Hybrid energy plants (HEPs), which include both fossil fuel technologies and renewable energy systems, can provide an important step toward a sustainable energy supply. In fact, the hybridization of renewable energy systems with gas turbines (GTs), which are fed by fossil fuels allows an acceptable compromise, so that high fossil fuel efficiency and high share of renewables can be potentially achieved. Moreover, electrical and thermal energy storage systems increase the flexibility of the energy plant and effectively manage the variability of energy production and demand. This paper investigates the optimal sizing of a HEP, which combines an industrial GT, renewable energy systems, and energy storage technologies. The considered renewable energy system is a photovoltaic system (PV), while the energy storage technologies are electrical energy storage and thermal energy storage. Moreover, a compression chiller and a gas boiler (GB) are also considered. For this purpose, the load profiles of electricity, heating, and cooling during a whole year are taken into account for the case study of the Campus of the University of Parma (Italy). The sizing optimization problem of the different technologies composing the HEP is solved by using a genetic algorithm, with the goal of minimizing the primary energy consumption (PEC). Moreover, different operation strategies are analyzed and compared so that plant operation is also optimized. The results demonstrate that the optimal sizing of the HEP, coupled with the optimized operation strategy, allows high average cogeneration efficiency (up to 84%), thus minimizing PEC.

In order to increase the exploitation of the renewable energy sources, the diffusion of the distributed generation systems is grown, leading to an increase in the complexity of the electrical, thermal, cooling, and fuel energy distribution networks. With the main purpose of improving the overall energy conversion efficiency and reducing the greenhouse gas emissions associated with fossil fuel based production systems, the design and the management of these complex energy grids play a key role. In this context, an in-house developed software, called COMBO , presented and validated in Part I of this study, has been applied to a case study in order to define the optimal scheduling of each generation system connected to a complex energy network. The software is based on a nonheuristic technique, which considers all the possible combination of solutions, elaborating the optimal scheduling for each energy system by minimizing an objective function based on the evaluation of the total energy production cost and energy systems' environmental impact. In particular, the software COMBO is applied to a case study represented by an existing small-scale complex energy network, with the main objective of optimizing the energy production mix and the complex energy networks yearly operation depending on the energy demand of the users. The electrical, thermal, and cooling needs of the users are satisfied with a centralized energy production, by means of internal combustion engines, natural gas boilers, heat pumps, compression, and absorption chillers. The optimal energy systems' operation evaluated by the software COMBO will be compared to a reference case, representative of the current energy systems setup, in order to highlight the environmental and economic benefits achievable with the proposed strategy.

Renewable energy penetration is growing, due to the target of greenhouse-gas-emission reduction, even though fossil fuel-based technologies are still necessary in the current energy market scenario to provide reliable back-up power to stabilize the grid. Nevertheless, currently, an investment in such a kind of power plant might not be profitable enough, since some energy policies have led to a general decrease of both the average single national price of electricity (PUN) and its variability; moreover, in several countries, negative prices are reached on some sunny or windy days. Within this context, combined heat and power (CHP) systems appear not just as a fuel-efficient way to fulfill local thermal demand but also as a sustainable way to maintain installed capacity able to support electricity grid reliability. Innovative solutions to increase both the efficiency and flexibility of those power plants, as well as careful evaluations of the economic context, are essential to ensure the sustainability of the economic investment in a fast-paced changing energy field. This study aims to evaluate the economic viability and environmental impact of an integrated solution of a cogenerative combined cycle gas turbine power plant with a flue gas condensing heat pump. Considering capital expenditure, heat demand, electricity price, and its fluctuations during the whole system life, the sustainability of the investment is evaluated taking into account the uncertainties of economic scenarios and benchmarked against the integration of a cogenerative combined cycle gas turbine power plant with a heat-only boiler (HOB).

