International Scientific Journals
of Scientific Technical Union of Mechanical Engineering "Industry 4.0"

In the paper, geometry parameters of a longitudinally-finned vertical shell-and-tube latent thermal energy storage (LTES), which uses paraffin as the phase change material (PCM) and water as the heat transfer fluid (HTF) have been optimized with the objective of maximizing its storage capacity, i.e. the amount of stored and released thermal energy. Three objectives were set: maximization of stored thermal energy in 8 h, maximization of released thermal energy in 12 h and a combination of the two, in which each objective was given equal significance. There geometry parameters were optimized; fin number, fin width and tube diameter. Optimization has been performed using response surface methodology and Box-Behnken approach. Responses have been obtained numerically, through an experimentally validated modeling procedure and solver scheme. The responses for each objective were fitted with a regression polynomial function and the fitness quality was evaluated through a coefficient R2. Optimization procedure offers different optimum values of analyzed parameters for each objective and provides guidance for choosing the favorable values of LTES geometry parameters in order to enhance LTES thermal performance.

The European Union’s REPowerEU strategy places green hydrogen at the center of its plan to eliminate fossil fuels and accelerate the green transition. The strategy targets 20 million tonnes (MTPA) of green hydrogen per year by 2030: 10 MTPA to be produced domestically and 10 MTPA imported. Achieving this requires scaling electrolysis capacity from the current 0.3 GW to 120 GW, a remarkably ambitious, if not unrealistic, target. Current green hydrogen production costs range from 100 to 200 €/MWh, several times higher than natural gas prices, which fluctuate between 20 and 40 €/MWh. In contrast, blue hydrogen, which is produced through natural gas reforming combined with carbon capture and storage (CCS), generally costs between 50 and 100 €/MWh. To bridge the cost gap between hydrogen and fossil fuels, the EU established the Hydrogen Bank with €3 billion to kick-start the market through competitive funding mechanisms. The REPowerEU hydrogen targets have drawn criticism due to limited availability of renewable electricity, underdeveloped infrastructure, and the slow pace of electrolysis deployment. Concerns also focus on the inefficiency of hydrogen use in sectors such as passenger transport, short sea shipping, residential and commercial heating, where direct electrification is significantly more effective. Nonetheless, the EU is advancing regulatory frameworks, developing over 40 Hydrogen Valley Projects, and establishing international import corridors to support market growth. This paper examines REPowerEU’s hydrogen ambitions, balancing its potential as a key decarbonization tool against economic, technical, and logistical challenges that may hinder its realization.

The study reports on a series of numerical simulations conducted to assess how tube diameter affects charging (melting) and discharging (solidification) performance in a shell-and-tube latent thermal energy storage (LTES) with longitudinal fins. In the investigated LTES, water flows through the tubes and serves as the heat transfer fluid (HTF), while paraffin is used as the phase change material (PCM) and fills the shell side. Employing an experimentally validated mathematical model and numerical procedure, LTES charging and discharging performances were investigated for three tube diameters: 28/24, 38/34 and 48/44 mm. LTES performance for different tube diameters was assessed by comparing melting and solidification times, as well as stored and released thermal energies in 8, 9 and 10 h of charging and 12, 13 and 14 h of discharging for each configuration. Results show that larger tube diameters accelerate melting and solidification processes due to increased conductive surface area, but also decrease LTES energy storing capacity as the amount of the PCM reduces as a result of increased tube diameter. The results indicate that tube diameter greatly influences LTES thermal performance and must be chosen carefully for the LTES to be effective.

