With the rapid growth of renewable energy under the goals of carbon peaking and carbon neutrality, power systems face increasing demand for long-duration energy storage and flexible peak regulation. Electrically heated solid particle thermal energy storage (TES) is a promising option because it offers high operating temperature, wide storage temperature range, low-cost storage media, good thermal stability, clean electric-to-thermal conversion, and strong potential for integration with renewable energy systems and coal-fired power plants. This paper aims to clarify the research progress, major bottlenecks, and future directions of this technology.

This paper reviews electrically heated solid particle TES from the perspectives of heating principles, representative devices, application scenarios, and key scientific and engineering issues. Two major routes, resistance heating and induction heating, are discussed in detail. For resistance heating, both indirect and direct modes are considered. Indirect resistance heating transfers heat from electric heating elements to particles through conduction, convection, and radiation. It has advantages such as simple structure, mature equipment, and good controllability, but it also suffers from additional thermal resistance and heat loss. Direct resistance heating allows conductive particles or conductive particle networks to generate Joule heat directly, which improves heating compactness and electric-to-thermal efficiency, while also introducing challenges related to conductivity stability, local overheating, oxidation resistance, and the formation of reliable conductive paths. Induction heating provides non-contact heating and rapid thermal response, and is attractive for high-temperature applications. However, its performance depends strongly on frequency, magnetic field intensity, coil design, particle size, electrical conductivity, magnetic permeability, and temperature-dependent material properties. In addition, induction heating systems often face higher equipment cost, cooling demand, and lower overall efficiency in practical applications. Representative devices for solid particle heating, including tubular heaters, plate heaters, fluidized-bed heaters, and moving-bed heaters, are also summarized. Tubular and plate heaters are relatively mature and suitable for small- and medium-scale systems, whereas fluidized-bed and moving-bed configurations show better heat transfer performance and greater potential for high-power and continuous operation. At the same time, they involve more complex issues such as particle flow stability, pressure drop, abrasion, temperature uniformity, and model accuracy. This paper further discusses key challenges, including high-temperature particle flow and heat transfer mechanisms, optimization of electric heating efficiency, durability of particle materials under thermal cycling, cost control, and coordinated operation with coal-fired power plants.

Electrically heated solid particle TES is a promising technical route for renewable energy integration, long-duration energy storage, and flexible operation of coal-fired power plants. Resistance heating is currently more mature and economically competitive, while induction heating has advantages in non-contact heating, rapid response, and high-temperature adaptability, but still requires progress in efficiency improvement, cost reduction, and particle material matching. Future research should focus on multi-field coupled particle flow and heat transfer, low-cost and high-performance particle materials, modular electric heating devices, heat loss control, and coordinated control strategies, so as to promote the scale-up, industrialization, and commercialization of this technology.

Conventional combined heating and power (CHP) systems often suffer from suboptimal thermal integration and limited exergy utilization, resulting in low overall energy efficiency and significant carbon emissions. To address these challenges, this study proposes a novel high-efficiency CHP system based on the synergistic integration of a solid oxide fuel cell (SOFC) and a lithium bromide (LiBr) absorption heat pump. The architecture is specifically designed to maximize cascaded energy recovery and enhance comprehensive thermodynamic and economic performance.

A comprehensive steady-state model encompassing thermodynamic and economic analysis was developed to evaluate the system behavior. In the proposed configuration, unreacted fuel in the SOFC anode exhaust is combusted using oxy-fuel technology, yielding a CO₂-concentrated flue gas suitable for carbon capture while simultaneously upgrading waste heat quality. The high-temperature flue gas is then recovered through an advanced cascaded heat exchanger network, sequentially enabling cathode air preheating, endothermic methane reforming, and high-pressure steam generation. This steam serves as the thermal driving source for the LiBr absorption heat pump to meet heating demands. A detailed parametric sensitivity analysis was conducted to investigate the effects of the steam-to-carbon ratio, SOFC operating temperature, and fuel utilization factor on key performance indicators.

