Taking CO₂ absorption by amine solutions in industrial-scale spray towers as the research object, a computational fluid dynamics (CFD) model is established to describe the gas-liquid two-phase flow, interphase heat and mass transfer, and chemical reaction process in industrial-scale spray scrubber, based on the Euler-Lagrange method. The reliability of the CFD model is validated by experimental data of CO₂ absorption by monoethanolamine (MEA) solution. On this basis, the fundamental laws of heat and mass transfer and chemical reactions accompanying the CO₂ absorption process, as well as the effects of the absorbents’ chemical composition, gas-liquid phase flow characteristics, and operating pressure on the efficiency of CO₂ removal in a spray tower were investigated. The numerical results indicate that, the volume fraction of CO₂ in flue gas decreases with the increase of scrubber height, while both the gas temperature and water vapor pressure firstly increase and then decrease with the increase of elevation. With the increase of CO₂ load in lean solution from 0.1 to 0.4, the highest gas temperature in the scrubber declines from 70 ℃ to 54 ℃. The overall decarbonization efficiency for the spray scrubber significantly decreases when the load of lean solution is greater than 0.25. When the superficial gas velocity is greater than 2.5 m/s, the enhancement of increased mass transfer specific interface area on CO₂ absorption is restricted ascribed to the declines of gas residence time and mass transfer coefficient. For the decrease of operating pressure in spray scrubber from 101 kPa to 70 kPa, the CO₂ removal efficiency decreases by about 15.9 percentage points.

To investigate the dominant role and mechanism of solid particles in enhancing mass and heat transfer and catalytic effects during CO₂ desorption from rich liquids, nano-titanium dioxide (TiO₂) and zeolite (HZSM-5) are selected as representative particles to represent the enhancement of heat and mass transfer and chemical catalytic effects, respectively. A continuous stirring reactor was set up, and the ratio of CO₂ desorption rate from rich liquids with and without particle addition was defined as the desorption enhancement factor. The effects of varying particle mass fraction, particle size, stirring speed, CO₂ loading of the rich liquid, and absorbent type on the CO₂ desorption enhancement were systematically investigated. The results show that, the HZSM-5 particles achieve a higher desorption enhancement factor compared with the TiO₂ particles, this is primarily due to the higher micropore surface area and Brønsted acid site coupling parameters of HZSM-5 particles. Additionally, the desorption enhancement factor for TiO₂ is less affected by operational conditions, fluctuating between 1.00 and 1.20. In contrast, increasing the particle mass fraction and CO₂ loading in the rich liquid significantly enhances the desorption effect of HZSM-5, with the desorption enhancement factor reaching up to 2.25. A linear relationship was observed between the HCO₃^– concentration in the rich liquid and the desorption enhancement factor for HZSM-5, indicating that HZSM-5 particles promote the CO₂ desorption process by enhancing the reaction pathway related to HCO₃^–. This finding provides a theoretical basis for further optimizing the design of solid particles and improving CO₂ desorption efficiency from rich liquids.

In the oxygen combustion CO₂ cycle, heat integration of the air separation unit (ASU) is commonly used to improve the matching of the heat recovery process. However, the ASU heat integration increases the heat recovery load, and the relatively low load ramp rate of the ASU affects the overall performance of the system. To eliminate the need for ASU heat integration and further enhance cycle efficiency, a method involving split adiabatic compression is proposed to balance the thermal capacities of the hot and cold streams. A power generation system model based on the gasification oxygen combustion CO₂ cycle is developed in Aspen, and the thermodynamic performance of the system, as well as the effect of ASU heat integration, are analyzed. A recompression system is also introduced for comparison. The results show that, the conventional system with integrated ASU heat has a net efficiency of 43.39%. Compared with a system without heat integration, the power consumption of the ASU increases by 19.9 MW, while 180.8 MW of heat integration is provided, resulting in a 1.64 percentage points increase in net efficiency. Considering limitations in heat recovery, the optimal split mass flow rate for the recompression system is 258.2 kg/s. Compared with the ASU heat integration, the recompression system reduces the heat recovery load by 59.8 MW, and the average heat exchanger temperature difference is further reduced by 3.1 ℃, improving the net efficiency to 43.52%. The study reveals the mechanism by which heat integration affects the efficiency of the oxygen combustion CO₂ cycle and proposes an optimization to decouple the power cycle from the ASU heat integration through the recompression process, providing theoretical guidance for the parameter design of the recompression system.