Waste heat recovery is a vitally important technology to address increasingly stringent emissions legislation and environmental concerns over CO 2 . One such means of recovering thermal energy is the inverted Brayton cycle (IBC). This paper presents an experimental study of a novel combination of the IBC with a Rankine cycle for the first time. The IBC requires cooling of the exhaust gases after expansion. If the gases contain water vapor, as is the case for hydrocarbon combustion, and cold enough coolant is available, the water can be condensed, pressurized, and reboiled for expansion in a Rankine cycle. The steam produced from the cycle can be utilized in a number of ways. In this study, steam is injected through a series of de Laval nozzles directed into the main turbine to produce additional shaft power in a compact arrangement. To minimize the size of the system, additive manufacturing was used for the heat exchangers, giving high performance per unit volume. The study demonstrates the feasibility of the cycle in producing power from waste heat using humid gas that already is present in most applications. The experimental results show that the system is able to generate power at very low exhaust temperatures where the standard IBC would cease to operate. With an IBC inlet temperature of 370 °C, approximately 5 kJ/kg of specific shaft work was produced with 5 g/s of steam flowrate. At higher exhaust temperatures, the IBC and the Rankine cycle started to work together to increase the shaft power resulting in much higher specific work. At 620 °C, a specific shaft work of 41 kJ/kg was generated at a steam flow of 9 g/s. For the present turbomachinery sizes, this corresponded to 1933 W of power at 47 g/s of main exhaust flow. A model of the thermodynamic system was created in order to study the sensitivity of the system to parameters such as the steam expander pressure ratio and efficiency. Higher steam pressure and higher steam expander efficiency both led to greater power generated for the same operating point, particularly at high IBC turbine inlet temperatures. The peak specific work for the range of parameters explored in the paper was 68 kJ/kg with a steam expander efficiency of 70% and exhaust conditions of 600 °C and 50 g/s. The plots produced in this study can be used as a guide for others considering this system to understand the expected power generated under a range of conditions.

A supercritical steam bottoming cycle has been proposed as a performance enhancement option for gas turbine combined cycle power plants. The technology has been widely used in coal-fired steam turbine power plants since the 1950s and can be considered a mature technology. Its application to the gas-fired combined cycle systems presents unique design challenges due to the much lower gas temperatures (i.e., 650 °C at the gas turbine exhaust vis-à-vis 2000 °C in fossil fuel-fired steam boilers). Thus, the potential impact of the supercritical steam conditions is hampered to the point of economic infeasibility. This technical brief draws upon the second-law based exergy concept to rigorously quantify the performance entitlement of a supercritical high-pressure boiler section in a heat recovery steam generator utilizing the exhaust of a gas turbine to generate steam for power generation in a steam turbine.

This paper evaluates the performance of an organic Rankine cycle (ORC) based micro- combined heat and power (CHP) unit using a scroll expander. The considered system consists of a fuel boiler coupled with an ORC engine. As a preliminary step, the results of an experimental campaign and the modeling of a hermetic, lubricated scroll compressor used as an expander are presented. Then, a fluid comparison based on several criteria is conducted, leading to the selection of R245fa as working fluid for the ORC. A simulation model is then built to evaluate the performance of the system. The model associates an ORC model and a boiler model, both experimentally validated. This model is used to optimize and size the system. The optimization is performed considering two degrees of freedom: the evaporating temperature and the heat transfer fluid (HTF) mass flow rate. Seasonal simulation is finally performed with a bin method according to the standard PrEN14825 for an average European climate and for four heat emitter heating curves. Simulation results show that the electrical efficiency of the system varies from 6.35% for hot water at 65 °C (high temperature application) to 8.6% for a hot water temperature of 22 °C (low temperature application). Over one entire year, the system exhibits an overall electrical efficiency of about 8% and an overall thermal efficiency around 87% without significant difference between the four heat emitter heating curves. Finally, some improvements of the scroll expander are evaluated. It is shown that by increasing the maximum inlet temperature (limited to 140 °C due to technical reasons) and using two scroll expanders in series, the overall electrical efficiency reaches 12.5%.