Simulation results show that increasing the steam-to-carbon ratio monotonically reduces both SOFC electrical efficiency and overall thermal energy utilization efficiency, whereas the coefficient of performance (COP) of the absorption heat pump remains stable at approximately 1.72. Higher SOFC operating temperatures significantly improve electrochemical kinetics and flue gas quality, thereby enhancing both electrical and thermal performance. A clear trade-off is observed with fuel utilization: higher fuel utilization factor increases electrical output but diminishes the availability of high-grade heat for downstream recovery. Under optimized conditions (with the steam-to-carbon ratio of 2, temperature of 1 000 ℃, and fuel utilization ratio of 0.85), the system achieves an electrical efficiency of 52%, an exergy efficiency of 56.6%, and an overall thermal energy utilization efficiency of 100.54% (defined on the basis of the fuel’s lower heating value, including all recovered thermal energy). Compared to a conventional natural gas-fired CHP benchmark, the proposed system improves the thermal utilization efficiency by 20%, and increases the exergy efficiency by 2.6%. Economic evaluation yields a levelized cost of exergy of 0.102 6 dollars/(kW·h) and a dynamic payback period of 8 years under current industrial energy pricing.

This coupled system significantly improves the energy utilization efficiency and comprehensive performance through the optimization of the energy cascade utilization mode. It demonstrates substantial economic feasibility and potential for engineering applications. The identified influence mechanisms of key parameters provide a theoretical foundation for the optimal design and operational control of such systems.

Against the dual backdrop of urgent global climate governance and low-carbon transformation demands of the coal-fired power industry, carbon capture and storage (CCS) is widely recognized as a critical pathway to deep emission reduction in the power system. However, the high cost of CCS technology has severely hindered its large-scale promotion. To address this cost optimization challenge, this study aims to systematically explore the cost-driven mechanisms of the full-chain CCS system, identify key influencing factors, and propose a targeted cost-reduction paradigm, providing theoretical and practical support for the scientific deployment and commercialization of CCS in coal-fired power plants.

This study adopted the ITEAM-CCUS quantitative evaluation model, covering the full-chain CCS and integrating three core modules: geological carbon storage assessment, techno-economic analysis, and source-sink matching optimization. A systematic multi-parameter sensitivity analysis was conducted based on a sample of 165 domestic coal-fired power plants. These samples were selected to represent different regional distributions, unit capacities, and operational conditions, ensuring the generalizability and reliability of the research results. The analysis focused on key technical, economic, and geological parameters, such as absorbent regeneration heat consumption, coal price, plant utilization hours, electricity price, transportation distance, and reservoir properties.

The study revealed that the average levelized cost of the full-chain CCS is 303 yuan per ton of CO₂. Among the four chains, the capture and compression stages account for over 80% of the total cost, emerging as the primary focus for cost reduction. Specifically, capture cost is most significantly influenced by absorbent regeneration heat consumption, coal price, and plant utilization hours, and reducing regeneration heat consumption through technological innovation or improving plant operational efficiency can effectively lower capture costs. Compression cost shows a strong correlation with electricity price. Pipeline transportation cost is constrained by transportation distance and economies of scale. Storage cost is extremely sensitive to geological parameters such as reservoir’s permeability coefficient, thickness, and depth-reservoirs with higher permeability, greater thickness, and moderate depth are more conducive to reducing drilling, injection, and monitoring costs.

Based on the quantitative findings, this study proposes a systematic “scale-geology-energy efficiency synergy” cost-reduction paradigm. The specific pathways include technological innovation for low-energy consumption in the capture stage, large-scale infrastructure sharing across the full-chain CCS, refined operation and management of the CCS system, and policy incentives. This research clarifies CCS cost structures and driving factors, providing a feasible framework for governments, enterprises, and research institutions. It offers important theoretical and practical reference for promoting large-scale, commercial CCS application in coal-fired power plants, advancing power system decarbonization, and supporting global climate governance.

The carbon capture pretreatment system faces challenges such as high energy consumption, unstable purification efficiency, and significant fluctuations in SO₂ absorption efficiency due to variations in pH value of washing solution. This study proposes a hybrid modeling method combining mechanism models with data-driven by taking the carbon capture pretreatment system in a power plant as the research object.

By integrating chemical reaction kinetics and decision tree algorithms, the model is implemented in Python to predict key parameters accurately, including the pH value of the washing solution and the SO₂ mass concentration at the system outlet.

The model yields a correlation coefficient of 0.85 and 0.80 for the pH value of the washing solution and the SO₂ mass concentration at the system outlet, respectively. The values fall within an acceptable error band, indicating the proposed model has good simulation performance. Moreover, a sensitivity analysis driven by baseline plant data further reveals that the model faithfully reproduces the system response to perturbations in inlet flue-gas temperature, liquid-to-gas ratio, and alkali feed rate.

These outcomes furnish a quantitative foundation for subsequent optimization of the CO₂-capture pretreatment system, offering clear avenues for energy minimization and robust steady-state operation.

