The installed capacity of renewable energy is continuously increasing to address the impacts of the greenhouse effect. To enhance the grid's capacity to accommodate renewable energy, this work proposed a novel thermal battery system integrating a Brayton-based heat pump with multiple heat sources (steam and water) within a 350 MW coal-fired power plant (CFPP). The electricity and thermal energy within CFPP are transferred into thermal energy stored in molten salt by heat pump, which enhance the CFPP peak shaving capacity. The theoretical analysis was firstly conducted to investigate the effects of temperature and mass flow rate parameters on heat pump coefficient of performance (COP), and then the heat pump operational domain is determined by analyzing the temperature of the thermal energy storage (TES) system and the heat source. A simulation model was established to evaluate the performance of integrated system utilizing different heat sources within CFPP in actual conditions. Results show that the maximum equivalent heat pump COP can reach 1.224 utilizing reheat steam as heat source during the charging process. The equivalent roundtrip efficiency of this integrated system is obtained as 50.52%~54.64% through the parameters optimization process. Compared with the theoretical condition, the inlet temperature of the TES and the air outlet temperature of heat source heat exchanger are the main factors limiting the heat pump to reach its theoretical maximum COP

High penetration of renewable power into power system poses a challenge to the power grid security. Thermo-mechanical electricity storage technologies are an effective solution to enhance operational flexibility of the power system. This work proposed a novel pumped thermal electricity storage system (PTES), which consists of a high temperature heat pump subsystem based on Brayton cycle, molten salt heat storage units and a Rankine-based thermal power plant. Simulation models were developed to analyze the impact of operation parameters during the charging and discharging process, and a system configuration design method targeting different objectives is proposed. To further decrease the deep peak shaving capacity, the electricity and low-grade heat of thermal power plant are stored by high temperature heat pump subsystem. Results reveal that the maximum heat engine efficiency of the heat storage system can reach 44.35%, and the coefficient of performance of the heat pump can reach to 1.292 through the parameter optimization of heat pump subsystem. The minimum output power of the PTES can decrease from 30.00% of rated load to 2.22% during the charging process. The maximum equivalent roundtrip efficiency of the PTES is up to 53.72% and the minimum levelized cost of storage can reach 67.42 $/MWh.

Pumped Thermal Electricity Storage (PTES) needs to operate at off-design conditions for a long time to participate in grid flexibility regulation frequently. This paper focuses on a 2.0 MW Joule-Brayton PTES system incorporating liquid thermal storage, off-design models of the systems were developed, and the variation of thermodynamic parameters under distinct power input/output conditions were investigated. High-efficient and flexibility operational strategies of the PTES system applied in load up and down processes were proposed, and then peak shaving operational domain and corresponding exergy loss were evaluated. The results reveal that as the input electric power ratio decreases from 100% to 50%, the COP of the heat pump subsystem decreases from 1.33 to 1.05. As the output electric power ratio decreases from 100% to 20%, the cycling efficiency of the heat engine subsystem decreases from 44.8% to 24.3%. When both input and output power conditions change, the system roundtrip efficiency declines substantially from 59.2% to 13.3%. During the load up process, the strategy that decreasing heat pump power is better than that increasing the output power of the heat engine subsystem, and the corresponding relative exergy losses ranging from 0.007 to 0.17 MW, with a critical threshold observed at 0.4 MW load increase. During the load down process, the strategy that decreasing the output power of the heat engine subsystem is feasible when the load decrease amplitude is below 1.0 MW and it exhibits contrasting behavior with exergy losses between 0.009-0.116 MW.

