Search Results (404)

Off-grid agricultural cold chains suffer from high energy conversion losses due to intermediate electrical stages in traditional refrigeration. This study addresses the lack of empirical quantification by comparing Direct Mechanical Drive (DMD) and Electrical Power Generation (EPG) drive trains for an R-134a vapor compression refrigeration system. Under steady-state conditions (randomized block design), DMD achieved a statistically significant 13.89% reduction in biomass consumption over EPG (1840.0 vs. 2136.7 g/h; p < 0.001). The biomass consumption was evaluated based on the measured charcoal mass flow under the same lower heating value basis. Conversely, refrigeration COP was statistically equivalent (2.74 vs. 2.73; p = 0.815), confirming that drive-train architecture does not alter internal vapor compression thermodynamics. Only 19.6% of the compressor shaft power appeared as useful fluid-side compression work under this fractional-load operating condition, a volumetric rather than mechanical deficiency arising from operation at 7.7–15.5% of the compressor’s rated capacity. Referenced consistently to the primary biomass chemical energy input, the First-Law biomass-to-cooling system efficiency was 3.66% (equivalent to 5.34% when referenced to the syngas delivered to the engine), with a corresponding biomass-referenced exergy efficiency of 0.44%. Component exergy analysis revealed that the internal combustion engine (59.13% of total exergy destruction, ε = 13.1%) and the gasifier (32.4%, ε = 67.7%) dominated total system exergy destruction (15.49 kW). Furthermore, a 10-year life-cycle cost (LCC) analysis indicates DMD-Syngas yields net present value savings of 21,071.57 USD over gasoline-EPG, yielding a 0.14-year (~50-day) simple payback period on the 400.12 USD net incremental hardware capital cost (the gasification subsystem less the alternator–motor drive train that the direct-drive configuration does not require, and excluding one-time installation and training costs). When the fully installed cost is accounted for—including site preparation, process-water supply and effluent handling, low-voltage provision, installation labor, operator training and contingency—the incremental investment rises to 1298–2405 USD and the payback period extends to approximately 162–301 days. Under the least favorable combination examined, in which commercially purchased charcoal is imposed simultaneously with the upper installed-cost bound, capital recovery extends to approximately 1.4 years; the base case nevertheless recovers the incremental investment within the first operating year. An operational-phase (gate-to-gate) carbon assessment indicates near parity with the gasoline baseline on a strictly attributional basis (+120 to +1200 kg CO₂e yr⁻¹); a net saving of 8880–13,320 kg CO₂e yr⁻¹ arises only under the consequential scenario in which open-field burning of orchard residues is displaced and is further contingent on including black carbon in the accounting basket. This is not a full ISO 14040/44 life-cycle assessment, and the environmental outcome is therefore scenario-dependent rather than intrinsic to fuel substitution. These results demonstrate that mechanical drive-train optimization substantially enhances fuel economy without compromising refrigeration performance, providing a rigorous evidence base for scalable biomass-powered off-grid cold chains. Full article

Rail stations have non-traction electricity and heat demands, requiring coordinated renewable generation, storage, and conversion. We develop a cloud–edge–terminal energy-management framework for an electricity–hydrogen–thermal system. A 24 h mixed-integer linear programming model schedules grid import, photovoltaic (PV) generation, battery and thermal storage, electrolysis, hydrogen compression and storage, and fuel-cell and heat-pump operation. Hydrogen inventory is represented by stored hydrogen mass, with tank pressure linked to hydrogen density through a pressure–density relation. We compare three systems: hydrogen-free, hydrogen-integrated, and hydrogen-free with electrically equivalent battery storage. Hourly schedules map 150 capacity-equivalent virtual terminals for minute-level verification under operational and communication disturbances. Hydrogen integration reduces objective value by 1.06%, operating cost by 0.34%, and peak grid import by 6.89% relative to hydrogen-free operation but increases daily grid electricity purchase and CO₂ emissions by approximately 3.09%. Sensitivity analyses show stronger benefits at higher PV penetration, negligible gains from tank-volume expansion beyond the storage range, and electrolyzer power as the constraint on renewable absorption at high PV capacities. Verification achieves a 98.503% average command–delivery success rate, a steady-state grid import error below 1 kW, and 2 min to self-heal faults. Hydrogen improves peak shaving and intertemporal energy shifting, whereas total electricity use and emissions depend on renewable availability and conversion limits. Full article

