas cycle ageing has less impact. [ABSTRACT FROM AUTHOR]

• A calculation model is developed to determine energy consumption. • Thermodynamic matching is analyzed to judge energy consumption qualitatively. • Cost model of thermal energy is established to calculate energy consumption cost. • MgH 2 &TiFeMn is considered to be a better selection for thermal energy storage. • A matching principle based on the life cycle economic analysis is concluded. Matching of metal hydride pairs has a significant influence on performance of thermal energy storage (TES) system. This article conducts a complete techno-economic analysis of screening metal hydride pairs (MgH 2 &LaNiAl and MgH 2 &TiFeMn). A mathematical model is developed to calculate the energy consumption, which is solved by COMSOL Multiphysics v5.1. Firstly, thermodynamic matching is analyzed to judge the energy consumption qualitatively. Further, a cost model of thermal energy is established to estimate the energy consumption cost. It is found that the charging energy consumption cost of MgH 2 &LaNiAl system is reduced to be zero due to a good thermodynamic matching, whereas that of MgH 2 &TiFeMn system accounts for as high as 63.8% of the cycle energy consumption cost. Based on the life cycle economic analysis, matching of MgH 2 &TiFeMn is considered to be a better selection due to a smaller levelized thermal storage cost (28 USD/kWh th), where two major expenses are the capital cost and energy consumption cost, 74.3% and 19.3% respectively. Therefore, a matching principle is concluded that screening metal hydride pairs for TES should be considered in two ways: firstly, the hydrogen storage cost due to the expensive price of low temperature metal hydride; secondly, the thermodynamic matching, which determines the energy consumption cost. [ABSTRACT FROM AUTHOR]

Highlights • Identify thermal characteristics of biogas plant as source for waste heat recovery. • Membrane distillation of reject water can increase the capacity of the biogas plant. • Thermal integration between biogas plant and membrane distillation. • Evaluate the integrated performance of biogas plant and membrane distillation. • Cost analysis applied for the economic feasibility of the thermal integration. Abstract Digestate reject water from biogas production is often recirculated for dilution of source-separated organic waste to yield a suitable feedstock for the digestion process. The total solids (TS) content of the recycled reject water has a large impact on the potential added amount of organic substrate, and thus on the efforts to maximize the capacity of the plant without exceeding the capacity of the pumps. This study assessed the potential to improve the overall efficiency of a full-scale co-digestion plant using thermally integrated membrane distillation (MD) and the possibility of recovering waste heat from the substrate sanitization process for use in the MD system. The results showed that reducing the TS content of recirculated reject water by MD could increase the loading, thus increasing biogas production by 45–50%, and that thermal integration with MD improved the overall energy efficiency of the integrated system. The thermal energy demand for the MD process was supplied by the low-temperature waste heat from the sanitization process (21%) and additional heat from a district heating (DH) network (79%). On using waste energy recovery, the energy demand to heat the reject water for MD was lower than the energy in the additional biogas production. Specific thermal energy demand for the MD system tested ranged from 800 to 1050 kWh/m3 without coolant-side heat recovery, but was only 116 kWh/m3 when heat recovery was possible. The concentration of nutrients from highly diluted reject water (>90% water content) reduced the storage requirement and transportation costs of the bio-fertilizer. The economic assessment indicated that thermal integration of a biogas plant with MD could be economically feasible. However, the lifetime of the MD modules and the impact of fouling need further study. [ABSTRACT FROM AUTHOR]

This study aims to explore the techno-economic potential of harnessing waste heat from a Small Modular Reactor (SMR) to fuel Direct Air Carbon Capture (DACC) and High Temperature Steam Electrolysis (HTSE) technologies. The proposed system's material flows, and energy demands are modelled via the ASPEN Plus v12.1 where results are utilised to provide estimates of the Levelised Cost of DACC (LCOD) and Levelised Cost of Hydrogen (LCOH). The majority of thermal energy and electrical utilities are assumed to be supplied directly by the SMR. A sensitivity analysis is then performed to investigate the effects of core operational parameters of the system. Key results indicate levelised costs of 4.66 $/kgH 2 at energy demands of 34.37 kWh/kgH 2 and 0.02 kWh/kgH 2 thermal for HTSE hydrogen production, and 124.15 $/tCO 2 at energy demands of 31.67 kWh/tCO 2 and 126.33 kWh/tCO 2 thermal for carbon capture; parameters with most impact on levelised costs are air intake and steam feed for LCOD and LCOH, respectively. Both levelised costs, i.e., LCOD and LCOH would decrease with the production scale. The study implies that an integrated system of DACC and HTSE provided the best cost-benefit results, however, the cost-benefit analysis is heavily subjective to geography, politics, and grid demand. • A sustainable energy system that combines direct air carbon capture and hydrogen production has been proposed. • Thorough techno-economic analyses provide valuable insights into its feasibility and potential. • By 2050, projected levelised costs are $40/tCO 2 for carbon capture and $1.50/kgH 2 for hydrogen production. • A comprehensive cost comparison offers valuable benchmarks against competing technologies. [ABSTRACT FROM AUTHOR]

