Techno-economic analysis of deep peaking for hydrogen co-firing in a 300 MWe subcritical power plant with hydrogen production from valley electricity

As the proportion of renewable power generation increases annually, thermal power plants are supposed to operate in deep peaking with high flexibility to balance power supply and power demand as well as ensure grid security. Hydrogen co-firing in thermal power plants is one of the promising approaches to maintaining stable combustion during deep peaking periods, improving peak capacity, and reducing carbon emissions. This paper numerically investigated the thermodynamic performance of deep peaking at 30 % and 20 % heating loads for hydrogen co-firing in a 300 MWe subcritical power plant using the Aspen Plus model and conducted an economic analysis of four scenarios of boiler deep peaking and hydrogen production from valley electricity. The results show that as the hydrogen blending heat ratio increases from 0 % to 15 % with the constant total excess air ratio of 1.15 at 30 % heating load, the boiler thermal efficiency increases from 91.13 % to 92.05 %, the standard coal consumption decreases from 395 g/kWh to 331 g/kWh, and the CO₂ emission per unit of fuel heat input also drops from 132.52 g/MJ to 112.55 g/MJ. If the boiler heating load is further adjusted to 20 %, hydrogen blending and oxygen enrichment can also improve the theoretical combustion temperature and boiler efficiency, as well as save coal and reduce carbon emissions. Regarding the economic analysis, the prices of standard coal and electrolyzers are two key factors affecting the payback time. As the capacity of electrolyzers decreases from 60 MW in Scenario 2 to 20 MW in Scenario 4, the payback time drops from 10.45 years to 3.63 years. In the meantime, the hydrogen blending heat ratio also decreases from 15 % to 5 % at 20 % heating load. There exists a tradeoff between a high hydrogen blending ratio (which means more stable combustion at low heating loads) and a short payback time.