The evaluation of the effectiveness and sustainability of decarbonization measures, especially but not only through electrification, is not trivial. Combustion technologies improve by small amounts year to year and as the emission factors of fuels can be considered constant across European countries; however, the emission factors of electricity generation are not uniform among countries and do not share a common trend in their evolution over time. These two aspects, the different evolution trends of electricity emission factors and the non-uniformity of these factors among countries, can lead to unexpected results: under/overestimation of carbon savings and sustainability in the long-term forecast in the massive technologic transition in both the civil and industrial sectors. This paper, using trend observations and the Myopic model, highlights possible biases in the long-term projection of CO₂ emissions savings in the industrial sector. This study focuses on a comprehensive investigation of the integration of a high-temperature heat pump into a combined cooling, heating, and power plant. A detailed assessment of the system’s energy performance is conducted through steady-state simulations under both fixed boundary conditions and annual operational scenarios, addressing building heating, cooling, and electrical requirements across varying electricity emission factors for different European countries and evolution trends until 2050, with the results compared with conventional energy production systems. Full article

The efficacy of low-carbon power systems is reduced by the high energy demand of conventional CO₂ capture processes, the loss of recoverable thermal energy, and power-quality disturbances associated with variable renewable generation. This study suggests an integrated framework that integrates membrane-assisted CO₂ capture, thermoelectric waste-heat recovery, photovoltaic generation, battery energy storage, and a grid-connected converter to address these issues. During the capture of CO₂, the waste heat is converted into electrical energy using a thermoelectric generator and integrated with the photovoltaic and battery outputs through a common DC link. A conventional phase-locked loop is not necessary for reference-signal extraction, DC-offset rejection, harmonic compensation, and power management, as an Enhanced Notch Filter-Based Second-Order Generalized Integrator (ENF-SOGI) controller is employed. The effectiveness of the proposed system is demonstrated by simulation and experimental studies conducted under variable irradiance, nonlinear loading, distorted-load, and distorted-grid-voltage conditions. The membrane unit achieves a CO₂ capture efficiency of approximately 92%, with a specific energy consumption of 1.2 GJ/tCO₂. The controller reduces the source-current total harmonic distortion from 24.3% to approximately 1.2–1.3%, limits its experimental variation to ±5 V, and maintains the DC-link voltage at approximately 600 V. Consequently, the proposed architecture is designed to facilitate low-carbon grid operation by integrating a unified energy-management system that includes high-efficiency CO₂ separation, the productive recovery of waste heat from the capture process, increased renewable energy utilization, and IEEE-compliant source-current quality. Full article

This paper presents a detailed analysis of the operating parameters of a solar active installation with seven photovoltaic-thermal (PV/T) collectors with a total area of 14 m² in a single-family house. A comparative analysis of the work parameters was carried out for the following two locations: Warsaw (Poland) and Andravida (Greece), based on the research of the solar system model created in the TRNSYS 16 program. Considering the months with the best sunshine, from May to August, the average monthly electricity yield in PV/T solar collectors was 206 kWh (Warsaw) and 248 kWh (Andravida). In July, the monthly generation-to-consumption ratio of the PV/T system under the Polish climate conditions was 82%, and under the Greek climate conditions—99%. The heat recovery from PV/T solar collectors in July in the climate of Greece was estimated at 264 kWh and is 29% higher compared to the heat recovery in a hybrid solar installation located in Poland. The generation of electricity in the PV/T solar system instead of a coal-fired power plant can contribute to the avoidance of the annual emissions of pollutants by: 14.00–19.11 kg of SO₂, 2.72–3.72 kg of NO_X, 5.44–7.43 kg of CO, 1330.86–1816.79 kg of CO₂, and 1.09–1.49 kg of particulate matter, depending on the location. Full article

