Reheat Steam Research Articles

Air Oxidation Behavior of Sanicro-25 with Different Surface Finishes

AbstractSanicro-25 is a high-temperature material used as the structural material for steam superheaters and reheaters in advanced ultra-supercritical power plants. The air oxidation behavior of Sanicro-25 with various surface roughnesses is being assessed at 650 °C for about 1000 h. Different surface-roughened samples were studied, namely polishing the sample up to diamond finish, grinding up to (80-grit finish and 600-grit finish) and grit blasted. The diamond finish sample showed more weight gain than others, and higher weight gain was observed in the initial oxidation stage. Attributed to different surface preparations leads to defects at different levels, which further alters the diffusion of various elements. The diamond finish sample showed the presence of Cr-rich oxides, and other samples showed the presence of Fe-rich oxides. Smooth surfaces promoted the formation of thick protective oxide scales.

Integration and capacity optimization of molten-salt heat storage in coal-fired power plant with carbon capture system

Developing a new generation of economical, low-carbon, and flexible coal-fired power plants (CFPP) is crucial for achieving the low-carbon transformation of the energy industry. Deploying molten salt heat storage (MSHS) in the CFPP can effectively enhance its peak shaving capability and reduce the limitations of carbon capture on wide range operation of the plant. To this end, this paper proposes four integration schemes for MSHS into the power plant-carbon capture system. The thermal efficiencies, exergy efficiencies, and peak shaving capabilities of the entire plant under different integration schemes are evaluated and compared. The results indicate that the optimal integration scheme involves utilizing hot reheat steam to heat the cold molten salt and further provide heat for the carbon capture system during the heat charging process and utilizing hot molten salt to heat the outlet water of the feed water pump during the heat discharging process, which achieves the highest thermal efficiency of 38.00 % and exergy efficiency of 37.09 % across the entire cycle. A novel integrated design, scheduling, and control optimization (IDSCO) method is proposed to find the optimal capacity configuration of MSHS, in which the investment, maintenance, fuel, carbon emission, and long-timescale and short-timescale load tracking deviation penalty costs are fully considered. A design parameter-aware control system is developed based on a multi-parametric programming model predictive control approach to ensure a fair evaluation of closed-loop dynamic performance under different configuration capacities. The simulation results demonstrate that the deployment of MSHS can significantly enhance the flexibility of the power plant-carbon capture system and the proposed IDSCO approach can reduce 17.05 % of load tracking deviation penalty cost and 1.38 % of totalized cost compared to the conventional configuration approach. This paper effectively leverages the potential of MSHS in enhancing the operational flexibility of CFPP-PCC system, thereby providing useful guidance for future deployment of MSHS within CFPP-PCC system.

CO2 emission characteristics modeling and low-carbon scheduling of thermal power units under peak shaving conditions

To accommodate the high penetration of renewable power, the operational flexibility of thermal power units is highly required by the power system, so thermal power units frequently operate under peak shaving conditions. The CO2 emission characteristics of a thermal power unit are significantly influenced by the load factor, and also by the installed capacity and design parameters of the thermal power unit. Therefore, detailed CO2 emission characteristics of thermal power units should be modeled and considered in the low-carbon scheduling of the power system. In this study, thermal power units are classified by live steam parameters, installed capacities, reheat stages, cooling modes, and operation modes, and the models of detailed CO2 emission characteristics are developed and validated. The turbine isentropic efficiency, boiler thermal efficiency, and auxiliary power consumption are comprehensively considered in the CO2 emission model. A new indicator is defined to evaluate the reduction of carbon emissions in a power system when a TPU accommodates per unit of renewable power generation, and an optimization method for low-carbon scheduling based on it is proposed. Finally, a reference case study is conducted. Results show that the total carbon emissions for a day of the proposed low-carbon scheduling method are 0.06 %−0.20 % less than the efficiency priority method, and 1.53 %−2.36 % less than the capacity weighting method.