The Rankine-based Carnot battery is an effective solution for integrating renewable energy and enabling cogeneration in regional energy systems, owing to its long lifespan, low specific investment, and geographical adaptability. This study presents a performance analysis and comparison of the standalone Rankine-based Carnot batteries with different heat pump systems and multi-stage thermal storage modes based on the exergy method. The mathematical models of these Rankine-based Carnot batteries were developed and validated, the performance indicators were introduced, and then the highest roundtrip efficiencies of different system configurations were sought through parameter optimization. The results reveal that after introducing latent thermal storage in the hot storage side, the heat pump cycle achieves better match with the ORC, leading to a significant improvement in performance. The COP of the heat pumps are between 2.01 and 2.56, and the efficiencies of the ORC are between 15.54 % and 16.31 %. The roundtrip efficiencies of the cascade heat pump configurations without and with latent thermal storage are 31.22 % and 38.21 %, respectively. For the flash heat pump configurations without and with latent thermal storage, the roundtrip efficiencies are 34.80 % and 41.06 %, respectively. Additionally, replacing cold storage medium with latent thermal materials can further enhance system performance, increasing the roundtrip efficiency up to 46.67 %. Exergy losses are concentrated in heat exchange processes, compressors, and turbines, and the introduction of latent thermal storage in the hot and cold storage sides can effectively lower exergy losses during charge and discharge processes.

Due to the increasing penetration of renewable power in the power grid, primary frequency regulation (PFR) resources are severely constrained, which threatens the operational safety of the power grid. Consequently, the PFR capability of coal-fired power plants, which have a decreasing share of installed capacity within the power grid, is of paramount importance. The PFR capability of coal-fired power plants tends to degenerate and the prediction error of the PFR model increases progressively under deep peak-shaving conditions. To reveal the degradation mechanism, both the steady-state and dynamic thermal storage characteristics were examined. As the load decreases from 75 % to 20 %, the frequency regulation time, maximum, and cumulative frequency deviation increase by 52.4 %, 287.0 % and 376.0 %, respectively, and the steady-state total thermal and exergy storage of the unit decrease by 111.0 GJ and 49.8 GJ, respectively. Moreover, during the step response of the high-pressure control valve, the transient release capacity of the thermal and exergy storage was substantially weakened by 73.4 %, ultimately contributing to the degradation of PFR capability. To enhance the prediction accuracy of the PFR capability under various conditions, a PFR margin prediction model was developed by integrating mechanism-driven and data-driven approaches, thereby improving both accuracy and efficiency, considering the variation in both live steam flow rate and work done per unit mass of live steam. The comprehensive prediction errors were reduced by 95.6 % compared to the standard model-based approach.

Thermo-mechanical energy storage technologies can play an important role in low-carbon energy systems by storing surplus renewable energy and discharging when needed, with several promising variants currently under development for grid-scale applications. Relevant technologies include adiabatic compressed-air energy storage, liquid-air energy storage, and pumped-thermal electricity storage. In this work, comprehensive thermo-economic optimisation models are developed for these three technologies, using a unified framework based on consistent performance and cost assumptions. This approach allows for a consistent comparison between these leading thermo-mechanical energy storage technologies. The optimisation and comparisons are performed for a range of nominal discharge power ratings and charging and discharging durations to capture scale effects. Results show that adiabatic compressed-air energy systems achieve the lowest capital costs but rely on access to available, suitable large underground caverns to store the air. Liquid-air and pumped-thermal electricity storage systems do not face such geographical constraints. Between these two options, the former exhibits lower costs at low power ratings (as low as 380 v. 470 $/kWh for 10-MW systems), while the latter is more economical at high nominal power (as low as 160 v. 205 $/kWh for 100-MW systems) and offers a higher energy density (up to 72 v. 30 kWh/m3 for 100-MW systems). Overall, minimum energy capital costs of 124 $/kWh at power capital costs of 1120 $/kW can be achieved for 100-MW compressed-air systems, which is highly competitive with other grid-scale energy storage technologies such as electro-chemical batteries, hydrogen storage or power-to-gas.