This study investigates the integration of CO₂/H₂S separation and internal power generation in power- and biomass-to-liquid (PBtL) and fuel-assisted PBtL (FAPBtL) processes to enhance carbon efficiency and reduce external electricity demand. Four configurations (PBtL, FAPBtL-recycle, FAPBtL-purge, and Purge-to-Fuel (Purge-tF)) are evaluated through detailed mass and energy balances, thermal integration analysis, and techno-economic assessment. Reintegration of separated CO₂ eliminates carbon losses in the acid gas removal unit, increasing carbon efficiencies to approximately 98% for PBtL and Purge-tF, 97% for FAPBtL-recycle, and 79% for FAPBtL-purge. Increasing the carbon efficiency from 91% to 98%, for PBTL, comes from capturing 85% of the CO₂ downstream of the acid gas removal unit. In parallel, integration of a supercritical two-step reheat Rankine cycle with preheating enables the recovery of high-temperature process heat, increasing cycle efficiency from 42% to 55% and generating up to 61 MW of internal power. Although CO₂/H₂S separation introduces additional capital and energy requirements, the combined integration of carbon recycling and heat-to-power recovery improves overall system performance. The Purge-tF configuration achieves the lowest net production cost of 2.60 €/kg_fuel (2.11 €/L_fuel). Sensitivity analysis confirms electricity price as the dominant economic driver. The results demonstrate that strategic integration of carbon recycling and advanced heat recovery can substantially improve both the carbon utilization and economic viability of biomass-based synthetic fuel production. Full article

The sizing of rooftop solar energy systems is commonly based on the most visible load or on generic end-use allocations, leading to an inadequate distribution of the limited rooftop area between heat and electricity. This study formalizes the energy audit within a three-level deterministic framework that selects and sizes solar technologies by energy vector: demand is first decomposed by vector; the technology for the thermal vector is then selected through a levelized cost of heat selection ratio $\psi$, while the photovoltaic system of the electrical vector is sized for self-consumption; and the rooftop area is finally allocated among vectors according to marginal value per unit area. In a 75-bed university residence in Cienfuegos, Cuba, air conditioning is the dominant energy end-use in terms of installed power (accounting for $77\%$ of the connected load), whereas the thermal vector dominates annual energy consumption (domestic hot water: 127,440 versus 76,818 kWh/year for electricity; thermal-to-electric ratio $1.66$). Solar thermal technology has been selected for the thermal vector ($0.018$ versus $0.088$ USD/kWh_th; $\psi =0.21$, a robust value according to the sensitivity analysis), and the marginal value (≈111 versus ≈32 USD/(m²·year)) allocates 104 m² to solar thermal collectors and 134 m² to photovoltaic energy, thereby reversing the original design that prioritized photovoltaic energy. The resulting portfolio achieves an annual solar fraction close to $100\%$ in both vectors on an energy balance basis, avoids $86.5$ t of operational CO₂ emissions per year, and combines a simple payback of $1.1$ years (solar thermal) with a net present value of 55,327 USD and an internal rate of return of $28\%$ (photovoltaics). The sizing decision is shown to be robust to the choice of statistical design criterion (median, mean, P90, maximum), and none of the three framework decisions is reversed under $\pm 30\%$ parameter variations. By replacing the subjective weightings of multi-criteria methods with observable economic criteria, the framework provides a replicable and auditable design protocol. Full article

Rankine cycle CO₂ pumped thermal energy storage (R-CPTES) offers high-density, emission-free grid storage, but existing designs are limited by modest turbine inlet temperatures and produce electricity only, leaving their thermal potential unused. This paper introduces a Rankine CO₂ storage cycle driven by a high-concentration parabolic dish collector (PDC) and configured solely for combined heat and power, representing a combination of point focus solar energy with CO₂ pumped thermal storage that has received limited attention in the literature. During discharge, the dish superheats the working fluid and raises the high temperature turbine inlet from 456 °C to 500 °C, boosting net power. A heating recovery exchanger placed ahead of the second regenerator then extracts useful heat from the turbine exhaust for district or process supply, without the absorption refrigeration subsystem used in comparable cooling inclusive designs. The aim is to characterise this system through energy, exergy, and parametric analysis. A closed, pinch-consistent model is developed under steady-state assumptions using the Span–Wagner equation of state, with the discharge low pressure, discharge mass flow rate, and PDC outlet temperature varied independently and jointly at a fixed 10 MPa high-pressure boundary. The analysis reveals a power-versus-heat trade-off governed by the discharge pressure and bounded by physical limits rather than interior optima, shows that the solar superheat is a prerequisite for cogeneration, and identifies the system as heat-transfer destruction dominated, with the latent cold storage the largest single source of irreversibility. At the design point the system delivers 16.1 MW of power and 2.5 MW of heat, attaining a storage round-trip efficiency of 73.2% (electricity-only), a solar-inclusive electrical efficiency of 58%, an energy utilization factor of 67%, and an overall exergy efficiency of 61.3%. A preliminary economic assessment gives a levelised cost of storage of 0.10–0.18 $/kWh, competitive with comparable CO₂ storage systems. The proposed system thus provides a simple, fossil-free cogeneration solution for high-DNI regions based on a modular, point focus solar configuration. Full article