Costs versus revenues of flexibility enhancement techniques for thermal power units in electricity-carbon joint markets

Thermal power units (TPUs) are required to enhance operational flexibility to ensure power grids accommodate the increasing penetration of intermittent renewables. The flexibility enhancement includes increasing peak shaving depth, increasing ramp rate, or both. In electricity-carbon joint markets, increasing peak shaving depth means TPUs can generate less electricity during low-tariff periods while increasing ramp rate means TPUs can respond faster to changes in electricity tariffs. Flexibility enhancement brings additional revenues, but also additional investments. The tradeoff between costs and revenues is important for the construction of sustainable power systems mainly based on renewables, but limited literature models them. To address this gap, variable costs, fixed costs, revenues, and an optimization model for maximum profits are proposed and modeled. Then the economic applicability of different flexibility enhancement aspects is evaluated by comparing the maximum profit increase for a day before and after the flexibility enhancement of TPUs. Furthermore, the profitability of applying different flexibility technologies under the same investments is analyzed, obtaining the optimal flexibility enhancement route. The proposed method is applied to TPUs with different live steam parameters, installed capacities, and reheat stages. Numerical simulations provide detailed economic analysis and optimal flexibility enhancement routes for TPUs in electricity-carbon joint markets.

Rational Mode Parameters of Power Units Operating in Modern Energy Market Conditions

The paper analyzes the operation of condensing and heating turbines in modern energy market conditions with an assessment of the impact of operating parameters of live and secondary steam on economic indicators. It has been shown that when operating at variable loads, the most effective in terms of high-pressure turbines is a rational reduction in the initial pressure ps (sliding pressure), which leads to an increase in thermal efficiency by 1-1.5%. The experimental results of a study of the vacuum effect in the condenser on fuel consumption are presented in the paper as well. Using a specific example of the K-320-26.5 turbine unit, the need for a rational choice of cooling water flow in winter season to ensure optimal vacuum is shown. The issue of choosing a rational steam reheat temperature tr is examined in more detail. It has been established that one of the main reasons for the decrease in the efficiency of turbine units when operating in variable modes is the irrational use of the reheat temperature and the heat of phase transition in the flow part of the low pressure cylinder. The physical explanation of these processes in the turbine as tr decreases is given in detail. It has been shown that, as a result of analyzing the operation of turbine units of various capacities, a rational choice of reheat temperature (reducing tr by 10-20 °C) increases thermal efficiency by 1-2 %, and turbine efficiency - by 0.4-1.0 %. It is recommended to consider the pressure of the hot steam of the high pressure cylinder (рs), the pressure in the condenser (рc=f(tcirc.water)), as well as the reheating temperature tr, which altogether leads to a reduction in heat consumption by 2.5-3.5 % as rational parameters of steam when operating in variable modes. In order to increase the economic efficiency of the operation of turbine units of TPPs and CPPs at reduced loads, it is recommended to revise the regulatory documentation on the current amendments for changes in the reheat temperature. It is stated that with strict adherence to the recommendations discussed above, fuel savings at TTPs and CHPs in Ukraine can amount to 250–300 thousand tons of coal per year.

Thermal energy storage integration for increased flexibility of a power plant with post-combustion CO2 capture

Flexible operation of thermal power plants will become increasingly relevant in the coming years. This work evaluates the effect of integrating a steam accumulator into a 598 MW supercritical coal-fired power plant with moving bed temperature-swing adsorption CO2 capture. Charging the accumulator with reheat steam from the turbine train can reduce the net power output by up to 1.4 % (8.2 MW) for around 200 min. Small charging flow rates are recommended to maximize the final pressure of the accumulator. Covering the sorbent regeneration duty and meeting the demand of two feedwater heaters were considered as alternatives for discharging of the accumulator. Thermal storage discharging was found to give relative power plant load increases between 1.7 and 11.2 % (10.2–66.9 MW) for up to 37.5 min, which exceeds the requirement for primary reserve. Increases in the electrical energy output of 10.5–11 MWh were achieved. The flexibility modes studied in this work are compatible with high CO2 recovery rates.

Performance evaluation and operation optimization of a combined heat and power plant integrated with molten salt heat storage system

