Selective catalytic reduction (SCR) flue gas denitrification systems are inherently complex, typically embodying characteristics of non-linearity, significant time delays, and susceptibility to multiple disturbances. In the context of coal power units engaging in deep load cycling and rapid frequency adjustment, conventional proportional-integral-derivative (PID) control struggles to meet the demands of effective control. This study introduces a control strategy that incorporates a “state observer + Linear Quadratic Regulator (LQR) state feedback + Improved Quantum Genetic Algorithm (IQGA) optimized PID”. Initially, local linear mathematical models of an SCR denitrification system at 340 MW, 450 MW, and 540 MW loads were used to design state observer and LQR state feedback control parameters for each operational condition. At a single load point, the IQGA was employed to optimize the outer loop PID parameters, followed by simulation experiments of load increases and decreases between 340 MW and 540 MW. The results demonstrated that, compared to two other strategies, the proposed approach reduced the overshoot by a minimum of 1.5% and shortened the adjustment time by 31.7% under conditions of step disturbances and internal perturbations. Throughout variable operational conditions, the strategy consistently exhibited minimal output fluctuations, rapid adjustment capabilities, strong disturbance rejection, and robust stability. This algorithm proves to be an effective method for controlling NOx concentrations, offering insights for precise ammonia injection control in future applications.

Molten salt thermal energy storage (TES) coupled with coal-fired power units is regarded as one of the most promising routes for deep peak-shaving retrofits. Among the available heat-discharge options, using molten salt to replace the regenerative extraction steam for feedwater heating offers the simplest configuration and the lowest retrofit cost. Existing studies, however, predominantly rely on steady-state platforms or system-level lumped-parameter simulations, and therefore fail to resolve the transient heat transfer inside the heat exchanger, which is in fact the dominant bottleneck restricting the load ramp rate. This paper establishes a dynamic model of the load response in this mode for a 660 MW supercritical unit. The high-pressure feedwater heater (HPH) is modelled as three zones, with Nusselt film condensation corrected for tube rows on the shell side, a piecewise Nusselt correlation covering the laminar, transition and turbulent regimes on the tube side, and a dimensionless correction referenced to the rated heat balance for the migration of fluid properties. A nine-stage-group turbine model based on the Flügel formula turns the redistribution of extraction steam into the power output. The feedwater flow rate is stepped down to 0 % (full bypass), 30 %, 50 % and 80 % of the design value at 30 %, 50 % and 75 % turbine heat acceptance (THA). Both the mean feedwater temperature and the shell-side pressure then rise without overshoot along an approximately first-order path, and the settling time is set by the tube-side water inventory rather than by the heat storage of the tube-bundle metal. The settling time shortens as the unit load rises. The maximum load increment reaches 16.4 MW (2.5 %Pe), 32.2 MW (4.9 %Pe) and 58.8 MW (8.9 %Pe) at 30 %, 50 % and 75 % THA, respectively, and the corresponding standard average ramp rate over the 10 %–90 % steady-state band is 1.95, 5.58 and 15.8 %Pe/min. The results provide a basis for designing and controlling such retrofits.

Molten salt thermal energy storage (TES) coupled with coal-fired power units is regarded as one of the most promising routes for deep peak-shaving retrofits. Among the available heat-discharge options, using molten salt to replace the regenerative extraction steam for feedwater heating offers the simplest configuration and the lowest retrofit cost. Existing studies, however, predominantly rely on steady-state platforms or system-level lumped-parameter simulations, and therefore fail to resolve the transient heat transfer inside the heat exchanger, which is in fact the dominant bottleneck restricting the load ramp rate. This paper establishes a dynamic model of the load response in this mode for a 660 MW supercritical unit. The high-pressure feedwater heater (HPH) is modelled as three zones, with Nusselt film condensation corrected for tube rows on the shell side, a piecewise Nusselt correlation covering the laminar, transition and turbulent regimes on the tube side, and a dimensionless correction referenced to the rated heat balance for the migration of fluid properties. A nine-stage-group turbine model based on the Flügel formula turns the redistribution of extraction steam into the power output. The feedwater flow rate is stepped down to 0 % (full bypass), 30 %, 50 % and 80 % of the design value at 30 %, 50 % and 75 % turbine heat acceptance (THA). Both the mean feedwater temperature and the shell-side pressure then rise without overshoot along an approximately first-order path, and the settling time is set by the tube-side water inventory rather than by the heat storage of the tube-bundle metal. The settling time shortens as the unit load rises. The maximum load increment reaches 16.4 MW (2.5 %Pe), 32.2 MW (4.9 %Pe) and 58.8 MW (8.9 %Pe) at 30 %, 50 % and 75 % THA, respectively, and the corresponding standard average ramp rate over the 10 %–90 % steady-state band is 1.95, 5.58 and 15.8 %Pe/min. The results provide a basis for designing and controlling such retrofits.