When thermal power units employ amine-based carbon capture, electro-carbon coupling exists. To enhance the load flexibility tracking performance of decarbonized units, a variable-load control strategy based on electric-carbon coordination is proposed. Using existing data, an electric-carbon coordinated control system model for drum boiler thermal power units was established through system identification. The response time scales of reboiler load to power generation load and carbon capture rate were analyzed. Based on this, a dual-control loop for power generation load was designed, incorporating both decarbonization steam extraction and fuel quantity regulation. Furthermore, to address the effect of long time scales on carbon capture rate, the transient quantities of reboiler load variation throughout the process were reconstructed, and a flexible power generation load control method based on electric-carbon synergy was proposed. Simulation tests on a 300 MW unit demonstrated that, compared with the conventional coordinated control strategies, the proposed strategy ensures performance metrics for thermal load and carbon capture rate while improving both the load variation control rate and AGC performance metrics by an average of 100% or more.

As the global climate change intensifies, carbon capture, utilization and storage technology (CCUS) has become a crucial means to achieve the goal of carbon neutrality. Focusing on addressing the issues of poor operational stability and high regeneration energy consumption in conventional absorption agents, a new water-poor compound absorption agent was developed, which is mainly composed of tert-butyl aminoethanol (TBAE). The absorption agent was optimized by combining different ratios of amines and stabilizers and was mixed at a total amine mass fraction of 30%. The CO₂ absorption-desorption performance, corrosion situation, and small-scale upscaling experiment were tested and investigated using 30% (mass fraction) conventional absorption agent ethanolamine (MEA) as a reference standard. The aim is to enhance the CO₂ absorption capacity and desorption rate while reducing regeneration energy consumption and improving the stability of the solvent in the device. The experimental results indicate that, when the formula is 20% TBAE + 10% 3-methyl-1-propanol + 50% N-methylpyrrolidone, the saturated CO₂ absorption capacity is 3.10 mol/L, the cyclic absorption capacity is 2.97 mol/L, the corrosion rate is 0.016 2 mm/a, and the regeneration energy consumption is 4.00 GJ/t. Compared with the 30% MEA absorption agent, the saturated CO₂ absorption capacity increases by 12.3%, the cyclic capacity rises by 22.7%, the corrosion rate reduces by 60.3%, and the regeneration energy consumption decreases by 36%. The excellent basic performance of the new water-poor compound absorption agent and its long-term stable and low-energy operation in a 10 t/a carbon capture small-scale pilot plant have laid a solid foundation for its future industrial application.

In post-combustion CO₂ capture, organic amine absorbents are prone to degradation, forming heat-stable salts (HSS) that impair absorption performance and accelerate equipment corrosion. Electrodialysis (ED), operating under ambient conditions with high HSS removal efficiency, has emerged as a promising technology for amine recovery. This review systematically summarizes recent advances in ED for amine solvent recovery, covering the configurations of different ED systems and the mechanisms by which key process parameters (voltage, current density, initial HSS concentration, CO₂ loading, etc.) affect removal efficiency, amine loss, and energy consumption. It highlights process optimization strategies such as multi-stage membrane stacks and ED coupling with resins or bipolar membranes, and compares industrial performance data across different applications. Finally, challenges related to membrane stability, energy consumption, and cost control are discussed, with perspectives on future development directions for ED-based amine recovery in carbon capture systems.

