Steam Cycle Research Articles

Integration of Thermal Solar Power in an Existing Combined Cycle for a Reduction in Carbon Emissions and the Maximization of Cycle Efficiency

The energy transition towards renewable energy sources is vital for handling climate change, air pollution, and health-related problems. However, fossil fuels are still used worldwide as the main source for electricity generation. This work aims to contribute to the energy transition by exploring the best options for integrating a solar field within a combined cycle power plant. Different integration positions at the gas and steam cycles for the solar field were studied and compared under several operating conditions using a thermodynamic model implemented in MATLAB R2024a. Fuel-saving and power-boosting (flowrate and parameter boosting) strategies were studied. The results revealed that, for a maximum fuel savings of 7.97%, the best option was to integrate the field into the steam cycle before the economizer stage. With an integrated solar thermal power of 3 MW, carbon dioxide emissions from fuel combustion were reduced to 8.3 g/kWh. On the other hand, to maximize power plant generation, the best option was to integrate the field before the superheater, increasing power generation by 24.2% for a solar thermal power of 4 MW. To conclude, guidelines to select the best integration option depending on the desired outcome are provided.

Performance of sCO2 Cycles for Waste Heat Recovery and Techno-Economic Perspective as Gas Turbine Bottoming Cycle

Abstract Supercritical carbon dioxide (sCO2) cycles are compact, cost-effective and widely adaptable to various heat sources, including the waste heat from gas turbine (GT) exhaust gases. While the addition of a steam cycle enhances the typical 40% efficiency of GTs up to 60%, their substantial investments render them less appealing for smaller GTs. This creates an opportunity for sCO2 cycles, but a comprehensive comparison of their performance with that of steam across a range of applications remains lacking. Moreover, their applicability to various industrial scenarios based on existing installations is missing from a techno-economic standpoint. To address these needs, four promising sCO2 cycles are evaluated and optimized using Aspen, and compared with the simple steam cycle. Their techno-economic performances are then investigated for 20 industrial GTs of different size up to the larger combined cycle gas turbine (CCGT) units incorporating amine-based carbon capture systems. Due to the significant investments required by the carbon capture unit, the implementation of a CC unit is only investigated for the largest CCGT units. The analysis yielded performance maps demonstrating comparable performances for sCO2 and steam cycles, as well as significant techno-economic advantages for sCO2 bottoming cycles for smaller GTs. However, when it comes to larger GTs combined with reheats and expansions steam cycles, sCO2 cannot outperform them in current technological standards. Nevertheless sCO2 cycles offers an attractive alternative, facilitating cogeneration. Among the different approaches designed to integrate the heat requirements of amine-based capture, steam cycles have always proved more suitable because of the thermal stability of amines. In conclusion, the research underscores the cost-effectiveness and adaptability of sCO2 cycles for heat recovery applications, particularly as bottoming cycles for smaller GTs, while larger GTs present a challenge. The work conducted sheds light on the substantial promise of sCO2 cycles, encouraging further exploration and implementation of these systems in the energy sector.

Self-superheated combined flash binary geothermal cycle using transcritical-CO2 power cycle with LNG heat sink as the secondary cycle

Combined flash binary geothermal cycle (CFBGC) is an efficient geothermal energy conversion technology. Natural gas (NG) is a preferred fuel in the current energy scenario. LNG gasification is a needed step for delivering NG among the end users. In the present study, a self-superheated single-flash geothermal steam cycle, a transcritical CO2 power cycle and an LNG gasification unit are integrated into a CFBGC. This study shows that the LNG gasification rate and power output can be increased simultaneously by increasing the steam turbine inlet pressure. At a higher steam turbine inlet pressure, desirable steam quality (i.e., 0.9) at the steam turbine exit is maintained by implementing self superheating of the steam. It is observed that 15°C DSH of steam enables the CFBGC to operate at a steam turbine inlet pressure that substantially enhances the output power without a noticeable increase in levelized electricity cost (LEC). The CFBGC operating at this condition yields 9.97% higher power output compared to that of the CFBGC operating at steam turbine inlet pressure requiring no DSH of steam. As a geothermal-based power plant emits very low CO2, the proposed energy system may emerge as a future sustainable energy option.