Carbon capture and utilization (CCU) by methanation combines CO 2 capture and Power-to-Gas (PtG) routes, and could simultaneously realize excess clean energy storage and industrial flue gas carbon mitigation. However, a problem of large energy consumption is associated with the long-chain CCU-methanation process. In contrast, integrated carbon capture and utilization (ICCU) could largely reduce energy consumption by integrating CO 2 capture and methanation in just one reaction device. Although progressive work has been done on the development of ICCU-methanation, it still lacks of quantitative evaluation on the energy consumption and production cost. Herein, techno-economic analysis is conducted on calcium looping-based ICCU-methanation and the reference CCU-methanation. Results show that ICCU-methanation only requires 1/3 coal consumed by CCU-methanation to complete carbon capture of a 1000 MWe coal-fired power plant. When waste heat recovery is considered, the plant equipped with ICCU releases 83.6 kg CO 2 per 1 MWe h−1 of electricity comparing to 148.93 kg of CCU. Meanwhile, CH 4 cost by ICCU scheme is 837.1 € t−1, much lower than the 962.86 € t−1 of CCU. After taking the recovery of waste heat and carbon tax into account, the cost of CH 4 produced by ICCU becomes to be 443.26 € t−1, approaching the market price of natural gas (429 € t−1), showing a promising application perspective. • ICCU-methanation process based on calcium looping is simulated and evaluated. • ICCU-methanation only requires 1/3 coal consumed by CCU-methanation. • Cost of CH 4 produced by ICCU approaching the market price of natural gas. [ABSTRACT FROM AUTHOR]

Energy systems for flexibility in buildings are hybrid, primarily including rooftop photovoltaics (PV), cooling storage, and battery. Considering their techno-economic patterns, this research establishes an optimization model to determine the optimal technology portfolio and financial advantages of PV-battery-cooling storage systems for commercial buildings in China. The analysis of all cases indicates that cooling storage outperforms batteries in economic benefits, suggesting the prioritization of cooling storage installation. Once the optimal cooling storage rate is exceeded, it is advisable to proceed with batteries. Meanwhile, PV integration significantly enhances the system efficiency and promotes battery utilization. For example, a 40% PV penetration combined with a 0.006 $/(a·kWh e) energy storage investment results in an impressive 27.3% cost reduction in a Beijing mall, while the optimal cooling storage rate decreases from 55% to 40%. Furthermore, the study emphasizes the impact of tariff patterns and electricity demand on the economic feasibility of hybrid energy systems. The museum's substantial annual cooling requirements and nighttime loads make cooling storage favorable, with PV less suitable than the mall and office. Notably, cities like Beijing, Shanghai, Chongqing, and Guangzhou exhibit considerable peak-to-valley tariff differences, yielding higher economic benefits ranging from 23% to 27%. Finally, as battery costs decline and electricity price becomes more volatile, the battery would gradually replace cooling storage, especially when battery cost drops from 150 $/kWh to 70 $/kWh. [Display omitted] • Technology portfolio and cost savings of hybrid energy systems are optimized. • Application potential of PV-battery-cooling storage systems is discussed in China. • Cooling storage is prioritized due to economic performance compared to batteries. • PV integration enhances energy storage efficiency and promotes battery utilization. • Tariff patterns and electricity demand impact economic feasibility of hybrid systems. [ABSTRACT FROM AUTHOR]

Following the societal electrification trend, airports face an inevitable transition of increased electric demand, driven by electric vehicles (EVs) and the potential rise of electric aviation (EA). For aviation, short-haul flights are first in line for fuel exchange to electrified transportation. This work studies the airport of Visby, Sweden and the effect on the electrical power system from EA and EV charging. It uses the measured airport load demand from one year's operation and simulated EA and EV charging profiles. Solar photovoltaic (PV) and electrical battery energy storage systems (BESS) are modelled to analyse the potential techno-economical gains. The BESS charge and discharge control are modelled in four ways, including a novel multi-objective (MO) dispatch to combine self-consumption (SC) enhancement and peak power shaving. Each model scenario is compared for peak power shaving ability, SC rate and pay-back-period (PBP). The BESS controls are also evaluated for annual degradation and associated cost. The results show that the novel MO dispatch performs well for peak shaving and SC, effectively reducing the BESS's idle periods. The MO dispatch also results in the battery controls' lowest PBP (6.9 years) using the nominal economic parameters. Furthermore, a sensitivity analysis for the PBP shows that the peak power tariff significantly influences the PBP for BESS investment. • Quantified demand-increase for airport energy from electric aviation and vehicles. • Proposed novel value-stacking battery operation. • Quantified techno-economic analysis of varying battery operations. • Sensitivity analysis of battery payback period on investment cost and power tariff. [ABSTRACT FROM AUTHOR]

