Combined Cycle Research Articles

Technical and economic analysis of hydrogen production from pre combustion carbon capture by Rectisol process in combined cycle power plant

Thermal efficiency impacts of structural and environmental variables in combined cycle plants: A machine learning approach to relocation scenario

Research and development of combined-cycle power plants operating on methane–hydrogen fuel mixtures with condensing heat-recovery steam generators

Improving the energy efficiency of thermal power plants through the thermodynamic analysis of their operational parameters in real time is a major issue in order to ensure rational and sustainable operation. An in-depth analysis has been conducted on the thermodynamic efficiency of three gas turbines in a gas/steam combined cycle power plant using real-time operational data. The presented work is part of the research that deals with operational parameters in order to maintain the performance of thermal power plants at the highest possible value. A combination of the first and second laws of thermodynamics has been developed to provide a model able of predicting the thermal efficiency of gas turbines in different operating modes in real-time. The results of our study indicate that each turbine demonstrated a thermal efficiency of around 33.5%. Additionally, the turbines produced an output power of 284 MW and had a specific fuel consumption rate of roughly 206 kg/MWh. The analysis not only verifies the durability of the turbines under various operating conditions, but also presents a verified method to monitor and improve energy efficiency in real time, which is crucial to optimize the power plant operations. Furthermore, this thermodynamic model can be used as a calculation program to be integrated into the display panel which will be used to provide operating indicators in real time. Keywords: Steam/Gas combined cycle, Gas turbine, Thermal performance, Energy conversion.

Abstract The turbojet module for a turbine-based combined cycle engine is sized subject to constraints arising from the configuration of its scramjet engine. An existing turbojet engine (TJE) core (compressor, burner, turbine) is scaled for air mass flow rate such that the desired thrust at the handover Mach number is achieved. An aerothermal model for the TJE core is integrated with a supersonic intake and nozzle, which are designed using a method of characteristics code. The intake and nozzle, which are constrained by the ramp angles selected for the scramjet module, are managed by appropriate use of splitter plates. The TJE module is sized by scaling the engine core with matching intake and nozzle designs in an iterative manner until the process converges to an acceptable value of handover thrust. A single operating point at the handover Mach could be found that met the thrust requirement while satisfying the constraints.

Iran, situated in the Middle East, is recognized as a prominent energy hub, with its economy heavily reliant on the exportation of energy. Iran currently faces significant water stress, underscoring the importance of examining its Water–Energy (WE) nexus. Hence, it is crucial to examine the Water–Energy (WE) nexus in this nation. This study evaluates Iran’s WE nexus from upstream to downstream in its energy subsystem (2007–2017) through an integrated framework combining water footprint analysis, water consumption methodologies, and nexus system modeling. This study assessed the WE nexus from upstream to downstream in Iran from 2007 to 2017. Key findings reveal that steam turbine power plants, particularly Ramin and Neka, exhibit the highest water consumption intensities, approximately 2.04 and 2.65 m3/MWh respectively, making them critical targets for efficiency improvements or retirement. Conversely, combined-cycle plants with dry cooling technology show significantly lower water intensity (0.18 m3/MWh), presenting viable alternatives. The study recommends shifting energy infrastructure towards combined-cycle and gas turbine plants to mitigate water stress, thus providing actionable insights for sustainable energy and water resource management in water-stressed regions.

At present, enhancing the first- and second-law efficiencies of power generation cycles is no longer the sole objective of engineers. Increasing attention is now being paid to reducing carbon emissions in the environment and minimizing the time required to recover the costs of the power plant, in addition to improving work output and first- and second-law efficiencies. The present analytical study compares the power generation cycle with and without a carbon capture unit. The combined cycle selected is the reheat gas turbine cycle using an ammonia–water mixture and transcritical carbon dioxide as working fluids in the bottoming cycle. The comparison of both the configurations depicts that at a cycle pressure ratio of 40, an ambient temperature of 303 K, and a turbine inlet temperature of 1600 K, the configuration incorporating the maximum number of ammonia–water turbines in the bottoming cycle yields the highest work output, amounting to 952.3 kJ/kg. The payback period is found to be the longest—approximately 8 years and 4 months for the configuration utilizing transcritical carbon dioxide as the working fluid. The integration of a carbon capture unit results in a reduction in carbon emissions ranging from a minimum of 15% to a maximum of 22.81%. However, a higher operating separation temperature for ammonia and water is observed to degrade the thermodynamic performance across all configurations analyzed.