Coal combustion for electric power generation is one of the major contributors to anthropogenic CO 2 emissions to the atmosphere. Carbon capture and storage (CCS) technologies are currently intensively investigated in order to mitigate CO 2 emissions. The technique which is currently the most pursued is post combustion scrubbing of the flue gas, due to the potential to retrofit post combustion capture to existing power plants. However, it also comes with a substantial energy penalty. To reduce the energy demand of CO 2 processing, the so-called oxyfuel technology presents an option to increase the concentration of CO 2 in the flue gas. Here, the coal is burned in a mixture of oxygen and recycled flue gas. Hence, the flue gas primarily consists of CO 2 and water vapor, which can be easily condensed. In general, there are two different techniques for oxygen production in oxyfuel power plants: cryogenic air separation (it is a method which can be easily implemented since it is already well established in industry) and a mixed metal oxide ceramic membrane (ITM or OTM) operating at high temperatures (it is a new process for O 2 production, which is under development). In the last ten years, efforts in the efficient utilization of energy and reduction of emissions have indirectly stimulated research in mixed conducting membranes. In fact, the presently available cryogenic air separation process consumes a significant fraction of the generating plant’s output and reduces its efficiency. Oxygen transport membrane (OTM) integration with an ultra-supercritical (USC) power plant is, indeed, considered a promising technology that will lead to economic and energy savings compared to the previous solution. In this paper, we discuss the actual potentialities and limits of OTM and their integration in USC power plants.

Since the superheated steam temperature system of boiler in thermal power plant is characterized as time varying and nonlinear, it is hard to achieve a satisfactory performance by the conventional proportional-integral-derivative (PID) cascade control scheme. This paper presents a design method of adaptive PID cascade control system for superheated steam temperature based on inverse model: First, the inner loop and the outer process in the cascade control system are equivalent to a generalized plant. A simplified Takagi–Sugeno (STS) fuzzy model is adopted to identify the inverse model of the generalized plant. By choosing the appropriate structure and optimizing with constrains for the parameters of the inverse model, the organic combination of the PID primary controller with the inverse model is realized. To maintain the structure of the existing conventional PID cascade control system in power plant without change, in the control process, the parameters of the primary controller are adjusted on-line according to the identification result of the inverse model of the generalized plant; thus an adaptive PID cascade control system is formed, which matches with the characteristics of the controlled plant. Through the simulation experiments of controlling superheated steam temperature, it is illustrated that the proposed scheme has good adaptability and anti-interference ability.

In order to investigate the two-phase flow behavior during countercurrent flow limitation in the hot leg of a pressurized water reactor, two test models were built: one at the Kobe University and the other at the TOPFLOW test facility of Forschungszentrum Dresden-Rossendorf (FZD). Both test facilities are devoted to optical measurement techniques; therefore, a flat hot leg test section design was chosen. Countercurrent flow limitation (CCFL) experiments were performed, simulating the reflux condenser cooling mode appearing in some accident scenarios. The fluids used were air and water, both at room temperature. The pressure conditions were varied from atmospheric at Kobe to 3.0 bars absolute at TOPFLOW. According to the presented review of literature, very few data are available on flooding in channels with a rectangular cross section, and no experiments were performed in the past in such flat models of a hot leg. Commonly, the macroscopic effects of CCFL are represented in a flooding diagram, where the gas flow rate is plotted versus the discharge water flow rate, using the nondimensional superficial velocity (also known as Wallis parameter ) as coordinates. However, the classical definition of the Wallis parameter contains the pipe diameter as characteristic length. In order to be able to perform comparisons with pipe experiments and to extrapolate to the power plant scale, the appropriate characteristic length should be determined. A detailed comparison of the test facilities operated at the Kobe University and at FZD is presented. With respect to the CCFL behavior, it is shown that the essential parts of the two hot leg test sections are very similar. This geometrical analogy allows us to perform meaningful comparisons. However, clear differences in the dimensions of the cross section ( H × W = 150 × 10 mm 2 in Kobe, 250 × 50 mm 2 at FZD) make it possible to point out the right characteristic length for hot leg models with rectangular cross sections. The hydraulic diameter, the channel height, and the Laplace critical wavelength (leading to the Kutateladze number) were tested. A comparison of our own results with similar experimental data and empirical correlations for pipes available in literature shows that the channel height is the characteristic length to be used in the Wallis parameter for channels with rectangular cross sections. However, some limitations were noticed for narrow channels, where CCFL is reached at lower gas fluxes, as already observed in small scale hot legs with pipe cross sections.