In light of the global energy and climate crises, integration of low-carbon technologies into energy systems is being considered to mitigate the high energy costs and carbon footprint. The wide range of available capacities, efficiencies, and investment costs of these technologies and their different possible operating schedules can unlock several pathways towards decarbonisation. This paper presents an optimisation framework for a public healthcare facility to determine the optimal operation schedule of the site's energy system. A detailed techno-economic analysis of low-carbon power generation, conversion, and energy storage technologies that can be incorporated into the system based on real historical data was carried out for different scenarios. The results reveal that a heat pump with a capacity of 1800 kW can replace gas boilers on-site to meet the heat demand while recovering the investment in 5 years and providing an operating and carbon cost saving of 22.47% compared to the base case. The analysis shows that a more electrified mode of operation is favoured during high gas prices, thus making electrical energy storage more attractive than thermal energy storage. While handling real data, the optimisation algorithm was sensitised to discriminate conventional energy supplies from clean energy sources by considering their carbon impact so that it minimises energy bills in a smart and eco-friendly way. The optimisation algorithm and the subsequent techno-economic analysis provide a comprehensive framework to decision-makers for facilitating energy investment decisions. The framework can be used based on the short and long term goals of the energy system, visualising the evolution of financial benefits over equipment lifetime, and understanding the environmental impacts of integrating renewable energy. • Heat pumps are the most favourable decarbonisation technology for the hospital. • The moderate variations in energy demand limit the scope of energy storage. • Fuel price surcharge favours EES over TES and reduces payback period of retrofits. • PVT's savings scale linearly with roof space until 3 times the available capacity. • Monetising the carbon footprint shortens the DPP of clean retrofit technologies. [ABSTRACT FROM AUTHOR]

Hydrogen (H 2) is considered a promising fuel and an energy carrier for carbon neutrality, but H 2 has an issue in transportation and storage due to its low volumetric density. H 2 liquefaction is an important technology in H 2 supply that can overcome the low density issues, but the system has a serious challenge of high energy consumption. Thus, an improved energy efficient 50 ton day−1 of H 2 liquefaction system comprising 4 mixed refrigeration cycles is proposed in this study. Especially, liquefied natural gas (LNG) was mainly used in the replacement of the precooling cycle, and the energy was saved by using the cold energy of LNG and generating electricity through vaporization. The specific energy consumption (SEC) of the proposed system was obtained as 3.996 kWh kg−1, however, particle swarm optimization (PSO) was implemented to increase energy efficiency of proposed process. As a result, the SEC of the optimized process was reduced to 2.917 kWh kg−1 where the LNG-cold energy control during the optimization was crucial to improve the energy efficiency. In addition, the economic and environmental feasibility were investigated. For the optimized process, the cost of the liquefied H 2 (LH 2) model was calculated as 1.37 $ kg-1, and 1.14 kg CO2 kg−1 LH2 emissions were recorded as a result of environmental assessment. Moreover, the uncertainty analysis was implemented to assess the degree of the cost variance and the possibility of H 2 production from water electrolysis was quantified. Unfortunately, electrolysis-based LH 2 was hard to be economically better than steam methane reforming-based H 2 , however, alkaline water electrolysis-based LH 2 showed the potential to overcome that of steam methane reforming in the future through technological advancement and reduction in production cost. The proposed H 2 liquefaction process has a highly improved energy consumption rate, and this process can contribute to developing the H 2 economy and become the potential candidate to overcome storage and transportation issues. • Feasibility study of large-scale hydrogen liquefaction technology is carried out. • Mixed-refrigerants and liquefied natural gas are utilized in refrigeration cycles. • Optimized and thermodynamically improved process lead to reduction in energy usage. • Economic feasibility and environmental impacts of liquefied hydrogen are estimated. [ABSTRACT FROM AUTHOR]

Electric-based methanol (e-MeOH) has the potential to substitute fossil-based hydrocarbons as the prominent feedstock in the production of climate-neutral synthetic fuels and organic chemicals because e-MeOH can be fully produced from renewable energy sources, such as solar photovoltaic (PV) and wind energy. It is basically produced via direct CO 2 -hydrogenation from captured CO 2 and electrolytic H 2. Although the techno-economics of the e-MeOH production process have been extensively studied, the published results have not included direct comparison of the reactor design configuration, different kinetic models, and exergy analysis. To assess the process performance, the e-MeOH plant is modelled and simulated in Aspen Plus® on the basis of the state-of-the-art Lurgi MegaMethanol® technology. The in-house tool TEPET (Techno-Economic Process Evaluation Tool) assists with the techno-economic analysis, including a sensitivity analysis regarding CO 2 and H 2 costs and an exergy analysis of the e-MeOH plant. With the recommended process configuration, the e-MeOH plant could achieve energetic and exergetic Power-to-Fuel (PtF) efficiency of 52.4% and 56.4%, respectively. The e-MeOH can be produced in 2018 at NPC 1129–1481 €t − 1 or 57–74 €GJ − 1. These values would be doubled if the e-MeOH plant operates exclusively with the help of solar and wind energy in Germany. The study also investigates the impact of different published kinetic models of methanol synthesis, which alter the NPC by around 2.3%. • Economic viability of e-methanol synthesis from German renewable electricity. • Investigation of the recommended reactor design configuration. • Techno-economic comparison of different kinetic models. • Identification of process inefficiencies through an exergy analysis. [ABSTRACT FROM AUTHOR]