Proposed process intensification in the literature claims relevant savings in operational cost through optimization of the energy required to operate a typical solvent-based CO2 capture facility, meanwhile granting the same capture performance. However, the techno-economic assessment for these proposed designs is not well developed and not fairly compared using a detailed and standardized cost evaluation technique that follows the association for the advancement of cost engineering (ACEE) class 4 costing methodology. This limitation makes it difficult and less viable to decide which solution is more cost-effective in consideration of the integration market with coal or natural gas combined cycle power plants. This work suggests a standardized methodology for cost evaluation and ultimately aids in formulating an accurate and high-fidelity guideline for industrial deployment of the proposed technologies, covering analysis on the flue gas compression (FGC) and lean vapor compression (LVC) configurations. Design, simulation, sensitivity analysis, and optimization are conducted initially to build a baseline design that closely represents an existing commercial design, such as Cansolv and Petra Nova technologies. The energy saving from the two configurations is analyzed in parallel to the investment cost, levelized cost of electricity (LCOE), and the CO2 avoided cost. It was found that FGC improved the capture performance of the baseline design, but at the same time raised the cost of operation and investment by a higher magnitude, making the CO2 avoided cost $98.2/tonneCO2, which is $16 higher than that of the baseline design. Meanwhile, LVC has been defined as an attractive configuration for lowering the CO2 avoided cost.

Biogas has been identified as a sustainable resource of renewable and clean energy because of its social, economic, and environmental benefits. In this work, the analysis of a biogas combined cycle power plant coupled with a carbon capture and utilization (CCU) technology and an organic Rankine cycle (ORC) was considered. The integrated process was subjected to a multi-objective assessment considering energy, economic, environmental, and safety items. The CCU system was taken to produce syngas as a value-added product, and the use of different working fluids for the ORC, namely, R1234yf, R290, and R717, was also examined. Such working fluids were selected to represent options with varying environmental and inherent safety implications. It was shown that the integration of the CCU and ORC components to the biogas cycle plant can provide significant benefits that include a 48.65 kt/year syngas production, a decrease in carbon capture energy penalty by 33%, and a reduction in e-CO2 emissions above 80% with respect to the stand-alone power plant. Comparison with conventional technologies also showed important environmental benefits. The analysis of inherent safety showed that the selection of working fluids for the ORC can have a significant impact on the process risk. From the set of working fluids considered in this work, R717 provided the best choice for the integrated system based on its lowest operational risk and the highest electricity production (355 kWe). The multi-objective approach used in this work allowed the quantification of benefits provided by the integration of CCUs and ORCs with respect to the base process within an overall economic, sustainability, and inherent safety assessment.

