The paper analyses operating and developing technologies for hydrogen implementation, transition, and storage at operating thermal power plants (TPPs) to make recommendations for realization of perspective projects for evaluation of the use of hydrogen as a fuel. Over the medium-term horizon of the next decade, it is suggested that using the technology of burning a mixture of hydrogen and natural gas in gas turbines and gas-and-oil-fired boilers in volume fractions of 20% and 80%, respectively, be implemented at operating gas fired TPPs. We consider the construction of the liquefied hydrogen and natural gas storage warehouses for the required calculated quantities of the gas mixture as a reserve energy fuel for operating the TPPs. We consider the possibility of the reserve liquid fuel system being replaced by the technology involving storage of liquefied hydrogen in combination with natural gas. An economic assessment of the storing cost of reserve fuel on the TPP site is given. The paper suggests that the methane-hydrogen mixture be supplied to the TPP site by two independent gas pipelines for the possibility of using the mixture as the main fuel and to exclude fuel storage at the plant.
The paper considers the integration and joint operation of a methane steam reforming unit (MSRU) and a heat pump unit (HPU) at a thermal power plant (TPP) as one of the possible ways to follow the global decarbonization policy. Research methods are simulation modeling of a thermal power plant in the program “United Cycle” and analysis of thermodynamic cycles of heat pumps. The Petrozavodskaya combined heat and power plant (CHPP) was selected as the object of the research. During the research, technological schemes for hydrogen production at the Petrozavodskaya CHPP were developed: with steam extraction to MSRU from a live steam collector and with the use of production steam. A scheme for HPU integration is proposed to reduce the cost of hydrogen and to reduce waste heat. A heat pump is used to preheat natural gas before going to MSRU. A method for determining fuel costs for hydrogen production in the trigeneration cycle of a thermal power plant was developed. The minimum specific fuel consumption for hydrogen production—7.854 t ref.f./t H2—is achieved in the mode with steam extraction to MSRU from the turbine PT-60-130/13 (industrial extraction with a flow rate of 30 t/h). At this mode, the coefficient of fuel heat utilization is the highest among all modes with hydrogen production—66.18%.
THE PURPOSE. To consider the actual problem of determining the optimum value of the connected heat load to the cogeneration combined cycle gas turbine (CCGT) of the heat generation profile. METHHODS. Simulation modeling of operation modes using the "United Cycle" software is applied as a research method of the considered power unit operation. We studied several regimes of heat supply from the considered CCGTs during the heating period with the determination of integral annual indicators, as well as the relative fuel savings compared to the separate generation and the increase in the specific integral economic effect for different values of the cogeneration coefficient.RESULTS. We found that the optimal cogeneration coefficient for the object of study is 0.49. However, the value of the optimal cogeneration coefficient, determined by the condition of maximizing the specific integral economic effect for the object of research, is also 0.49. CONCLUSION. Determining the optimal unit commitment, which influences not only the initial investment, but also the expected operating (fuel) costs, is a pressing issue in power plant design. We present a basis for the possibility of using the indicator of relative fuel economy compared to separate generation as an optimization criterion. This parameter is widely used for optimization of combined heat and power units under conditions of planned economy. Under current economic conditions, it is possible to obtain a direct link between the incremental net discounted income from combined production and the relative fuel savings. This method can be used to analyze and optimize the mix of CCGT equipment regardless of geographical area, type of power system, energy resources cost, market conditions, as well as the characteristics of the used equipment.
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