Direct CO 2 electroreduction of flue gas is a technology that simplifies CO 2 capture and purification process and directly utilizes CO 2 in flue gas. Low CO 2 reduction reaction selectivity caused by the low CO 2 partial pressure and side reactions competition is the challenge. In this study, a direct CO 2 electroreduction system for multicomponent flue gases was established. A two-dimensional steady model was developed by considering major electrode reactions of flue gas in Cu x O-based catalysts. General influence criteria and optimum operation window for the potential, temperature, and pressure were proposed. In addition, a techno-economic analysis of the flue gas electrolysis system was conducted. The results demonstrated that the CO 2 electroreduction reaction performances are weak at atmospheric pressure owing to the side reaction competition and small reactant concentration. A method involving pressurization and catholyte inlet temperature declination is proposed to break the stalemate of tiny reactant concentrations and ensure the dominance of the CO 2 electroreduction reaction. The selectivity and current density of the CO 2 reduction reaction were 71% and − 148 mA/cm2 at −1.17 V vs. reversible hydrogen electrode potential (RHE), respectively, under the conditions of an inlet electrolyte temperature of 273 K and an operating pressure of 20 atm. C 1 products with excellent yields are the dominant products. Furthermore, the techno-economic analysis showed that the flue gas electrolysis system has higher profitability and lower cost than the purified CO 2 electrolysis system. The present results can be used to optimize the electrolyzer operating parameters and construct CO 2 reduction systems. • Direct CO 2 electroreduction system for multicomponent flue gas is established. • Performance and electrochemical conditions of flue gas electrolysis are analyzed. • Pressurization and temperature control are proposed to improve flue gas electrolysis. • Flue gas electrolysis is more economic and lucrative than purified CO 2 electrolysis. [ABSTRACT FROM AUTHOR]

Highlights • Applies over 400 real-world driver data from German commercial vehicles (LDV). • Quantifies cost-efficiency of longer battery ranges & fast charging infrastructure. • Fast-charging infrastructure increases utility of many drivers and is cost-efficient. • Longer ranges are needed for high BEV fleet shares. Abstract To reach ambitious CO 2 mitigation targets, the transport sector has to become nearly emission-free and the most promising option for passenger cars are battery electric vehicles (BEV) powered using renewable energy. Despite their important benefits, BEV still face technological barriers, mainly their limited battery range and the limited availability of public fast-charging infrastructure. These factors are hindering the diffusion of electric vehicles (EV). The question of how to address these technical barriers has been widely analyzed in the literature, but so far there has been no cost-efficiency comparison of longer battery ranges and more widespread fast-charging infrastructure that evaluates them both technically and economically. This paper aims to find cost-efficient ways to address limited battery ranges and availability of public fast-charging infrastructure. We focus on German passenger cars that are licensed to commercial owners, since these are an important first market for EV. Our results indicate that fast-charging infrastructure is very cost-efficient as it enables significant proportions of BEV in the fleet at low infrastructure density. The technically feasible maximum BEV shares in the commercial sector can only be achieved with longer battery ranges. However, longer battery ranges are currently associated with comparatively high additional costs. [ABSTRACT FROM AUTHOR]