For the analysis of transient two-phase flows in nuclear reactor components such as a reactor vessel, a steam generator, and a containment, KAERI has developed a three-dimensional thermal hydraulic code, CUPID . It adopts a three-dimensional, transient, two-phase and three-field model and includes various physical models and correlations of the interfacial mass, momentum, and energy transfer for the closure. In the present paper, the CUPID code and its two-phase flow models were assessed against the downcomer boiling experiment, which was performed to simulate the downcomer boiling phenomena. They may happen in the downcomer of a nuclear reactor vessel during the reflood phase of a postulated loss of coolant accident. The stored energy release from the reactor vessel to the liquid inside the downcomer causes the boiling on the wall, and it can reduce the hydraulic head of the accumulated water, which is the driving force of water reflooding to the core. The computational analysis using the CUPID code showed that it can appropriately predict the multidimensional boiling phenomena under a low pressure and low flow rate condition with modification of the bubble size model.

The key product of a combined cycle power plant is electric power generated for industrial, commercial, and residential customers. In that sense, the key performance metric that establishes the pecking order among thousands of existing, new, old, and planned power plants is the thermal efficiency. This is a ratio of net electric power generated by the plant to its rate of fuel consumption in the gas turbine combustors and, if applicable, heat recovery boiler duct burners. The term in the numerator of that simple ratio is subject to myriad ambiguities and/or misunderstandings resulting primarily from the lack of a standardized definition agreed upon by all major players. More precisely, it is the lack of a standardized definition of the plant auxiliary power consumption (or load) that must be subtracted from the generator output of all turbines in the plant, which then determines the net contribution of that power plant to the electric grid. For a combined cycle power plant, the key contributor to the plant’s auxiliary power load is the heat rejection system. In particular, any statement of combined cycle power plant thermal efficiency that does not specify the steam turbine exhaust pressure and the exhaust steam cooling system to achieve that pressure at the site ambient and loading conditions is subject to conjecture. Furthermore, for an assessment of the realism associated with the two in terms of economic and mechanical design feasibility, it is necessary to know the steam turbine exhaust end size and configuration. Using fundamental design principles, this paper provides a precise definition of the plant auxiliary load and quantifies its ramification on the plant’s net thermal efficiency. In addition, four standard auxiliary load levels are quantitatively defined based on a rigorous study of heat rejection system design considerations with a second-law perspective.

The present regulatory requirements enforce the modification of the firing modes of existing coal-fired utility boilers and the use of coals different from those originally designed for these boilers. The reduction in SO 2 and NO x emissions was the primary motivation for these changes. Powder river basin (PRB) coals, classified as subbituminous ranked coals, can lower NO x and SO x emissions from power plants due to their high volatile content and low sulfur content, respectively. On the other hand, PRB coals have also high moisture content, low heating value, and low fusion temperature. Therefore when a power plant switches from the designed coal to a PRB coal, operational challenges were encountered. A major problem that can occur when using these coals is the severe slagging and excess fouling on the heat exchanger surfaces. Not only is there an insulating effect from deposit, but there is also a change in reflectivity of the surface. Excess furnace fouling and high reflectivity ash may cause reduction in heat transfer in the furnace, which results in higher furnace exit gas temperatures (FEGTs), especially with opposite wall burners and with a single backpass. Higher FEGTs usually result in higher stack gas temperature, increasing the reheater spray flow and therefore decreasing the boiler efficiency with a higher heat rate of the unit. A successful modification of an existing unit for firing of PRB coals requires the evaluation of the following parameters: (1) capacities or limitations of the furnace size, (2) the type and arrangement of the firing system, (3) heat transfer surface, (4) pulverizers, (5) sootblowers, (6) fans, and (7) airheaters. In the present study we used a comprehensive methodology to make this evaluation for three PRB coals to be potentially fired in a 575 MW tangential-fired boiler.