Traditional fossil-fuel-based industries, including electric power generation and petrochemical production, are plagued by their inherent carbon dioxide emissions. Current efforts to minimize CO₂ discharge tend to focus on costly capture and sequestration rather than utilizing the process energy and products to produce profitable chemicals. This work describes a concept and design strategy for a comprehensive facility to convert natural gas and air to carbon monoxide, which could be further used to synthesize desirable compounds and fuels. The basic components of the process are an improved supercritical carbon dioxide (sCO₂) electric power plant for driving solid-oxide electrolysis cell (SOEC) reduction in CO₂ to CO. This study examines opportunities for integrating a sCO₂ process with an associated air separation unit (ASU) and an SOEC, including material recycling and heat integration. A Life Cycle Assessment (LCA) is expected to show more positive results than for separate processes. Preliminary economic evaluations provide a profitable process and product route for the combined process, suggesting that carbon emission reduction could be good business. Full article

Energy industrial zones can act as a transformative model for industrial decarbonization by integrating renewable energy infrastructure directly with industrial production. By combining energy industrial zones with the energy community framework and peer-to-peer (P2P) energy trading, this study proposes a pathway toward 100% renewable energy sources. The model was tested using a techno-economic assessment applied to the Bravar-Jasenice case study in Croatia featuring 12 MW of solar PV, 10 MW of wind power, and a 9.3 MW biogas cogeneration plant. This integrated approach can achieve 80–90% energy self-sufficiency and reduce electricity expenditures for participating enterprises by approximately 15%. Furthermore, the system facilitates an annual reduction of roughly 20,000 tonnes of CO₂ emissions, thus directly supporting European Green Deal objectives. The study also highlights the potential for industrial symbiosis, including green hydrogen production, data centre integration, and waste heat recovery. Ultimately, the proposed framework provides a robust strategy for enhancing industrial competitiveness and ensuring energy security through localized, sustainable energy management. Full article

The increasing penetration of variable renewable energy sources (RESs) poses significant challenges to power system flexibility and reliability, particularly in systems with high solar generation. At the same time, existing Concentrating Solar Power (CSP) plants in Europe face declining economic viability due to high capital costs and the expiration of incentivized tariff schemes. This study proposes and evaluates a novel approach to repurpose CSP plants as flexible energy assets through the integration of cold thermal energy storage (CTES) within a Thermally Integrated Power-to-Heat-to-Power Energy Storage (TI-PTES) framework. The proposed system combines an ice/water-based cold storage with a CO₂-based refrigeration cycle to enhance the efficiency of the CSP steam cycle by reducing condenser temperatures, while also enabling temporal shifting of electricity consumption. A techno-economic optimization model based on PyPSA is developed to determine the optimal sizing and operation of the storage and refrigeration system under realistic load and electricity price conditions representative of the Spanish market. Results show that the integration of cold storage significantly alters system operation, shifting the chiller from a continuous demand-following mode to an intermittent, high-intensity regime. This leads to a reduction in annual operating expenditures by approximately 32% and an increase in annual profit and net present value (NPV), despite higher capital investment. While hourly net revenue becomes more volatile, with negative values during charging periods, cumulative annual performance improves due to effective temporal optimization. However, the absence of strong electricity price arbitrage and negative price signals limits the revenue potential of the storage system, which primarily acts as a cost-reduction mechanism. The findings demonstrate that cold thermal storage can successfully reposition CSP plants as flexible, value-generating assets in modern electricity systems. The proposed concept offers a promising pathway for extending the operational lifetime of existing CSP infrastructure while supporting higher integration of renewable energy sources. Full article