Highlights • Economic feasibility of portable systems to utilize forest residues was investigated. • Forest residues were processed into raw and torrefied briquettes and biochar. • Minimum selling price (MSP) of biochar was estimated to $1044/ODMT. • MSP of raw and torrefied-briquettes were $162 and $274/ODMT respectively. • MSPs could be reduced by at least 50% with improved portable systems. Abstract Wildfires are getting extreme and more frequent because of increased fuel loads in the forest and extended dry conditions. Prevention of wildfire by fuel treatment methods will generate forest residues in large volumes, which in addition to available logging residues, can be used to produce biofuels and bioproducts. In this study, the techno-economic assessment of three portable systems to produce woodchips briquettes (WCB), torrefied-woodchips briquettes (TWCB) and biochar from forest residues were evaluated using pilot-scale experimental data. A discounted cash flow rate of return method was used to estimate minimum selling prices (MSPs) for each product, to conduct sensitivity analyses, and to identify potential cost-reduction strategies. Using a before-finance-and-tax 16.5% nominal required return on investment, and a mean transport distance of 200 km, the estimated delivered MSPs per oven-dry metric ton (ODMT) of WCB, TWCB, and biochar were $162, $274, and $1044 respectively. The capital investment (16–30%), labor cost (23–28%), and feedstock cost (10–13%) without stumpage cost were the major factors influencing the MSP of solid biofuels and biochar. However, the MSPs of WCB, TWCB, and biochar could be reduced to $65, $145, and $470/ODMT respectively with technologically improved portable systems. In addition, the MSPs of solid biofuels and biochar could be further reduced by renewable energy and carbon credits, if the greenhouse gas (GHG) reduction potentials are quantified and remunerated. In conclusion, portable systems could be economically feasible to use forest residues and make useful products at current market prices while simultaneously reducing potential wildfires and GHG emissions. [ABSTRACT FROM AUTHOR]

Graphical abstract Highlights • Representative pathway models for co-production of fuels and high-value co-products. • Economic sensitivity to co-products, policy, carbon prices, and methodology. • Cost tradeoff of $7.3 million capital to $1 million yr−1 operational at 10% IRR. • High capital of algal fuels requires significant co-product credits for economic viability. • WWT integration with algal growth represents economic challenge. Abstract This study presents an extensive systems-level multi-pathway sustainability assessment of algae biofuel production that demonstrates the necessity of high-value co-products, examines the impact of public policy scenarios, and identifies improvements and pathway directions required for economic viability. Engineering process models for several fuel and co-product pathways were leveraged to perform high fidelity techno-economic analysis. These pathways included: baseline hydrothermal liquefaction; protein extraction followed by hydrothermal liquefaction; fractionation into high-value chemicals with fermentation followed by hydrothermal liquefaction for fuels; and a small-scale first-of-a-kind plant coupled with a wastewater treatment facility. From these models, it was shown that hydrothermal liquefaction as a fuel-only pathway is not economically viable. Likewise, the benefits of coupling with wastewater water treatment are insignificant compared to the impact of reduced facility size resulting in increased capital costs. These models were also used to examine public policy scenarios, uniquely presenting their impact on the breakeven cost of fuel production and sensitivity to scenario assumptions. Specifically, depreciation type was shown to be irrelevant for writeoffs faster than 10 years. Due to discounting, short-term subsidies were found to capture 50% of the subsidy value in 6 years with an additional 24 years required for full subsidy valuation. Integration of a carbon economy was shown to decrease biofuel production costs, particularly for the protein pathway due to the co-product accounting. Finally, a metric of normalized costs was used to compare algal biorefineries to corn and cellulosic ethanol production, showing that algal systems are uniquely different due to significantly higher capital costs, though operational costs are comparable. This work demonstrates that, to reach economic viability, algal biofuel production must either utilize higher value non-fuel co-products or achieve drastic reductions in capital costs. [ABSTRACT FROM AUTHOR]

Highlights: • The techno-economic potential of offshore power generation with CCS is presented. • Two markets are considered: mainland electricity and offshore oil and gas facilities. • The techno-economic performances of the concept are compared to suitable references. • The impacts of technological improvements and case characteristics are discussed. • The concept has a strong economic potential to decarbonise offshore oil and gas facilities. Abstract This study investigates the techno-economic potential of offshore power generation from natural gas with carbon capture and storage to reduce the climate impact of mainland electricity and the offshore oil and gas industry. This potential is assessed through techno-economic assessments over two relevant cases ("floating" and "shallow water" cases) including comparison with relevant reference concepts. In the base case evaluation, the offshore power plant concept toward decarbonising mainland electricity results in high costs (178 and 258 $/MWh respectively for the floating and shallow water cases) compared to a reference onshore power plant with carbon capture and storage (around 95 $/MWh). However, a stronger potential is identified for the concept toward decarbonising offshore oil and gas platforms as the concept results in costs more comparable with the reference electrification concept (137 compared to 133 $/MWh in the floating case and 207 compared to 166 $/MWh in the shallow water case). Although the base cases show a limited potential for the offshore concept, the results show that with technological improvements (advanced capture technology, reuse of infrastructure...) and more suited case characteristics (development based on associated gas...), the offshore concept offers a significant potential for cost-efficiently decarbonising the offshore oil and gas industry, while a more moderate potential is foreseen for the decarbonisation of mainland electricity. [ABSTRACT FROM AUTHOR]