ABSTRACTThe properties of a semi‐closed combined cycle power system make it a better option for this study than an open system, since it turns an open‐cycle gas turbine into a pollutant‐free power system. Also in the selected cycle, the exhaust is channeled toward a divider rather than being released into the atmosphere, and the exhaust is divided into a separation duct and a return duct by the divider. Part of the exhaust is directed back toward the compressor via the return duct. This study investigates the effect of thermodynamic parameters analysis (turbine inlet temperature, ambient air temperature, pressure ratio, and regenerator effectiveness) on thermal efficiency and specific fuel consumption (S.F.C.) for a semi‐closed system. The properties of a semi‐closed combined cycle power system make it a better option for this study than an open system, since they turn an open‐cycle gas turbine into a pollutant‐free power system. Also in the selected cycle, the exhaust is channeled toward a divider rather than being released into the atmosphere. The exhaust is divided into a separation duct and a return duct by the divider. Part of the exhaust is directed back toward the compressor via the return duct. This study investigates the effect of thermodynamic parameters analysis (turbine inlet temperature, ambient air temperature, pressure ratio, and regenerator effectiveness) on thermal efficiency and S.F.C. for a semi‐closed gas turbine cycle. The operating conditions are taken into account when determining the analytical formulas for assessing thermal efficiency and S.F.C., which are calculated by using thermodynamic equations. The model is constructed using MATLAB®. The results show that the thermal efficiency is increased due to increased turbine inlet temperature, increased regenerator effectiveness, and decreased ambient air temperature. Conversely, S.F.C. decreases. It was also found that when the pressure ratio was roughly 2, the thermal efficiency rose, while the S.F.C. started to decrease. After this value, the thermal efficiency began to decline gradually, and the S.F.C. increased. Also, as the regenerator's effectiveness increased to roughly 0.95, the data indicate that the thermal efficiency achieved its maximum value of 0.60. and at a turbine inlet temperature of about 1600 K, while the S.F.C recorded a minimum value of 0.1394.

In predictive maintenance frameworks, risk curves are used as interpretable, real-time indicators of equipment degradation. However, existing approaches generally assume a monotonically increasing trend and neglect the corrective effect of maintenance, resulting in unrealistic or overly conservative risk estimations. This paper addresses this limitation by introducing a novel method that dynamically corrects risk curves through a quantitative measure of maintenance effectiveness. The method adjusts the evolution of risk to reflect the actual impact of preventive and corrective interventions, providing a more realistic and traceable representation of asset condition. The approach is validated with case studies on critical feedwater pumps in a combined-cycle power plant. First, individual maintenance actions are analyzed for a single failure mode to assess their direct effectiveness. Second, the cross-mode impact of a corrective intervention is evaluated, revealing both direct and indirect effects. Third, corrected risk curves are compared across two redundant pumps to benchmark maintenance performance, showing similar behavior until 2023, after which one unit accumulated uncontrolled risk while the other remained stable near zero, reflected in their overall performance indicators (0.67 vs. 0.88). These findings demonstrate that maintenance-corrected risk curves enhance diagnostic accuracy, enable benchmarking between comparable assets, and provide a missing piece for the development of realistic, risk-informed predictive maintenance strategies.

Supercritical carbon dioxide (sCO2) emerges as an effective working fluid in closed-loop energy conversion cycles, offering significant advantages over traditional steam-based Rankine cycles. This research focuses on optimizing combined cycle systems utilizing sCO2 to enhance energy efficiency, improve exergy performance, increase stability, reduce emissions, and lower costs. Various configurations of the sCO2 cycle are analyzed, with an emphasis on their impact on efficiency as dictated by the first and second laws of thermodynamics. Key parameters include a gas turbine outlet temperature of 489 °C, a smoke flow rate of 89 kg/s, and a maximum cycle pressure of 230 bar, alongside turbine pinch temperatures of 30 °C and condenser pinch temperatures of 20 °C. The study evaluates three configurations: simple cycle, recuperator cycle, and split cycle, achieving first law efficiencies of 17.73%, 19.26%, and 23.56%, respectively. By minimizing exergy losses, this research enhances environmental sustainability and system stability, leading to reduced pollutant emissions. Economic analyses further compare the electricity generation costs of sCO2 cycles to those of steam cycles, revealing cost ratios of 0.80, 0.92, and 0.98 for the simple, recuperator, and split cycles, respectively. Additionally, sustainability indices for the simple, recuperator, and split cycles are calculated at 1.92, 2.09, and 2.76, respectively. The findings underscore that advancements in sCO₂ cycles not only improve power output, energy efficiency, and environmental sustainability but also reduce cycle costs and environmental pollution.