Used engine oil (UEO) is a hazardous waste stream that poses significant environmental risks when improperly managed. However, its high heating value makes it a promising candidate for energy recovery. In Kuwait, rising vehicle ownership has led to increasing quantities of UEO, while the power sector remains heavily dependent on conventional fossil fuels. Although extensive research has examined UEO treatment methods and combustion characteristics, limited attention has been given to its integration into utility-scale power-generation systems. This study presents a national-scale techno-economic and environmental assessment of using UEO as a supplementary fuel for electricity generation in Kuwait. East Doha Power Station was selected as a representative case study to evaluate fuel-substitution potential and the practicality of integrating UEO into existing power-generation infrastructure. Historical vehicle-registration data were used to estimate UEO generation, and future availability was projected through 2035 based on vehicle-growth trends. The corresponding thermal energy potential, equivalent electricity generation, fuel-displacement capacity, economic benefits, and environmental impacts were subsequently evaluated. The results indicate that annual UEO generation is projected to increase from approximately 181,800 tonnes/year in 2024 to 303,300 tonnes/year in 2035. This quantity corresponds to about 12,126 TJ/year of recoverable thermal energy and an equivalent electricity-generation potential of approximately 1.1 TWh/year (4000 TJ/year), assuming a power-plant efficiency of 33%. The recovered UEO could displace approximately 311,000 tonnes/year of heavy oil or 287,000 tonnes/year of crude oil, with estimated net annual fuel-cost savings of approximately 28–30 million KD. Based on literature-reported emission factors, UEO utilization could reduce combustion-related CO₂ emissions by up to 19.0% and NO_x emissions by up to 45.5% compared with heavy oil. Sensitivity analysis further confirmed the robustness of the findings under a range of recovery and operating conditions. To the best of the authors’ knowledge, this study represents the first comprehensive national-scale assessment of the potential use of UEO for utility-scale power generation in Kuwait. The findings indicate that UEO has the potential to serve as a strategic secondary energy resource that supports waste reduction, fuel conservation, economic savings, and circular-economy objectives. However, practical implementation will require appropriate collection and treatment infrastructure together with further technical validation, pilot-scale demonstration, and regulatory evaluation. Full article

There has been a rising trend for recovering waste heat, especially after the invention of new types of semiconductors. Among all available utilization options, thermoelectric generation (TEG) systems are promising for recovering waste heat. Thermoelectric devices are environment-friendly, operate silently, and are suitable for low- to high-power applications. This review paper presents a comprehensive study of TEGs, starting with the current problem, state of the art, advantages, disadvantages, generation and related principles, and applications, and covers different arrangements (individual and combined) and working fluids. Furthermore, this article systematically covered various experimental and numerical studies, including optimization, offering insights into heat exchanger configurations, working fluids, and performance parameters. Here, an effort is made to describe the contributions of individual/coupled TEG systems. As a coupled system, the individual TEG system is used with other systems like solar, distillation, solar pond, etc., for cogeneration and enhanced efficiency. The thermal/system parameters of individual/coupled systems are thoroughly discussed, and their impact on efficiency and power generation is illustrated. It was found that the design of the heat exchanger configuration varies from plate type to an efficient liquid-based electricity generation system in these TEG systems. The working fluid inside the fluid loop of a thermoelectric generation system varies from simple fluids to nanofluids. The current state of thermoelectric generation technology is facing challenges in module materials, equipment cost optimization, and commercialization. The progressive TEG generation capabilities have improved with recent advancements in these areas. The power densities are increasing from 0.5 to 1.2 W/cm² in earlier standalone TEGs to 2.5–4.8 W/cm² in recent optimized hybrid configurations, and overall system efficiencies are rising from an average of 5.2% (standalone) to 18.7% in coupled solar-TEG or waste heat recovery systems. The reported maximum ZT values are also improved from ~1.2 to 2.1–2.8 in next-generation materials. Liquid-based heat exchangers in conjunction with nanofluids are the most efficient way to maximize temperature gradient coefficient (0.75–0.92) and minimize parasitic losses. While flexible, ionic, and hybrid next-generation material platforms are still in the early phases of development (TRL 3–5), liquid-based heat exchanger systems improved with nanofluids are closest to commercialization (Technology Readiness Level, TRL 6–8). Therefore, further research in these areas is required to mitigate these challenges. Finally, the recent developments in the thermoelectric generation field and future research direction are briefly discussed. Full article