Rapid load cycling of ultra-supercritical coal-fired units is essential for high renewable penetration, but it creates thermal and structural risks in water wall tubes, particularly under low load dry-out conditions. This study develops a coupled dynamic simulation and safety assessment framework for a 1100 MW ultra-supercritical once-through coal-fired unit, integrating water wall thermal hydraulic behavior, metal temperature evolution, plane strain thermomechanical stress calculation, and ASME based low-cycle fatigue assessment. The framework evaluates metal temperature, thermomechanical stress, and fatigue life consumption during the 30% to 50% THA ramp-up transient. Dry-out induced heat transfer deterioration strictly constrains the allowable power ramp rate. Under the original control strategy with uniform flow, peak wall temperatures at 39.0, 40.5, and 42.0 m reached 599.4, 578.9, and 564.6 °C at 3.0% Pe·min-1, exceeding the 550 °C limit for 15CrMoG. Reducing the ramping rate to 2.0% Pe·min-1 kept all monitored sections within the material limit. Flow maldistribution reduced the safety margin, lowering the permissible ramping rate to 1.5% Pe·min-1 and 1.0% Pe·min-1 for 3% and 6% flow deviation cases, respectively. An active feedwater control strategy triggered by dry-out zone wall temperature was proposed. Under uniform flow, staged feedwater compensation limited peak temperatures to below 550 °C at 3.0% Pe·min-1, reduced the maximum von Mises stress by 5.2%–6.3%, and decreased fatigue life consumption by 24.7%–26.8%. Under the 6% flow deviation case, overheated sections returned to a safe range, and fatigue life consumption decreased by approximately 17%–18%. These findings support safety constrained rapid load cycling and fatigue life management.

To integrate the high penetration of renewable energy into the power grid, thermal power plants must expand their load variation range and rate. However, increased these operational flexibility leads to rapid fluctuations in thermal parameters, which induces stress variations that affect the safety of critical components within power plants, particularly steam turbine rotors. Consequently, monitoring rotor stress during dynamic processes is essential for the safe and reliable operation of power plants, which has been underemphasized in previous studies. In this study, a dynamic model of the power plant and an online stress calculation model were developed to assess the thermo-mechanical performance of the steam turbine rotor. The governing stage has been identified as the most critical area during peak shaving processes. The study reveals that as the load variation rate increases from 1.0 % to 4.0 % Pe min- 1 during peak shaving processes from 50 % to 75 % THA, the stress amplitude at the governing stage escalates from 1.8 to 22.8 MPa. Furthermore, at a load variation rate of 2.0 % Pe min- 1, increasing the peak shaving depth results in a rise in stress amplitude and fatigue damage from 3.7 MPa and 6.6 x 10- 11 to 7.8 MPa and 3.0 x 10-9.

Increasing steam temperature is an effective means to enhance the efficiency of thermal power plants. However, the irreversibility of the regenerative system remains high due to large temperature differences within regenerative heaters. The idea of cascade Rankine cycle, i.e., the integration of a regenerative cycle, is an effective way to decrease the irreversibility of the regenerative system, and it has been applied in many ultra-supercritical power plants. Nevertheless, the increased system complexity and thermal inertia reduce the operational flexibility of thermal power plants adopting cascade Rankine cycles, particularly in the control of feedwater systems during peak shaving. Accordingly, this study investigates a 1000 MW-class thermal power plant equipped with a back-pressure extraction steam turbine driving the feedwater pump. Two major limiting factors for feedwater control were identified: the uncompensated mechanical inertia of rotating components and the simplified modeling of nonlinear dynamics in the original control strategy. Therefore, a feedforward-feedback compensation framework during peak shaving was proposed, the feedforward component pre-adjusts the control inputs based on flow deviation, while the feedback loop provides fine-tuned corrections. Simulation results demonstrate that under peak shaving operations (50 %-75 % Pe, where Pe is the rated power of the unit, and 75 %-100 % Pe) and variable load rates (2 %-5 % Pe min-1), the revised strategy enhances feedwater tracking accuracy by 70 %- 88 %, reduces main steam temperature deviations by 24 %-39 %, and limits reheat steam deviations by up to 35 %. This approach enhances unit stability and peak-shaving capability, facilitates renewable energy integration, and supports the low-carbon transition of power systems.