Semi-Closed Oxy-Combustion Combined Cycles for Combined Heat and Power Applications

Abstract This study focuses on the design and comparison of three utility-scale combined heat and power (CHP) cycles with carbon capture and storage (CCS): (i) a CHP semi-closed oxy-combustion combined cycle (SCOC-CC), (ii) a CHP natural gas combined cycle (NGCC) with postcombustion CCS, and (iii) a CHP NGCC with postcombustion CCS and supplementary firing. Performance evaluations are conducted at the design point and partial load (gas turbine at 30%) for different exports of high-temperature pressurized steam. The comparison is extended against two reference separate production systems with CCS, one based on postcombustion technologies, and another based on oxy-combustion. Simulations of the H-class gas turbines are performed using gas steam (GS), a specific in-house validated software, while the heat recovery steam cycle is modeled using Thermoflex. The CO2 capture processes employ validated models in Aspen Plus. The results highlight the suitability of the SCOC-CC for CHP applications, demonstrating superior performance and flexibility compared to CHP postcombustion technologies at both nominal and minimum loads. The SCOC cycle achieves a maximum first-law efficiency of 65.95%, outperforming CCS technologies that generate electricity and heat separately and enabling fuel savings up to 9.2%.

Importance of Clay Swelling on the Efficacy of Cyclic Steam Stimulation in the East Moldabek Formation in Kazakhstan

Both steam and hot water flooding of high-viscosity oils in the presence of swelling clays are difficult methods for producing oil efficiently because of potential formation permeability reduction. This paper pertains to heavy oil recovery from the East Moldabek formation where the oil API gravity is about 22 and is inundated with swelling clays. To achieve this, we used the IntersectTM reservoir simulator to compare oil recovery economics using both hot water and steam injection as a function of steam cycle duration, temperature, and steam dryness. We also studied clay swelling in the East Moldabek formation where clay poses a significant challenge due to its impact on permeability reduction. In this research, we developed an equation based on experimental data to establish a relationship between water mineralization and permeability in the East Moldabek formation. The equation provides valuable insight on how to mitigate clay swelling which is crucial for enhancing oil recovery efficiency—especially in sandstone reservoirs. Our modeling studies provide the recovery efficiencies for salinities of the hot water EOR versus cyclic steam EOR methods in a formation containing swelling clays. Specifically, the reduction in formation permeability as a function of the distilled water fraction is the controlling parameter in hot water or steam flooding—when the formation water mixture becomes less saline, oil recovery decreases. Our research shows that clay swelling can significantly impact cyclic steam stimulation outcomes, potentially reducing its effectiveness, while hot water flooding may offer a more cost-effective and operationally feasible solution in formations where clay swelling is a concern. Economic analysis reveals the potential for achieving an optimal favorable condition for hot water injection. Therefore, this paper provides a guideline on how to conduct thermal oil recovery for heavy oils in fields with high clay content such as the East Moldabek deposit.

A real-time phase transition modeling of supercritical steam cycle and load variation rate enhancement of thermal power plants under deep peak shaving

The ambitious green revolution to renewable energy sources in global power grids necessitates massive integration of solar and wind energy, which involves intermittent and unpredictable challenges. Thermal power plants are crucial in stabilizing the grid and addressing these challenges through flexibility reformation including deep peak shaving and frequent load variations since the unsteady state energy transfer and thermal dynamics during combustion and heat transformation in thermodynamic processes vary significantly. These conditions lead to issues such as furnace instability and latent heat of phase transition. This study introduces a novel approach to modeling phase transitions of supercritical steam cycle, and investigatesthe length, position, temperature, and energy transfer of the working medium and components under normal and low operational states. Conducting and analyzing the thermal feasible region associating the security of components and working medium this study establishes a control strategy for dynamic heat transfer to reduce component degradation effects andenhance load variation rate under flexible operations. Simulation model of a supercritical power unit based on the proposed method demonstrates an accuracy of 97.94%. Results from the optimal approach in maximizing load variation rate show the effectiveness and achieve 1.2%p.e./min most under transition process.