Combined heat and power is an effective way to enhance the energy efficiency of thermal power plants. The solar and wind power are intermittent, and dispatchable power sources are critical to balance the supply and demand sides. To facilitate the high penetration of renewable energy, combined heat and power (CHP) plants should provide more and more peak shaving services for the power grid. The thermal energy can be stored in and released from the molten salt heat storage system (MSHSS). The integration of MSHSS can enlarge the adjustable range of the power load of CHP plants, so it is a potential way to enhance the operational flexibility of CHP plants supplying industrial steam and power. In this study, the MSHSS integrated within CHP plants are proposed, which store a part of sensible heat energy carried by extraction steam before supplying to industrial users. The heat storage capacity dominates the flexibility enhancement, and indicators to evaluate energy performances of the proposed system are defined. Moreover, models for the operation optimization of CHP plants integrated with the MSHSS are developed, and a case study of a 350 MW CHP unit is conducted. When the reheat steam is extracted to supply to industrial steam, the maximum and minimum adjustable power loads can be increased and decreased by 17.13 and 12.01 MW, respectively with the integration of the MSHSS. Moreover, during the peak, flat, valley time of reference day, the heat supply coal consumption rates are 73.94, 74.19 and 81.03 kg t−1,respectively. With the operation scheduling of CHP plant integrated with MSHSS, the MSHSS with reheat steam as heat source show the lowest coal consumption rate as 1553.79 ton/day.

Enhancement of thermal power plant performance through solar-assisted feed water heaters: An innovative repowering approach

Increasing the efficiency of a power plant by optimization or repowering has always been a crucial challenge for energy analysts. At the same time as natural energy resources are limited, the integration of renewable energy sources such as solar energy has been prioritized for the past few decades. This study presents a way of enhancing a thermal power plant with a regenerative reheating Rankine cycle, evaluating the impact of solar-powered heat exchangers on feed water heating at 200 MW single unit of the Shahid Montazeri Power Plant operating at 13 MPa and 540 °C. Increases in energy-exergy efficiencies, power output and fuel save due to this modification have been studied in 14 different cases which have been analyzed in Engineering Equation Solver (EES). The case studies cover replacing single, double, and triple Feed Water Heaters (FWH). Parametric analysis of the four most promising cases has been performed in varying operating conditions such as main steam and reheat steam temperature and pressure and condensation pressure. In the most favorable configuration (case 12), the net thermal power output increases to 225 MW while energy and exergy efficiency increases to 39.73 % and 43.99 % respectively. Exergy and energy loss across different major components have been presented as well which indicates room for further improvement and contributes valuable insights to thermal power plant optimization for sustainable and efficient energy solutions in the future.

Design and performance evaluation of thermal energy storage system with hybrid heat sources integrated within a coal-fired power plant

The operational flexibility of coal-fired power plants (CFPPs) should be effectively enhanced to accommodate large-scale photovoltaic and wind power within the power grid. The integration of thermal energy storage (TES) systems is a potential way to enlarge the load-cycling range of CFPPs. To achieve high operational flexibility of CFPPs and high round-trip efficiency of TES systems, TES systems with hybrid heat sources including the heat converted from power by power-to-heat (P2H) devices and transferred from the reheat steam integrated into CFPP were proposed. Then, simulation and thermo-economic analysis models were developed, and the system design procedure was provided. Results show the minimum power load ratio is decreased from 30 % to about 16 % by storing heat from the reheat steam within the TES system, and then to zero by converting electricity to heat with P2H devices. The mode P-basic constitutes two double-tank molten salt TES systems, which are charged by the heat converted from power by P2H devices and the heat transferred from the reheat steam, respectively. It is discharged by releasing the heat to water/steam cycle of CFPP, and the highest equivalent round-trip efficiency of mode P-basic is up to 62.97 %. Moreover, mode P-basic exhibits the largest total cost of the equipment and storage materials at $58.26 million while it has the largest net present value at $103.79 million and the corresponding payback period is 5 years.

The integration of seawater desalination system with nuclear power plant: Operational flexibility enhancement and thermo-economic performances

To accommodate the high penetration of renewable power, nuclear power plants (NPPs) should participate in peak shaving services, which has become a key issue restricting the efficient and reliable operation of NPPs. To enhance the operational flexibility efficiently, the seawater desalination system is integrated within a NPP in this paper. Thermo-economic performances of the proposed system were evaluated. When the main steam, inlet reheat steam, and outlet reheat steam of the NPP are extracted to drive the LT-MED desalination system, and the output power ratios of the integrated system can be decreased to 12%, 65%, and 61%. Therefore, the operational flexibility of the NPP can be effectively enhanced with the integration of desalination system. Then, the capacity and configuration of the LT-MED system were optimized, and gain output ratio and water production cost were used to evaluate performances of the integrated system. The water production cost reaches its minimum value of 0.64 $/m3, when the LT-MED desalination system decreases the output power ratio of the integrated system to 65%. The exergy efficiency of the integrated system is 7.9%, 18.3%, and 25.6% higher than that of AP1000 when the extraction steam is main steam, outlet reheat steam, and inlet reheat steam.