Highlights • Uncertainty in market prices drives financial outcomes. • Monte Carlo simulation allows uncertainty to be quantified. • Biochar-only production offers a potentially profitable venture. • Biofuel-biochar coproduction requires RINs to achieve financial success. Abstract A comparative techno-economic analysis of two different thermochemical biomass conversion pathways was conducted to examine the effects of fuel price and other variables on project financial performance. Monte Carlo simulation was used to quantify the effects of uncertainty and volatility of ten critical variables: biofuel, biochar and feedstock prices, discount rate, capital investment, labor cost, loan terms, feedstock drying, and biofuel and biochar conversion rates. Market prices for biofuel and biochar have the largest impact on net present value (NPV) of any variable considered, due in part to the high levels of uncertainty associated with future prices of both. Across the ranges of input values for these variables in simulation analysis, hearth-based pyrolysis biochar production had the highest likelihood of profitability with a mean NPV of $41.5 million and only 20% of outcomes resulting in a net loss, while 68% of outcomes for auger-based biochar-biofuel coproduction represented a financial loss, including a mean NPV of -$24.2 million. However, when additional revenue from Renewable Identification Numbers (RINs) credits generated by biofuel production is considered, financial outcomes of biochar-biofuel coproduction improve to 50% likelihood of experiencing a net loss. Findings of the very strong impact of market prices on financial outcomes, relative to other important technical and economic variables, can inform effective targeting of future renewable energy policy, as well as the design of future techno-economic analyses, which do not currently focus on the effect of market prices on profitability. [ABSTRACT FROM AUTHOR]

Highlights • Analysis on the cost-effectiveness of DC distribution in commercial buildings. • Lifecycle cost and payback period analysis using Monte Carlo simulation. • Evaluation for various solar and battery storage capacities. • Sensitivity analysis for future conditions. • DC can be viable in commercial buildings with DC loads, PV and storage. Abstract Improvements in building end-use efficiency have significantly reduced the energy intensity of new buildings, but diminishing returns make it a challenge to build very-low energy buildings cost-effectively. A largely untapped efficiency strategy is to improve the efficiency of power distribution within buildings. Direct current (DC) distribution with modern power electronics has the potential to eliminate much of the power conversion loss in alternating current (AC) building distribution networks that include photovoltaics and DC end uses. Previous literature suggests up to 15% energy savings from DC power distribution in very energy efficient buildings with onsite generation and battery storage. This paper extends prior energy modeling of DC versus AC distribution in buildings, to consider the cost of implementing DC systems on a life-cycle basis. A techno-economic analysis framework based on commercially available products that evaluates the cost-effectiveness of DC systems is presented. The analysis is conducted for three commercial building types in two California climate zones and for various PV and battery storage capacities. Monte Carlo simulation is used to compute the payback period and lifecycle cost savings of DC versus AC distribution systems. A future-market scenario is also examined, which evaluates how future efficiency improvements in power converters and changes in electricity tariffs may affect cost savings. This analysis shows that DC systems can be cost-effective in all scenarios that include large capacities of battery storage and onsite solar, whereas for systems without storage, DC distribution is generally not cost-effective. [ABSTRACT FROM AUTHOR]

Highlights • Proposed novel chemical looping process for H 2 and NH 3 co-generation by coke-oven gas. • Conducted main parameters optimization and technical analysis for the process. • The process achieved 68.5–73.6% exergy efficiency and 100% CO 2 capture efficiency. Abstract The coke-oven gas direct chemical looping hydrogen generation is a promising process for chemical industry; however, it still suffers from high energy consumption and low hydrogen production. The chemical looping-derived H 2 and N 2 can be used to produce ammonia. Therefore, a new process for coke-oven gas chemical looping hydrogen and ammonia co-generation integrated with pressure swing adsorption technology, which can flexibly adapt to market demand, is proposed in this paper. The new process has two extreme configurations to produce hydrogen or ammonia only. A thorough analysis of key operational parameters of the proposed systems has been conducted to optimize coke-oven gas utilization, and maximize hydrogen and subsequent ammonia production. The maximal hydrogen and ammonia productions are 7126 and 4784 kmol/h of 5532 kmol/h coke-oven gas consumption for the two extreme configurations, respectively. Moreover, an exergy efficiency of 68.5–73.6% and about 100% direct CO 2 capture efficiency are obtained when switching between hydrogen and ammonia production in the novel process. These values are compared to those of the coke-oven gas chemical looping hydrogen generation process (hydrogen production of 6613 kmol/h per 6276 kmol/h coke-oven gas consumption, 66.0% exergy efficiency, and 73.3% CO 2 capture efficiency). Finally, the economic and sensitive analyses of the novel process are also conducted in this paper. [ABSTRACT FROM AUTHOR]