The integration of thermal energy storages with thermal power plants presents a promising approach of improving frequency regulation ability. However, conventional coordinated control strategies are limited in addressing the expanded regulatory parameters introduced by thermal energy storage integration. Here, a dual-layer coordinated control strategy is proposed to achieve the frequency regulation of thermal power plants integrated with thermal energy storage, thereby enhancing operational flexibility and efficiency. The upper layer executes load command reconstruction based on the effective working ability of steam extraction, while the lower layer dynamically revises regulatory parameters through adaptive adjustments according to heat distribution variations. The feasibility of the proposed control strategy under various integration methods is evaluated using a 660 MW double-reheat power plant integrated molten salt thermal heat storage. Furthermore, comparative analyses of frequency regulation potential and efficiency are conducted. Frequency regulation potential is the strongest when the extraction steam point is located at the inlet of intermediate-pressure cylinder, achieving a peak load down rate of 8.5 % THA & sdot;min-1. The standard coal consumption rate decreases with the extraction steam ratio, with a maximum decrease of 19.0 g & sdot;kWh-1. Notably, the extraction steam ratio exerts a stronger effect on system efficiency than the extraction steam point. The proposed dual-layer control strategy enables the frequency regulation process in thermal power plants assisted by thermal energy storage, thereby enhancing the flexibility. This work provides supports for grid de-carbonization, and points to future research, including applying machine learning for predictive parameters and incorporating dynamic electricity prices to maximize operational benefits.

The swift advancement of renewable energy demands greater flexibility and enhanced peak-shaving capabilities from coal-fired power plants (CFPPs). Molten salt thermal energy storage (MSTES) is considered a potential solution. In this study, a CFPP integrated steam and flue gas stepwise/staged heating MSTES system is proposed. The proportion of steam heat energy allocated to the molten salt and feed water is adjusted. The thermodynamic and economic performance of two configurations under different thermal load distribution ratios are compared and studied. Results show that, under the same molten salt thermal load distribution ratio, the stepwise configuration achieves an average energy storage density that is 2.53 kWh/m3 greater than the staged configuration. Furthermore, it demonstrates a 3.82 % improvement in average denitration efficiency and a 1.28 MW reduction in average charging exergy loss. Economic analysis reveals that the integrated system performs best when the molten salt thermal load distribution ratio is minimized. At this time, the stepwise configuration demonstrates a 9.3 % lower life cycle cost, a 9 % lower equivalence levelized cost of electricity, and a 9.5 % lower equivalence levelized cost of thermal storage compared to the staged configuration.

High flexibility is essential for maintaining the safe and stable operation of power systems with a high-proportion of intermittent renewable energy generation. Integration of an energy storage system is an effective way to improve the flexibility of thermal power plants. In this manuscript, a new coordinated control strategy based on the load decomposition, considering the heat to power conversion characteristics of a boiler-turbine with an energy storage system, is proposed to improve the flexibility of the power plants. The core concept of the load decomposition is that the turbine load commands equals the sum of boiler and energy storage system load commands. The proposed new coordinated control strategy is examined by a case study of a boiler-turbine with energy storage system. The results show that the maximum load down and up rates are up to 7.0 % and 6.5 % Pe0 min- 1, and the maximum reductions in standard coal consumption rates during load down and up are 1.4 and 1.8 g kWh-1, respectively. Additionally, the round-trip energy efficiency of the turbine-boiler-storage system during load down and up is improved by decreasing the extraction steam/water ratio or increasing the load cycling rate during load up. This study provides a comprehensive guide for enhancing the operational flexibility through the coordinated operation of the boiler, turbine, and energy storage systems.