In practical energy and chemical engineering systems, pipeline layouts often exhibit complex multi-directional configurations due to equipment arrangement, spatial constraints, and process requirements, rather than simple straight horizontal or vertical sections. This is particularly evident in applications such as compact heat exchangers for supercritical carbon dioxide (S-CO₂) Brayton cycles, nuclear reactor cooling circuits, and chemical transport pipelines, where the working fluid frequently undergoes abrupt changes in flow direction. Among these configurations, the L-shaped bend, a classic directional-changing structure that connects horizontal and vertical pipe sections, is especially common and plays a crucial role in achieving spatial redirection of the working fluid. Therefore, investigating the heat transfer characteristics of S-CO₂ in L-shaped bends is of significant importance. This study aims to investigate the effect of buoyancy-induced density stratification in a heated horizontal section on the subsequent heat transfer in a vertical upward flow under different experimental parameters.

An experimental system with high expandability was established, featuring a single-cycle S-CO₂ heat transfer test platform utilizing stainless steel circular pipes with adjustable lengths and bend angles. Experiments were conducted to study the flow and heat transfer characteristics of S-CO₂ inside a horizontal-to-vertical L-shaped turning pipe.

The experimental results reveal two distinct types of “asymmetric heat transfer deterioration” in the turning pipe: one characterized by asymmetry in the severity of deterioration, and the other by asymmetry in its location. When the wall heat flux is increased, wall temperature peaks indicating heat transfer deterioration appear in the vertical section, with unequal peak values on the two sides, representing asymmetry in severity. A further increase in wall heat flux shifts the deterioration position toward the inlet, while the enthalpy at which deterioration initiates remains unchanged, indicating that the wall heat flux does not affect the onset enthalpy of deterioration. When the heat flux is raised sufficiently for the deterioration to advance to the inlet of the vertical section, the wall temperature peak on the inner side occurs earlier than that on the outer side, demonstrating asymmetry in the location of deterioration.

The study demonstrates that asymmetry in severity originates from non-uniform cross-sectional mass flow distribution caused by temperature stratification extending from the horizontal section. In contrast, asymmetry in location occurs under high-temperature and high-heat-flux conditions due to the earlier fulfillment of deterioration criteria within the inner-side boundary layer. This research elucidates the coupling effect between buoyancy and flow redirection in L-shaped pipes, providing an experimental basis for the design of related heat exchange equipment.

This study aims to enrich the experimental study of the ORC using mixture working fluids and analyze its transient and steady-state operating characteristics.

A 4-kW organic Rankine cycle (ORC) prototype using R236fa/R123 was tested to obtain the transient and steady-state operating data.

The results of the ORC system at different mixture concentrations reveal that the operation characteristics of the ORC with mixed working fluids are consistent with those using a pure working fluid. The adjustment of the working fluid mass flow rate significantly affects the system output power, while it has a limited impact on the thermal efficiency. The ORC system operates relatively stable with the variation in the mixture concentration, as it has a minimal effect on both the output power and thermal efficiency. With the increase in the R236fa mass fraction, the expander inlet pressure is stable while its outlet pressure gradually increases, resulting in high pressure ratios. This phenomenon indicates that adopting the expander with a larger internal volume ratio can optimize the ORC performance. The trade-off between the exergy destructions of the evaporator and condenser at different mixture concentrations is the main factor determining the system performance. The temperature glide caused by the condenser pressure drop limits the attribution of the mixture working fluid to optimize the system performance.

In the design and operation of mixed-working-fluid ORC systems, it is crucial to consider the matching of the condenser pressure drop and the working fluid inherent properties.

To achieve recovery and utilization of low-grade waste heat, we proposed a phase change thermal storage unit incorporating “tree-branch fins + foam metal”, and co-optimized its structural and material parameters using response surface methodology and orthogonal experiments.

Under typical operating conditions (80 ℃, 0.005 m/s), tree-branch fins reduced the melting time of the phase change material (PCM) by 10.7% compared to straight fins, with optimal parameters including a length ratio of 1.143, a width ratio of 1.057, and a branching angle of 68.987°. Regarding system structure, the counterflow arrangement of dual heat exchanger tubes decreased the melting time to 558 s, and further filling with foam metal shortened it to 181 s. Although increasing porosity enhances the proportion of PCM, it weakens the structural support of the metal framework, thereby prolonging the melting time.