Due to the liberalization of the energy markets and the globalization of coal procurement, fuel management became of substantial importance to power plant operators, which are faced with new challenges when operating with coal types different from the originally designed ones for the specific boiler. Environmental regulations, combustion behavior, possible malfunctions and low operation, and maintenance cost became of essential importance. Fouling is one of the major challenges when new coals are being used. For that purpose we initiated a comprehensive study of fouling on the water-wall tubes in a 575 MW tangential-fired pulverized-coal utility boiler. We developed a methodology to evaluate fouling propensity of coals and specifically tested two bituminous South African coals: Billiton-Prime and Anglo-Kromdraai. The methodology is based on the adherence of ash particles on the water walls. Adherence of the ash particle depends on the particle properties, temperature, and velocity vector at the boundary layer of the water walls. In turn, the flow and temperature fields were determined by computational fluid dynamics (CFD) simulations. For CFD simulations we also needed the combustion kinetic parameters, emissivity, and thermal resistance, and they were all determined experimentally by a 50 kW test facility. Using this methodology we mapped off the locations where fouling is mostly to occur. It was found that our results fitted with the experience from the data obtained for these two coals in the Israel Electric Corporation utility boilers. The methodology developed was shown to be able to provide the fouling propensity of a certain coal, and yielded good prediction of the fouling behavior in utility boilers. Therefore, the methodology can assist in the optimization of the soot-blowing regime (location and frequency).

The aim of the paper is to introduce methods to estimate the residual life of steam generators with alloy 600 thermally treated (TT) tubing, taking into account primary water stress corrosion cracking (PWSCC) as the main contributor damage. The methods take into account both initiation and propagation of PWSCC cracks in the expansion transition zone of steam generator tubes, as well as the current damage status (cracking and plugging) of the tube bundle, known from inspection results. A probabilistic model is used to treat initiation, while the propagation stage is treated in a deterministic way based on inspection data. After introducing the methods used to assess the residual life, a brief parametric study will be shown to illustrate the effects of initiation versus propagation. Eventually, the cases of a few actual steam generators with tubing made of alloy 600 TT showing different situations of present damage and damage evolution rates will be presented.

As carbon capture and storage technology has grown as a promising option to significantly reduce CO 2 emissions, system integration and optimization claim an important and crucial role. This paper presents a comparative study of a gas turbine cycle with postcombustion CO 2 separation using an amine-based absorption process with monoethanolamine. The study has been made for a triple pressure reheated 400 MWe natural gas-fuelled combined cycle with exhaust gas recirculation (EGR) to improve capture efficiency. Two different options for the energy supply to the solvent regeneration have been evaluated and compared concerning plant performance. In the first alternative heat is provided by steam extracted internally from the bottoming steam cycle, while in the second option an external biomass-fuelled boiler was utilized to generate the required heat. With this novel configuration the amount of CO 2 captured can be even more than 100% if the exhaust gas from the biofuelled boiler is mixed and cleaned together with the main exhaust gas flow from the combined cycle. In order to make an unprejudiced comparison between the two alternatives, the reduced steam turbine efficiency has been taken into consideration and estimated, for the alternative with internal steam extraction. The cycles have been modeled in the commercial heat and mass balance program IPSEPRO ™ using detailed component models. Utilizing EGR can double the CO 2 content of the exhaust gases and reduce the energy need for the separation process by approximately 2% points. Using an external biomass-fuelled boiler as heat source for amine regeneration turns out to be an interesting option due to high CO 2 capture effectiveness. However the electrical efficiency of the power plant is reduced compared with the option with internal steam extraction. Another drawback with the external boiler is the higher investment costs but nevertheless, it is flexibility due to the independency from the rest of the power generation system represents a major operational advantage.

Demand for power is growing everyday, mainly due to emerging economies in countries such as China, Russia, India, and Brazil. During the last 50 years steam pressure and temperature in power plants have been continuously raised to improve thermal efficiency. Recent efforts to improve efficiency leads to the development of a new generation of heat recovery steam generator, where the Benson once-through technology is applied to improve the thermal efficiency. The main purpose of this paper is to analyze the mechanical behavior of a high pressure superheater manifold by applying finite element modeling and a finite element analysis with the objective of analyzing stress propagation, leading to the study of damage mechanism, e.g., uniaxial fatigue, uniaxial creep for life prediction. The objective of this paper is also to analyze the mechanical properties of the new high temperature resistant materials in the market such as 2Cr Bainitic steels (T/P23 and T/P24) and also the 9–12Cr Martensitic steels (T/P91, T/P92, E911, and P/T122). For this study the design rules for construction of power boilers to define the geometry of the HPSH manifold were applied.