Highlights • Optimizations of 3 compound power cycles have been carried out thermodynamically. • Five maps are obtained for selecting optimum geothermal power generation cycles. • Different ORC working fluids are investigated in generating the maps. • Techno-economic performance of each power cycle has been analyzed in detail. Abstract Both thermodynamic performance and techno-economic analysis of compound power cycles for enhanced geothermal systems have been investigated in this study. Thermodynamic analysis were carried out for four power generation systems: single-flash (SF) system, double-flash (DF) system, flash-ORC (FORC) system; and double-flash-ORC (DFORC) system. By choosing the maximum net power output as an objective function, optimization is done based on comparisons among the four systems with a goal of increasing the net power output by 20% under the condition that the SF is replaced by one of the compound systems (DF, FORC, and DFORC). As an original contribution, five maps useful for real applications have been generated for selecting optimum geothermal power cycles under different geofluid's conditions, with consideration of five ORC working fluids (R123, R152a, isobutane, n -pentane and R245fa). The boundaries that determine whether the compound systems have advantages over the SF system are functions of the geofluid temperature, geofluid dryness, and the type of the working fluid used by the ORC. In the techno-economic study, Levelized Electricity Cost (LEC) and Payback Period (PBP) analyses were carried out. The results from the LEC and PBP studies show good agreement. For the three scenarios analyzed, each of the compound power systems has a better engineering economic performance than the SF system. For the "common" heat source condition investigated, comparison among the three compound systems shows that the DF system has a lowest levelized electricity cost and the shortest payback period; the FORC and DFORC show similar techno-economic performance and have advantages over the SF system. [ABSTRACT FROM AUTHOR]

Highlights • Modeling of coal-to-liquids (CTL) process with different entrained flow gasifiers was conducted. • Thermodynamic analysis of CTL process was presented. • Locations and magnitudes of exergy inefficiencies were identified and quantified. • Techno-economic and CO 2 emissions analysis of CTL process were conducted. Abstract For the coal-to-liquids (CTL) plant, the most important unit is gasification, which determines the composition of the crude syngas, and affects CO 2 emissions and investment of the CTL process. This paper conducts a detailed plant-wide modeling of CTL process with different entrained flow gasifiers. The model is compared with the literature data. Three cases of CTL process with different entrained flow gasifiers (GSP, Shell and Texaco) are researched through thermodynamic, techno-economic and CO 2 emissions analysis. Case GSP represents the CTL process with GSP gasifier, Case Shell represents that with Shell gasifier, and Case Texaco represents that with Texaco gasifier. For a typical CTL process, Case GSP can produce FT liquids of 277.49 t/h, Case Shell can produce 246.25 t/h, and Case Texaco can provide 232.93 t/h. The energy efficiencies of Case GSP, Shell and Texaco are 50.85%, 48.18% and 41.09%, respectively. The exergy efficiencies are 49.89%, 47.20% and 40.44%, respectively. The exergy inefficiencies of the subsystem are quantified. The economic performance and CO 2 emissions of the three cases are also discussed. [ABSTRACT FROM AUTHOR]

Highlights • A techno-economic analysis of battery system at two different locations in Almeria (Spain) and Lindenberg (Germany). • The impact of changing orientation on SC, DA and LCoE in Germany is investigated. • The study is done at two different tilt angles, near to the optimum values for the two locations at south orientation. • The higher load profile is found to play a key role in increasing SC. • A trade-off still has to be made between increasing self-consumption and achieving cost reduction for the coming 20 years. Abstract The techno-economic analysis investigates first the impact of tilt angle and orientation on the production profile of a rooftop solar generator and the related performance of a photovoltaic battery storage system for single family houses at a specific location in Germany. Then, a technical comparison to a different location in Almeria in Spain is performed. The calculations are model-based and take into consideration the consumer load profile, technical and economic photovoltaic battery storage system parameters as well as the framework of regulations for the case of Germany. The parameters “share of self-consumption”, “degree of autarky”, and “economic efficiency in terms of levelized cost of electricity” make up the focus of the modelling results. It is concluded that self-consumption and degree of autarky are strongly and inversely related. In terms of system design, a trade-off has to be made between aiming for high self-consumption and a high degree of autarky. Key findings from the modelling results reveal that in Lindenberg in Germany, a south orientation gives the highest degree of autarky and the lowest levelized cost of electricity, but with the lowest share of self-consumption as well. For rooftops oriented towards east/west, an interesting possibility could be to split the total installed capacity (equally) between the two orientations. This makes it possible to benefit from the high self-consumption of the east orientation and the high degree of autarky of the west orientation. In general, it has to be considered that the optimum orientation strongly depends on the consumer load profile. The technical analysis shows that changing the location to Almeria increases degree of autarky and decreases share of self-consumption for south orientation with different magnitude that depends on the load profile. Finally, the results show opposite impacts that depend on orientation and location when switching from a tilt angle of 30° to 45°. For a south orientation in Almeria and Lindenberg, the degree of autarky is increased when approaching the optimum tilt angle, while for west and east orientations in Lindenberg self-consumption increases. [ABSTRACT FROM AUTHOR]