Pressure Gain Combustion (PGC) is an interesting emerging concept to enhance the performance of gas turbines currently based on the Brayton–Joule cycle. Focusing on a F-class gas turbine for land-based power generation, the current work investigates PGC potential in both simple and combined cycle operations by means of an in-house simulation software. The PGC cycle lay-out specifically includes a booster compressor for delivering cooling air to the blades at the first stage of the gas turbine expander. The effects of different amounts of air from the same booster to the PGC system for cooling requirements are also analyzed. Considering reasonable PGC values based on literature data, the efficiency of the gas turbine simple cycle rises by 2.85–3.40 percentage points in the case of no combustor cooling, or 1.85–2.25 percentage points for the most extensive cooling at the combustor, compared to the reference case. The combined cycle efficiency increases too, despite the almost equal power generation at the bottoming steam cycle. Ultimately, a revised parametric analysis with reduced efficiency at the first stage of the gas turbine expander is carried out as well to account for the losses induced by the PGC on the fluid dynamics of the expansion. In this new scenario, the risk of nullifying the advantages related to PGC is real, because of specific combinations of lower expansion efficiency at the gas turbine expander and extensive cooling at the combustor. Thus, better turbine design and effective thermal management at the combustor are fundamental to achieve the highest efficiency.

Controlling the temperature of superheated steam (SST) is essential for the safe and efficient operation of combined cycle power plants, but it has become challenging due to frequent load variations and safety requirements. Traditional PI controllers may struggle to provide optimal performance because of non-linearity, time delays, and disturbances, particularly under wide-range load conditions. This paper proposes a new feedforward gain-scheduling cascade control strategy that compensates for time delays while ensuring stable SST without complicating the control system. The method incorporates a well-defined feedforward control mechanism into a gain-scheduling PI structure, enabling quick adjustments of the water spray control valve to prevent SST overshoots during sudden power fluctuations. A stability analysis is included, and the proposed strategy has been successfully simulated and implemented at two real combined cycle power plants in Iran, demonstrating its effectiveness in maintaining smooth temperature control and enhancing power output without adding complexity to the system.

Waste-heat utilization for turbine air cooler and fuel heater in gas turbine combined cycle

An integrated Power-to-X-to-Power system in green methanol carrier with gas turbine combined cycle and carbon capture: Energy-exergy-cost-carbon intensities

Integration of membrane-based atmospheric CO2 capture with a combined cycle power plant: A novel hybrid CCS/DAC process concept

With the rise of energy needs and decentralization of power generation, and especially the need for energy production from renewable sources, the use of power plants based on organic Rankine cycle is becoming more and more significant. However, this type of power plant wastes a lot of available heat after preheating of the working fluid. Combined heat and power (CHP) production enables mitigating wasted heat potential and increasing the overall efficiency of the organic Rankine cycle-based power plant. The aim of this work is thermodynamic characteristics determination and their comparison, for two organic Rankine cycle configurations for combined heat and power: split flow simple organic Rankine cycle (SF SORC) and double stage organic Rankine cycle (DS ORC). Considered geothermal sources are low to medium temperature sources between 120°C and 180°C. The methodology includes thermodynamic analysis and optimization of the specified organic Rankine cycle configurations for heat and power production from geothermal sources. The obtained results show that the combined heat and power split flow simple organic Rankine cycle (CHP SF SORC) configuration is superior to the combined heat and power double stage organic Rankine cycle (CHP DS ORC) configuration, where plant (system) efficiency can be increased up to 28% for low temperature district heating, and for district heating plant (system) efficiency usually increases from about 12% to 18% depending on the working fluid and the temperature of the geothermal fluid. With regard to combined heat and power double stage organic Rankine cycle (CHP DS ORC) configuration plant (system) efficiency can be increased up to 18% for low temperature district heating, and for district heating plant (system) efficiency usually increases from 5% to 8%.

Decarbonization path of natural gas combined cycle using chemical looping hydrogen generation: Thermodynamics, emissions, and economics studies

Techno-economic assessment of a commercial natural gas combined cycle with a chemical absorption plant using lean vapor compression modification