In this paper, pressurized oxy-fuel combustion power generation processes are modeled and analyzed based on a 350 MW subcritical reheat boiler associated with a condensing steam turbine. The performance results are obtained. Furthermore, the influences of slurry concentration and coal properties on power plant performance are investigated. An oxy-fuel configuration operating at ambient pressure is studied to compare the performance with pressurized oxy-fuel configuration. Thermodynamic analysis reveals the true potentials of the pressurized oxy-fuel process. Based on the system integration, an improved configuration is proposed in which plant efficiency of pressurized oxy-fuel process is increased by 1.36%.

When steam power cycles are modeled, thermodynamic properties as functions of pressure and temperature are required in the critical and supercritical regions (region 3 of IAPWS-IF97). With IAPWS-IF97, such calculations require cumbersome iterative calculations, because temperature and volume are the independent variables in the formulation for this region. In order to reduce the computing time, the International Association for the Properties of Water and Steam (IAPWS) adopted a set of backward equations for volume as a function of pressure and temperature in region 3. The necessary numerical consistency is achieved by dividing the region into 20 subregions, plus auxiliary subregions near the critical point in which the consistency requirements are relaxed due to the singular behavior at the critical point. In this work, we provide complete documentation of these equations, along with a discussion of their numerical consistency and the savings in computer time. The numerical consistency of these equations should be sufficient for most applications in heat-cycle, boiler, and steam-turbine calculations; if even higher consistency is required, the equations may be used to generate guesses for iterative procedures.

A partial gasification combined cycle with C O 2 recovery is proposed in this paper. Partial gasification adopts cascade conversion of the composition of coal. Active composition of coal is simply gasified, while inactive composition, that is char, is burnt in a boiler. Oxy-fuel combustion of syngas produces only C O 2 and H 2 O , so the C O 2 can be separated through cooling the working fluid. This decreases the amount of energy consumption to separate C O 2 compared with conventional methods. The novel system integrates the above two key technologies by injecting steam from a steam turbine into the combustion chamber of a gas turbine to combine the Rankine cycle with the Brayton cycle. The thermal efficiency of this system will be higher based on the cascade utilization of energy level. Compared with the conventional integrated gasification combined cycle (IGCC), the compressor of the gas turbine, heat recovery steam generator (HRSG) and gasifier are substituted for a pump, reheater, and partial gasifier, so the system is simplified obviously. Furthermore, the novel system is investigated by means of energy-utilization diagram methodology and provides a simple analysis of their economic and environmental performance. As a result, the thermal efficiency of this system may be expected to be 45%, with C O 2 recovery of 41.2%, which is 1.5–3.5% higher than that of an IGCC system. At the same time, the total investment cost of the new system is about 16% lower than that of an IGCC. The comparison between the partial gasification technology and the IGCC technology is based on the two representative cases to identify the specific feature of the proposed system. The promising results obtained here with higher thermal efficiency, lower cost, and less environmental impact provide an attractive option for clean-coal utilization technology.

Following a detailed study of two of the mechanical precipitators in the air preheaters of a thermoelectric power plant, a large amount of ash that was deposited on one of the inlet conduits was observed, obstructing the incoming gas flow. A comparison of the available data for the two most recent hopper cleaning operations revealed that, on the one hand, the amount of ash collected by the clogged precipitator (A) was significantly less than that collected by the other (B) and, on the other hand, the temperature of the ash in the former was noticeably lower than in the latter. Prior to the cleaning of the conduits, a certain amount of damage was caused to the boiler dome, which meant that subsequent cleaning required the use of a hydrolazer, where it was noted that inlet pressures were very high. All of this indicated that the cause of the clogging was not physical. This paper provides a comprehensive analytical analysis that explains what happened, as well as resolving the situation.