Ammonia-coal co-firing is one of the important ways to achieve carbon reduction of coal-fired thermal power units, but the research on high proportion ammonia co-firing is rare. In order to further explore the feasibility of high-proportion ammonia co-firing, the mechanism model of ammonia-coal co-firing is established, and the ammonia-coal co-firing and pure ammonia combustion process of 4 MW boiler is simulated by using computational fluid dynamics (CFD) method. The error between CFD calculation results and experimental data is less than 3%. The experimental results show that, when ammonia is co-fired with coal, the flame temperature decreases by about 30 ℃ and the carbon dioxide volume fraction decreases by about 20% for every 20% increase in the co-firing ratio. When the ammonia co-firing ratio is increased from 0 to 40%, the NO volume fraction at the furnace outlet increases by about 77.33%, and the carbon content in fly ash increases from 4.65% to 6.16%; when it is increased from 0 to 60%, the NO volume fraction increases by about 136.44%. When excess air ratio of ammonia-coal co-firing is 1.15, the fuel burnout and nitrogen oxide generation are optimized. The two-stage input of ammonia fuel can reduce the NO volume fraction at the furnace outlet by 31.07% compared with the ungraded input. Compared with the combustion flame of coal combustion and ammonia-coal co-firing, the flame temperature of pure ammonia combustion is lower, the ignition distance is longer and the tangent circle diameter is larger. When pure ammonia is fired, the NO mass concentration at the furnace outlet is 475 mg/m³, and the escaping ammonia concentration is close to 0.

Large-scale hydrogen production technology from renewable energy such as solar power and wind power has become an important pathway for the consumption of renewable energy and the achievement of “dual carbon” goals. The policies and strategic layout of hydrogen energy at home and abroad are introduced, and the advantages and technical bottlenecks of water electrolysis technologies are analyzed. Moreover, the classification, coordination control optimization and energy management of large-scale renewable energy hydrogen production systems are sorted out. In view of the current development status of hydrogen energy in China, a brief analysis of the current installed capacity and the cost is performed, providing a reference for the construction of green hydrogen production system and the clean substitution of terminal energy in China.

With the grid-connection of renewable energy systems, more coal-fired units are required to participate in deep-peak-shaving and quickly respond to the automatic generation control command. Therefore, the controllers of coal-fired units should not only have satisfactory dynamic performance but also have strong robustness. However, the tuning of proportional-integral (PI) controllers which are widely applied to coal-fire units usually takes the dynamic performance into account and robustness in the application of PI controller parameter tuning is lack. Thus, the maximum-sensitivity-constrained desired dynamic equation (DDE) PI is proposed to obtain good dynamic performance and strong robustness. Simulations and field tests on the hot primary air system of the coal pulverizer indicate that, the proposed control method has better disturbance rejection performance and stronger robustness, which can effectively handle with uncertainties caused by the wide load variation of the unit.

In the context of building a new type of power system with new energy as the main body, it is required that thermal power units undertake more peak shaving tasks, and coupling heat storage tanks is one of the effective ways for units to improve the peak shaving capability. In order to solve the operation scheduling problem of heat storage tanks and units in the context of peak shaving auxiliary service market, thermal system simulation is conducted on combined heat and power (CHP) units to obtain coal consumption and operational safety zones that reflect the actual operating conditions of the units. After that, an optimization model for the CHP system coupled with heat storage tank is established. Aiming to maximize the net profit of the system, this article intelligently optimizes the hourly operation scheduling of a certain CHP and heat storage tank. The results show that, the heat storage process of the thermal storage tank occurs during the electricity price period, and the heat release process varies depending on the heating load. During the high cold period with high heat load, heat is only released during the electricity price valley period, while during the early and late stages with low heat load, heat is released during the valley and peak periods. The net income of the system decreases with the increase of heating load. Running the entire heating season with the optimized scheduling in this article can increase revenue by 21.13 million yuan per year, with a static investment payback period of 5.22 years.