The objective of this study is to numerically investigate the fluid flow and heat transfer performance of a finned-tube heat exchanger (FTHEX). The analysis focuses on the implementation of three vortex generator (VG) configurations: rectangular winglet (RW), delta-winglet upstream (DWU), and delta-winglet downstream (DWD) — mounted on the fin surface in a “common-flow-up” orientation. Attack angles of 15°, 30°, and 45° are considered for each VG type to evaluate their impact on the heat exchanger’s heat transfer potential and friction losses. The air-side Reynolds number, based on the outside tube diameter, was varied within the range 684 ≤ Re ≤ 1532. The results indicate that among the tested configurations, the RWP setup with an attack angle of 45° achieves the highest enhancement in the airside Nusselt number, with improvements ranging from 20% to 45% compared to the reference configuration, but at the expense of a higher pressure drop. For attack angles αvg = 15° and αvg = 30°, the highest overall performance (TPF factor) is achieved with the rectangular winglet configuration across the entire Reynolds number range. At an attack angle of αvg = 45°, the heat exchanger with downstream delta winglets shows higher TPF values compared to the other configurations, except at Re = 1278.

Compact air-cooled fin-and-tube heat exchangers are widely used in various fields, including the automotive and computer industries, as well as in heating, air conditioning, refrigeration, and process applications. Due to the thermal characteristics of air, the majority of heat transfer resistance occurs on the air side of the heat exchanger. As a result, research in this area primarily concentrates on enhancing the air-side performance. Numerous studies in the literature explore different fin and tube configurations aimed at optimizing the design of these heat exchangers however, pressure drop is sometimes neglected. In this study, a numerical analysis was conducted to investigate air-side pressure drop and heat transfer in various configurations of slotted fin-and-tube heat exchangers whereby heat exchangers with different ellipticity ratios were considered. The numerical model of the three-dimensional, laminar, steady-state problem of air-side flow and heat exchange was done using the finite volume method. The convection-diffusion equations were discretized using the Power Law scheme, and the SIMPLE algorithm was employed to couple pressure and velocity. Simulations were carried out in ANSYS Fluent 18.2. The validation of the proposed model was tested by comparing the numerical results with experimental measurements available in the literature whereby no discrepancies greater than 5% were observed. Four different inlet air velocities ranging from 1 to 4 m/s, corresponding to Reynolds numbers between 558 and 2233 were considered. Both the inlet air temperature and the tube surface temperatures were kept constant at 293 K and 373 K, respectively. The results emphasize potential benefits of using elliptic instead of round tubes in slotted fin and tube heat exchangers to achieve lower air-side pressure drop without penalty of lower heat transfer.

Carbon capture, Utilization and Storage (CCUS) technologies are rapidly evolving as a critical component of global decarbonization strategies, particularly in hard-to-abate sectors such as natural gas processing, power generation, fertilizer, cement and steel production industries. Amine-based absorption systems are currently the most established capture method, widely applied in large point sources for natural gas processing and chemical industries. Alternatives such as membrane separation, adsorption, and direct air capture are also emerging, offering benefits for specific applications. CO2 transport is increasingly diversified, with supercritical CO₂ pipelines and liquefied CO₂ shipping offering scalable and flexible solutions. CO₂ storage is focused on deep saline aquifers and depleted oil and gas fields. Carbon capture costs are project-specific and depend on CO2 concentrations, facility size, and technology complexity, with costs ranging from 30 to 120 US$/tCO2. The CCUS chain will undergo substantial development in the next decades, both in technological maturity and economic viability. As of early 2025, the total global CCUS capacity was 50 million tonnes per annum (MTPA) and is expected to reach 1300 MTPA by 2050. Yet, this will cover only 6% of total global CO₂ emissions, far from any net-zero carbon emissions scenario. By 2050, modularization, improved materials, and process integration are expected to reduce investment costs by up to 30%.

This article analyses the factors affecting the cost of electricity from geothermal power plants. Geothermal power is a capital – intensive technology and the installation costs are highly site sensitive. The costs of geothermal electricity are influenced by the thermal properties of the reservoir, the costs of site exploration and wells drilling, the number and depth of the wells, the power plant type. The choice of the power plant type depends on the properties of the geothermal resource, its temperature, quantity and quality. Being site- and technology-dependent, the installation costs for geothermal power may be as low as 2000 US$/kW and as high as 7000 US$/kW, with the global weighted average at 4000 US$/kW. This wide range of installation costs translates into levelized cost of electricity (LCOE) between 40 US$/MWh for upgrade and expansion projects and 170 US$/MWh for greenfield projects. The global weighted average LCOE is estimated at 70 US$/MWh. Further costs reductions may be accomplished through the research and development of more innovative and low-cost techniques for site exploration and drilling as well as with advanced exploitation methods for geothermal reservoirs.