Thermo-mechanical energy storage(TMES)technologies have attracted significant attention due to their potential for grid-scale,long-duration electricity storage,offering advantages such as minimal geographical constraints,low environmental impact,and long operational lifespans.A key benefit of TMES systems is their ability to perform energy conversion steps that enable interaction with both thermal energy consumers and prosumers,effectively functioning as combined cooling,heating and power(CCHP)systems.This paper reviews recent progress in various TMES technologies,focusing on compressed-air energy storage(CAES),liquid-air energy storage(LAES),pumped-thermal electricity storage(PTES,also known as Carnot battery),and carbon dioxide energy storage(CES),while exploring their potential applications as extended CCHP systems for trigeneration.Techno-economic analysis indicate that TMES-based CCHP systems can achieve roundtrip(power-to-power)efficiencies ranging from 40％to 130％,overall(trigeneration)energy efficiencies from 70％to 190％,and a levelized cost of energy(with cooling and heating outputs converted into equivalent electricity)between 70 and 200 $/MWh.In general,the evolution of TMES-based CCHP systems into smart multi-energy management systems for cities or districts in the future is a highly promising avenue.However,current economic analyses remain incomplete,and further exploration is needed,especially in the area"AI for energy storage,"which is crucial for the widespread adoption of TMES-based CCHP systems.

The operational flexibility of thermal power plants should be enhanced to accommodate the high penetration of photovoltaic and wind power within the power grid. The energy efficiency deteriorates heavily when thermal power plants operate under ultra-low power load ratio conditions, which will increase the carbon emissions of the low-carbon power system. To achieve the energy saving under ultra-low power load ratio condition, the CFPP's (coal-fired power plant) off-design condition models were developed, and the thermal system regulation with additional losses of the CFPP operates under below 30 % power load ratio condition was simulated. Then, influences of the degradation factors on the energy consumption characteristics under ultra-low power load ratio condition were evaluated. Moreover, the carbon emission rate of power generation considering the renewable power accommodation was evaluated. Results show the degradations of turbines' internal efficiencies are the main source of internal losses, and the degradation of boiler's efficiency and the increase of the auxiliary power ratio are the main source of external losses. The total carbon emission rate of power generation decreases by 21.98 g/(kW h) with the power load ratio of CFPP decreasing from 30 % to 20 % due to the increased accommodation of renewable power. Finally, energy saving potential evaluations under ultra-low power load ratio conditions were conducted. The net coal consumption rate is 298.56 g/(kW h) and 522.39 g/(kW h) when the thermal power plant operates under 100 % and 20 % power load ratio conditions respectively. The maximal energy saving potential of bnet under ultra-low power load condition are 87.25, 29.47, 25.05, 2.33 and 1.05 g/ (kW h), for the degradation of isentropic efficiency of turbine, the degradation of boiler's efficiency, the increase of auxiliary power ratio, the additional drainage water of the boiler and the switching action of BFPT's supply steam, respectively.

High-penetration of renewable energy with intermittent nature poses great challenges to safety and stability of the power system. Steam power plants (SPPs), as the main regulation resource for operational flexibility, are frequently required to operate at ultra-low loads (lower than 30 % load) to meet grid requirements, which results in thermal efficiency reduction, higher generation costs, and increased greenhouse gas emissions. To address these problems, a novel top turbine system integrated into SPPs was proposed, and corresponding models were developed to evaluate system performance at all loads, especially for the ultra-low loads. The results reveal that integrating the top turbine system can enhance power generation efficiency at ultra-low loads, and the lower the design flow rate of the top turbine, the more pronounced the efficiency improvement. For a 350 MW supercritical SPP, to enhance efficiency at 20 % load, the optimized high-pressure top turbine (HPTT) design steam flow rate, inlet, and outlet pressures are 90 kg s-1, 24.2 MPa, and 9.79 MPa, respectively. Following these optimizations, power generation efficiency increases from 30.6 % to 35.2 %, accompanied by rises in live steam pressure of 10.28 MPa, reheat steam pressure of 1.74 MPa, and feedwater temperature of 78.2 degrees C.