Highlights • Process design and techno-economics of pilot bio-jet fuel facility were studied. • Yields of furfural, LA, intermediate, bio-jet fuel were 59.5%, 34.4%, 75% and 51%. • 47.6% energy and 31% carbon of carbohydrate in corncob is recovered in bio-jet fuel. • TCP, OPEX and MSFB (no tax) was $3.96 MM, $1.18/L and $1.45/L for a 1.3 ML/a facility. • Economies of scale on MSFB is obvious when the discount rate increases and taxes impose. Abstract Process design and techno-economic analysis of a pilot bio-jet fuel production facility were investigated using Aspen plus software and net present value method (NPV). This process include two-step hydrothermal decomposition of corncob to furfural (steam stripping of hemicellulose) and Levulinic acid (LA, acidic hydrolysis of cellulose), oxygenated precursor production via aldol condensation reaction of furfural and LA, and the subsequent hydro-processing for oxygen removal. Lab experiments on the major area of the process were carried out. The yields of furfural, LA, oxygenated precursor and bio-jet fuel-range hydrocarbons (C 8 –C 15 ) were 59.5% (based on hemicellulose), 34.4% (based on cellulose), 75% (based on furfural and LA input) and 51 wt% (based on precursor) respectively. These values were used as the input information for the process simulation of a first-of-a-kind pilot facility for 1.3 ML/a bio-jet fuel production using this pioneering technology. The mass and energy analysis from Aspen plus model shows that the bio-jet fuel yield was 0.125 tonne/tonne dried corncob. 31.0% of carbon atoms and 47.6% of potential energy from carbohydrate compounds of corncob leave as bio-jet fuel. The estimated consumption of water, steam and electricity is relatively high of 12.3 kg, 63.7 kg and 1.22 KW h respectively due to small simulation scale and lack of process optimization. The total capital cost was ca. $3.96 MM for the 1.3 ML/a facility, of which 28% of equipment investment is spent for oxygenated precursor production. The total operation expense (OPEX) is $1.18/L bio-jet fuel, including variable and fixed costs. Expenses on corncob, catalytic catalyst and H 2 contribute 23%, 19% and 16% respectively. Single point sensitivity analysis of the major breakdown of OPEX shows that catalyst lifetime is the priority factor. Economy of scale of minimum selling price of bio-jet fuel (MSPB) for different capacity facilities (1.3 ML/a, 6.5 ML/a and 13 ML/a) was investigated using different discount and tax rates, of which the lowest MSPB was $0.74/L with a subsidy of $0.31/L at 10% discount rate. [ABSTRACT FROM AUTHOR]

Biogas has been considered as an alternative renewable energy, and CO 2 removal from raw biogas (i.e. biogas upgrading) is needed for producing biomethane to be used as vehicle fuels or injected into the natural gas grid. Biogas upgrading with physical absorbents, such as water and other commercial organic solvents, is simple, efficient and with low energy requirements for regeneration. Recently, deep eutectic solvents (DESs) with nonvolatility, nonflammability and low price have been reported as promising alternatives to replace conventional physical absorbents in many research areas including biogas upgrading. However, the performances of these physical solvents including conventional physical absorbents and DES-based solvents have not been evaluated and compared with each other. In this work, the properties of 4 physical solvents (i.e. water, dimethyl ether of polyethylene glycol (DEPG), propylene carbonate (PC), and aqueous DES (AQ DES )) were compared. Furthermore, a conceptual process was developed to upgrade biogas with these solvents and simulated based on Aspen Plus in order to conduct performance comparison. The simulation results of energy utilization, the amount of recirculated solvents and the diameters of absorber and desorber were analyzed and compared based on equilibrium and rate-based approaches, respectively. The simulation results based on the rate-based approach were further used to estimate the costs of biogas upgrading process with a same raw biogas capacity for comparison. Meanwhile, the specific cost of biogas upgrading process with a same size of equipment was also evaluated. The results show that the CO 2 solubility, selectivity and viscosity are three more important properties, providing valuable information for developing novel physical solvents for CO 2 separation. The simulation results show that the equilibrium and rate-based approaches result in different conclusions, especially when the solvent viscosity is relatively high, and the rate-based approach is preferable. Based on the simulation results from the rate-based approach, the performances of AQ DES and PC are similar with a same amount of energy utilization, that is around 11% lower than water, and DEPG is inferior to water. For the case with the same gas capacity, the total annual costs of biogas upgrading process with these solvents show the following order: DEPG > AQ 60wt.%DES  > water > AQ 50wt.%DES  ≈ PC. For the case with the same size of equipment, compared to water, the total specific costs of biogas upgrading process with PC and AQ 50wt.%DES decrease by about 30% and 45%, respectively, and the treated biogas capacities increase to 1.5 and 2 times, respectively. In general, both PC and AQ 50wt.%DES show better performance than the other solvents. Considering that DES is an environmentally benign solvent, and the performance of DES can be greatly improved by further designing, it is more promising. [ABSTRACT FROM AUTHOR]