Improving flexibility of thermal power plant through control strategy optimization based on orderly utilization of energy storage

Operational flexibility in thermal power plants has assumed a growing significance in maintaining power grid stability primarily driven by the increased penetration of intermittent renewable energy sources. Substantial energy resides within the deaerator and boiler subsystems of thermal power plants, and optimizing the utilization of the stored energy is crucial for enhancing the operational flexibility of these plants. A novel coordinated control strategy, informed by the characteristics of distributed energy storage and power ramping stages of thermal power plants, is proposed. This control strategy systematically activates energy reserves within the deaerator, regenerative heaters, and boiler subsystems through load decomposition, valve regulation, and revised coal feeding rate, respectively. Control performance is subsequently assessed within a reference scenario. The results demonstrate a notable improvement in the control performance. The variations in the reheat steam temperature, main steam pressure, and output power are reduced by 2.0 °C, 0.47 MPa, and 2.4 MW, respectively. Moreover, the maximum power ramp rate increases from 1.5 % to 5.5 % Pe0 min−1. Furthermore, a substantial reduction in coal consumption of up to 7.09 % is achieved through the orderly utilization of energy storage. This study provides a comprehensive reference for enhancing the operational flexibility of power plants.

Determination of optimal total area of heat recovery steam generator

Heat recovery steam generator (HRSG) plays a critical role in recovering waste heat from exhaust gas in a combined cycle. The performance of the steam cycle in the combined cycle depends on total HRSG area. This paper presents a comprehensive study on the determination of the optimal total area of single-pressure HRSG considering various factors such as exhaust gas temperature, main steam temperature, main steam pressure, reheat steam pressure, and reheat steam temperature. The research methodology involves the development of a mathematical model of HRSG that considers the key parameters affecting the HRSG performance. It is shown that, for given exhaust gas temperature and total HRSG area, there exists the set of steam parameters that yields the maximum net power output of the steam cycle. Furthermore, the power output increases monotonically with total HRSG area. However, the power output increases at a decreasing rate as total HRSG area increases. The optimal total HRSG area is shown to depend on the unit selling price of electricity, the unit cost of heat exchanger, the capacity factor of the power plant, and the acceptable payback period for the investment in the installation cost of HRSG.

Enhancing the flexibility and stability of coal-fired power plants by optimizing control schemes of throttling high-pressure extraction steam

Regulating the thermal system configuration can improve the ramp-up rate of the coal-fired power plants during peak shaving transient processes, while it may bring penalties in the performance of the steam temperature control and thermal efficiency. This study simulated the load ramping up transient processes when throttling the extraction steam of high-pressure heaters. The results show that there is a gap between the needed energy and energy supply caused by drastic fluctuations of reheat steam flowrate. Control schemes of steam temperatures and fuel demands were revised considering the dispatch of the fuel and working medium. According to economic optimality, the order of throttling high-pressure heaters was optimized. By implementing the revised control strategies, the fluctuations of steam temperatures were diminished and the maximum deviation of live and reheat steam temperatures was reduced by 23.5 °C and 11.4 °C, respectively. The flexibility indicator was increased by up to double at most. The average standard coal consumption rate variations with and without the revised control schemes were compared and the maximum difference is 1.23 g kW−1 h−1 with 2.5 % Pe min−1. The flexibility and economic performance were both improved when adopting the revised control schemes.

Development of a three-term MPC and its application to an ultra-supercritical coal fired power plant

Most MPC (Model Predictive Control) algorithms used in industries and studied in the control academia use a two-term QP (quadratic programming), where the first term is the weighted norm of the output errors, and the second term is that of the input increments. In this work, a DMC (Dynamic Matrix Control) algorithm that uses three-term QP is developed and studied, where the third term is the weighted norm of the output increments. A relationship between the three-term DMC and the two-term DMC is established; and based on that, ideal closed-loop response curves are derived. These results are useful for the tuning of the three-term DMC. Then, a method for comparing two control methods is proposed and it is shown that the three-term DMC outperforms the two-term DMC. The findings are verified using simulation studies. Finally, the three-term DMC is successfully applied to a 1030 MW ultra-supercritical coal-fired power plant. According to simulation study using the identified model, in comparison to traditional two-term DMC, there is a roughly 10% reduction in the standard deviation of load tracking error for similar control efforts. In real-life tests on the power plant, the performance of the three-term DMC is compared to that of the existing PID controller. The load rate of change increased from 0.8%/min to 1.5%/min while the standard deviation of steam pressure decreased 38%; the standard deviations of the main steam temperature and reheat steam temperature decreased more than 40% with their mean values increased by more than 2 ∘C and 4 ∘C respectively.