In conclusion, the integration of tree-branch fins and foam metal significantly improves the thermal storage performance of phase change thermal storage devices. Subsequently, staged thermal energy storage can improve the efficiency of heat storage. The optimal configuration for a three-stage cascade is put forward: Stage I: 0.9 porosity nickel foam + n-octadecane; Stage II: 0.5 porosity nickel foam + n-octadecane; Stage III: 0.5 porosity nickel foam + stearic acid PCM.

It can provide an integrated design basis for the efficient capture and reuse of low-grade waste heat at 50~60 ℃.

In the context of achieving the “dual-carbon” goals in the new era, coal-fired cogeneration systems are required to be highly efficient, flexible, and low in pollution and carbon emissions.

To tackle these challenges, this study proposes a novel system that integrates a supercritical CO₂ cycle with split-flow heating and low-temperature regeneration (SR-SCO₂-CHP), an ultra-low emission (ULE) flue gas control module, and a vacuum temperature swing adsorption (VTSA) carbon capture module (denoted as the SR-SCO₂-CHP-ULE-VTSA system). A system using monoethanolamine (MEA) for carbon capture (SR-SCO₂-CHP-ULE-MEA) serves as the benchmark for comparison. A comparative exergy analysis is conducted.

The results demonstrate that the proposed system achieves superior exergy efficiency across all electrical loads, because the exergy loss of the VTSA carbon capture submodule is less than one-third of that of the MEA. The exergy losses of MEA mainly occur in the absorption tower and desorption tower, which account for 80% of the total exergy losses of the carbon capture submodule. However, the exergy losses of VTSA adsorption & desorption tower and the pressure machine are relatively large, accounting for more than 60% of the total exergy losses of the carbon capture submodule. At full load, its exergy efficiency reaches 39.84%, significantly outperforming the benchmark system’s 35.16%. Furthermore, the proposed system enables effective thermo-electric decoupling through adjustments in the heat split ratio (x₁) and the split ratio of CO₂ turbine driving vacuum pump (x₂). The exergy efficiency of the system decreases as the split ratio x₁ and x₂ increase under any electrical load, and the optimal split ratios of x₁ and x₂ increase as the electrical load decreases. At 100% electrical load, the optimal values for x₁ and x₂ are 0.52 and 0.14, respectively. The carbon reduction capability of the proposed system is also remarkable. Across the electrical load range from 100% to 30%, the carbon reduction increases from 11.9 g/(kW·h) to as high as 85.3 g/(kW·h), demonstrating a significant advantage over the benchmark system.

This work confirms the SR-SCO₂-CHP-ULE-VTSA system as a promising solution for highly efficient and low-carbon coal-fired cogeneration. It should be noted that in terms of economic performance, the initial investment of the carbon capture module of the SR-SCO₂-CHP-ULE-VTSA system is closely related to the performance of the adsorbent material, and further optimization of the adsorbent is required to reduce equipment size and cost. Additionally, in terms of operation, its carbon capture module has a complex structure and high requirements for multi-tower operation switching, so its technical maturity needs to be further improved to promote its industrial application.

The low-temperature (–20~ –40 ℃) oxidation adsorption of multiple pollutants from coal-fired flue gas onto activated carbons enables their integrated removal, which has promising application prospect and environmental benefits.

This article studied the adsorption processes of NO and SO₂ by four activated carbons (graded-pore activated carbon, coal-based activated carbon, and two coconut shell-based activated carbons) in inert atmosphere and simulated flue gas under low temperature conditions of –20 ℃.

The experimental results showed that in an inert atmosphere, the adsorption performance of the four activated carbons for NO was weak, with a saturated nitrogen capacity of less than 0.07 mg/g, and the saturated sulfur capacity for adsorbing SO₂ was 31.70~57.07 mg/g. In simulated flue gas conditions, the presence of O₂ increased the saturated nitrogen capacity of activated carbons by three orders of magnitude and the saturated sulfur capacity by 2~5 times. The optimal coconut shell activated carbon-2 had a saturated nitrogen capacity of 175.70 mg/g and a saturated sulfur capacity of 320.65 mg/g. Density functional theory (DFT) calculations show that the adsorption binding energies of NO, SO₂, and their oxides on the zigzag edge carbon model follow the order of NO₂> SO₃> SO₂> NO. After NO and SO₂ are oxidized by O₂ into NO₂ and SO₃, their adsorption on activated carbon surfaces is significantly enhanced.

The research results can provide an important theoretical basis for the integrated adsorption and removal of NO and SO₂ in coal-fired flue gas under low temperature conditions.