This article presents the thermodynamic analysis of a 17.5 MW gross electric geothermal power plant based on binary cycle technology with isobutane. The geothermal power plant comprises two separate closed loops: the geothermal fluid flows in one loop and the Organic Rankine Cycle (ORC) fluid flows in the second loop. The geothermal fluid is extracted from a depth of 2500-3000 m with a temperature of 170 °C and a pressure of 25 bar. Two production wells supply geothermal fluid (brine and steam) with a high fraction of noncondensable gases (NCG). A separator extracts NCG from the geothermal fluid. Isobutane is preheated and evaporated before entering the ORC turbine with a temperature of 133 °C and a pressure of 28 bar, where expands to the condenser pressure of 4 bar. Electricity is generated by a 17.5 MW axial ORC turbine and additionally by a 1.5 MW NCG turbine. The analysis revealed that the configuration without NCG turbine achieves a net efficiency of 12.73% and a net electric power of 13.68 MW while the configuration with NCG turbine achieves a net efficiency of 14.04% and a net electric power of 15.16 MW but with much higher CO2 emissions into the atmosphere.

This paper analyses the performance of a future planned 500 MW ultra-supercritical pulverized coal power plant. The steam cycle configuration comprises a single-stage reheat, four high pressure feedwater heaters, three low pressure feedwater heaters and the deaerator. The electricity generation unit consists of a high pressure turbine, an intermediate pressure turbine, two double-flow low pressure turbines and the electric generator. The analysis is carried out for live steam temperature of 600 °C and pressure of 300 bar while th e reheat steam temperature is 610 °C and the pressure is 50 bar. The condenser pressure is 0.039 bar. The analysis revealed that the ultra-supercritical power plant achieves a gross thermal efficiency of 47.39% and a net thermal efficiency of 45.14%. The specific CO2 emissions per unit of generated electricity are 733.4 kg/MWh. Relatively to existing subcritical units, the analyzed ultra-supercritical power plant achieves a net efficiency gain of 9%-pts. and a CO2 emission reduction of around 20%.

This paper investigates the performance of post-combustion carbon capture and storage (PCCS) for pulverized coal-fired power plants. The PCCS units comprises CO2 absorption by 30 wt% monoethanolamine (MEA) solution and CO2 compression at 150 bar for permanent storage or enhanced oil recovery. The specific CO2 emissions per unit of generated electricity is 733 kgCO2/MWh in the reference power plant without PCCS while the power plant with integrated PCCS achieve specific emissions lower than 100 kgCO2/MWh, assuming a carbon capture rate of 90%. However, PCCS technology needs substantial amounts of thermal energy for absorbent regeneration and electricity for carbon capture, CO2 compression as well as for the operation of other parasitic electricity consumers. The PCCS energy requirements vastly affect the overall power plant performance. The reference coal-fired supercritical power plant (without PCCS) achieves a net efficiency of 45.1%. On the other hand, the PCCS integrated power plant achieves a net efficiency of 34.6%, a 10.5%-pts net efficiency loss over the reference scenario, when the PCCS specific energy demand is 3.5 MJth/kgCO2 for absorbent regeneration, 0.35 MJel/kgCO2 for CO2 compression and 0.15 MJel/kgCO2 for carbon capture and cooling water pumps. The corresponding electricity output penalty caused by the PCCS unit is 352 kWhel/kgCO2. PCCS technology shows promising potential for decarbonization of the power industry, but further development is necessary to improve its reliability, cost-effectiveness and to diminish its impact on the power plant performance.