Integration model and performance analysis of coupled thermal energy storage and ejector flexibility retrofit for 600 MW thermal power units

A flexible retrofitting method for thermal-energy-storage-coupled thermal power units is proposed. The exergy flow Sankey diagram and efficiency of the three charging methods was analyzed in detail, and comparative data were provided. The new thermal energy storage mode coupled with steam ejectors was the optimal solution, with a significantly higher round-trip efficiency than the published results. Further study of the mode revealed slight temperature variations in the molten salt did not affect system efficiency. As the extraction of reheated steam decreases and the extraction of main steam increases, the minimum generation capacity of the unit decreases continuously, reaching a minimum of 40 MW (6.67%). In contrast, the maximum output of the unit at 100% THA release can reach 682 MW, which caused the unit load to change from 26-100% to 6.67–113.67% before and after the retrofit. As the ejection coefficient increased, the round-trip efficiency increased significantly, corresponding to 73%, 77%, and 80% at the study points. The mathematical model based on principal component analysis can effectively characterize the relationship between the ejection coefficients, extraction of main steam, extraction of reheat steam, low valley peaking rate, peak modulation rate, and round-trip efficiency, providing a signal conversion basis for automatically controlling peaking commands during unit operation. Finally, the benefits before and after retrofitting were analyzed in terms of thermal plant operation, proving that the payback period of the system was 4.09 years. Peak tariff and auxiliary service revenue are the most critical parameters affecting the payback period, and a 10% reduction in the peak tariff corresponds to an increase in the payback period of one ∼ two years. The results of this study provide substantial theoretical and practical guidance for the flexible retrofitting of thermal power units.

Energy, exergy, and economic analyses on coal-fired power plants integrated with the power-to-heat thermal energy storage system

To accommodate high penetration of intermittent renewable power, including wind power and photovoltaic power, coal-fired power plants (CFPPs) are forced to enhance operational flexibility. The integration of a power-to-heat thermal energy storage (TES) system within a CFPP is a potential solution. In this study, the power-to-heat TES system was integrated within a CFPP, and the stored heat is released to heat live steam (scheme C1), reheat steam (scheme C), and high-pressure heater feedwater (scheme C3). The thermodynamic and economic performances of power-to-heat TES systems are evaluated and compared. Results show that the power-to-heat process can achieve zero output of CFPPs, but it has an exergy loss coefficient of more than 40%. When the boiler maintains a 75% rated thermal load, schemes C1, C2, and C3 can maximally increase output power by 150.0, 96.5, and 50.0 MW, accounting for 25.0%, 16.1%, and 8.3% of the rated load, respectively. Scheme C2 achieves the highest equivalent round-trip efficiency of 50.81%, which is slightly higher than that of scheme C1 (50.74%). Scheme C1 exhibits the lowest total cost of the equipment and storage materials at 63.68 million USD, and its net present value and payback period are 25.0 million USD and 13.5 years, respectively.

Performance and economic analysis of steam extraction for energy storage to molten salt with coupled ejector and thermal power units

A new thermal power unit peaking system coupled with thermal energy storage and steam ejector was proposed, which is proved to be technically and economically feasible based on the simulation of a 600 MW thermal power unit. Results show that the percentage of exergy losses in the retrofitted system is in the order of condenser, turbine and thermal energy storage system, with the exergy losses in the heat release process accounting for approximately 70 % of the cycle. The condenser and evaporator corresponding to the storage and heat processes account for 60 % of the total exergy losses in thermal energy storage system. The retrofitted system has a maximum cycle efficiency of 70–80 % with low and peak modulation rates of 16.5 % and 11.7 %. Extraction of main steam dominates the peaking rate and cycling efficiency compared to extraction of reheat steam. Increasing the main steam pressure at the ejector inlet increases the low peaking rates by 1.5 %, while reducing the molten salt flow rate per unit peaking depth by 10 t/h, which is essential for the stable operation of the retrofitted system. The economic analysis of the retrofitted system shows that the system operating time is the main factor affecting the payback period compared to the interest rate and starts to be profitable in 3.8 years, with later profitability of up to RMB 25 million/year. Further analysis reveals that two different extractions of reheat steam with the same extraction of main steam will achieve the same payback period, which offers a variety of possibilities for practical operational scenarios. In addition, when the extraction of main steam is <250 t/h, the payback time of the system will exceed 15 years, at which point it will be challenging to meet the economic viability of the retrofitted system.