This study addresses the technical, environmental, economic, and systemic role of multi-apartment residential buildings as hydrogen consumption nodes within urban energy systems. A representative five-story building comprising 30 apartments and 2400–2800 m² of heated floor area, located in a cold European climate, was modelled with an annual heat demand of approximately 185,000 kWh. Four heating configurations were assessed: a conventional natural gas/biomethane boiler (baseline), a hydrogen boiler, a hydrogen-fuel-cell combined heat and power (CHP) system, and a hybrid heat-pump–hydrogen solution. Dynamic simulations indicate that all hydrogen-based systems can fully satisfy space heating and domestic hot water demand without modifications to the internal hydronic distribution network. The fuel cell CHP achieved an overall efficiency of 93%. It generated approximately 54,000 kWh/year of on-site electricity, while the hybrid configuration reached a seasonal efficiency of 108% and the highest primary energy reduction (46%). Operational CO₂ emissions decreased from 37,800 kg/year (gas baseline) to 1900 kg/year (green hydrogen boiler), 1200 kg/year (fuel cell CHP), and 900 kg/year (hybrid system), corresponding to reductions of up to 98%. Peak-load analysis demonstrated improved operational stability in CHP and hybrid systems, characterised by reduced cycling frequency and enhanced thermal resilience through hydrogen storage integration. Capital expenditure (CAPEX) ranged from 41,000 EUR (gas baseline) to 101,000 EUR (fuel cell CHP), reflecting additional storage, safety, and control requirements. Over a 20-year lifecycle (5% discount rate), the hybrid system achieved the lowest levelized cost of heat (0.076 EUR/kWh), followed by fuel cell CHP (0.081 EUR/kWh), compared to 0.087 EUR/kWh for gas. Payback periods ranged between 9 and 13 years, depending on configuration and hydrogen pricing assumptions. Sensitivity analysis identified a break-even hydrogen price of approximately 0.085 EUR/kWh, while carbon pricing above 100 EUR/t CO₂ significantly improves economic competitiveness. District-scale aggregation modelling suggests that hydrogen-equipped multi-apartment buildings can reduce grid electricity imports by 30–40% through on-site generation and seasonal storage. The findings confirm that multi-apartment buildings offer structural and economic advantages for early hydrogen deployment compared to dispersed housing typologies. By combining high demand density, centralised infrastructure, and compatibility with sector-coupling strategies, such buildings can function as distributed energy hubs within decarbonized urban systems. Full article

This study evaluates the potential of integrating floating photovoltaic (FPV) systems with green hydrogen production on UK reservoirs to support decarbonization across electricity, heating, and transport sectors. PVsyst was used to simulate annual electricity generation for monofacial and bifacial systems at Killington reservoir and Drift reservoir, while HOMER Pro was used to model hydrogen production via electrolysis and its potential applications. Results indicate that maximum FPV deployment could generate approximately 61 GWh/year at Killington and 20 GWh/year at Drift. Surplus electricity during peak production enables PEM electrolysis, producing up to 869,149 kg/year and 185,277 kg/year of hydrogen for the bifacial systems, respectively. This hydrogen could alternatively deliver up to 9.216 GWh/year and 1.977 GWh/year of electricity or 26.071 GWh/year and 5.558 GWh/year of heat, or support approximately 1,225,808 km/year and 454,550 km/year of hydrogen-powered transport. Additional co-location benefits include significant reductions in reservoir evaporation, estimated at 1.96 million m³/year for Killington and 452,037 m³/year for Drift. Overall, the findings demonstrate that hydrogen integrated FPV systems represent a promising system configuration under idealized deployment conditions, with location-specific modeling providing a UK-specific multi-sector assessment of the low-carbon potential of reservoir-based energy systems. The hydrogen use cases presented are alternative applications of the total hydrogen produced and are not intended to occur simultaneously. Full article