Revealing steam temperature characteristics for a double-reheat unit under coal calorific value variation

Currently, the severe fluctuation of steam temperature in double-reheat (DR) ultra-supercritical (USC) units has become a major problem that constrains their efficient and flexible operation, wherein the deviation of coal calorific value from the design value is one of the major reasons for this issue. However, the effect of coal calorific value variation on the steam temperature characteristics during the flexible operation of DR USC units remains unclear. A dynamic model of a 1000 MW DR USC unit is developed with primary principles and validated with real operation data. The effect of the coal calorific value variation on the steam temperature characteristics is revealed. Results show that as the calorific value of the coal increases, the main steam temperature can always maintain at the design value with attempering water adjustments, while the two reheat steam temperatures decrease. The steady-state deviations of the reheat steam temperatures are positively correlated with the magnitude of the coal calorific value variation, where the deviation of the secondary reheat steam temperature is larger. Meanwhile, as the load increases, the steady-state deviations of reheat steam temperatures increase, but the response time decreases. Finally, the effect of calorific value variation on the boiler efficiency is studied. As the coal calorific value increases, the boiler efficiency firstly rises caused by the decrease in the loss of the flue gas and then falls caused by the limited furnace temperature increase. This study provides guidance on the DR USC boiler operation under coal variation.

Power grid load frequency control based on Fractional Order PID combined with pumped storage and battery energy storage

With the increasing proportion of installed renewable energy power generation capacity and the introduction of quantitative energy storage policies for new energy power generation. In view of the influence of intermittent and volatility of distributed generation on the safe of power grid, it is​ particularly important in the future to equip reasonable energy storage to ensure the flexibility of power system. In this paper, a load frequency control (LFC) strategy of hybrid energy storage based on fractional order proportion integral derivative (FOPID) is proposed to solve the frequency modulation problem of battery energy storage system (BESS) and pumped storage station (PSS) participating in the interconnection network. Firstly, the LFC model is established under the nonlinear factors such as regulator dead zone and generation rate constraint on a two-area reheat steam turbine. Secondly, a FOPID controller is designed. Furthermore, the combined LFC simulation is carried out by adding BESS under the two working operations of PSS generating and pumping. Finally, the influence of demand response is considered in the hybrid energy storage control.

Termodinamička analiza i usporedba dviju propulzijskih parnih turbina

This paper presents thermodynamic (energy and exergy) analysis and comparison of two different marine propulsion steam turbines based on their operating parameters from exploitation. The first turbine did not possess steam reheating and had only two cylinders (high-pressure and low-pressure cylinders), while the second turbine possesses steam reheating and has one additional cylinder (intermediate-pressure cylinder). In the literature at the moment, there cannot be found a direct and exact comparison of these two marine steam turbines and their cylinders based on real exploitation conditions. Along with energy and exergy analyses, the research it is investigated the sensitivity of exergy parameters to the ambient temperature change for both turbines and each cylinder. It is also presented the influence of the steam reheating process on the energy and exergy efficiency of the entire power plant. For both observed turbines and their cylinders it is valid that relative losses and efficiencies (both energy and exergy) are reverse proportional. The operation of an intermediate pressure cylinder from a steam turbine with reheating is the closest to optimal. Due to the different origins of losses considered in energy and exergy analyses, each analysis detects different turbine cylinders as the most problematic ones. The steam reheating process decreases losses and increases efficiencies (both energy of each turbine cylinder and the whole turbine. The whole turbine with reheating has an energy efficiency equal to 81.46% and an exergy efficiency equal to 86.48%, while the whole turbine without reheating has energy and exergy efficiencies equal to 76.47% and 80.94%, respectively. Exergy parameters of a steam turbine without reheating as well as its cylinders are much more influenced by the ambient temperature change in comparison to the steam turbine with reheating and its cylinders. The steam reheating process will increase the efficiency of the whole power plant in real exploitation conditions between 10% and 12%.