A Biomass-based Carbon Negative Brayton-Rankine Coupled Cycle Employing MCFC, Gasification and Combustion Boiler

Biomass based plants with CO2 capture usually experience low efficiency, at the same time, have great potential of mitigating environmental damage due to climate change. In this work, unlike conventional power plants, a novel biomass-based carbon negative power plant has been conceived considering both biomass gasification and a biomass combustion boiler. CO2 capture and improved efficiency due to the unique integration of the plant components are the major expected outcome from the proposed plant model. The plant contains a steam cycle, an MCFC and an EFGT unit as the power producing blocks. A vital operating parameter i.e., biomass combustion boiler equivalence ratio () has been varied to witness the changes in performance of the plant. The net power generated by the plant seemed to be increasing with . The plant performs best when the plant is operated at a  value of 2.5. At this operating condition, the net power generated by the power plant found to be 13796 kW with 75.52 % efficiency and 0.3957 kg/kWh specific biomass consumption (SBC).

Development of a solar-ocean based integrated plant with a new hydrogen generation system

Considering the global urgency to decrease carbon emissions and shift to sustainable energy sources, combining solar and other renewables with hydrogen generation appears to offer an appealing answer. The combination of solar and ocean energies with hydrogen production, therefore, offers a great potential to improve energy efficiency and create a feasible route towards zero-emission energy systems. A new hybrid photoelectrochemical (PEC)-conventional electrolysis system was designed and incorporated into the proposed multigeneration system. The hybridized reactor combines the benefits of PEC and conventional electrolysis by using a developed bipolar anode to produce hydrogen continuously, even when there is no solar radiation. The main aim of this research is to investigate the integrated power process that utilizes solar power for several uses, such as generating electricity, producing freshwater, and synthesizing hydrogen. The proposed research involves integrating several components, including a solar through collector system, a combination of power cycles (steam and organic Rankine cycles), a multi-effect desalination (MED) unit, a new hybrid electrolyzer system, a wave energy system, and a hydrogen storage and refuelling station. The main outputs include 2.05 kg/s freshwater production, 0.125 kg/s hydrogen production, 16,284.24 kW net work rate, and 95,068 kW solar heat input. The highest exergy destruction rates were found in the solar collector (56,194.8 kW) and turbines T1 and T2 (6019.9 and 4627.6 kW). The overall energy and exergy efficiencies of the proposed system are obtained to be 15.83 % and 16.61 %, respectively.

Simulation and Energy Analysis of Integrated Solar Combined Cycle Systems (ISCCS) Using Aspen Plus

The aim of this research is to simulate and analyze a combined power cycle (Steam turbine and gas turbine cycles) by studying the effect of changing the natural gas flow rate on the developed power. Therefore, reducing the amount of used natural gas in the combustion chamber of the gas turbine cycle from 9.2 to 4 kg/s showed a significant drop in the power produced by the gas turbine, i.e., from 123.7 to 57.7 MW. Additionally, this change in the combusted natural gas amount affected the heat recovered in both heat recovery steam generators (HRSGs), i.e., from 219.79 to 100.35 MW, respectively. Consequently, the amount of generated steam in the high pressure HRSGs and the power developed in the steam turbine changed from 60.88 to 27.79 kg/s and from 56.39 to 27.13 MW, respectively. A heat exchanger (HFHX) utilizing a heating fluid was used as an external source of energy to compensate the reduction in the generated heat and to increase the amount of generated steam up to 157.32 kg/s, which keeps the power plant capacity at 180 MW. Existing combined local plant data were used in this study and were simulated in Aspen Plus software V11. A sensitivity analysis was made to optimize the cycle operating conditions that use less natural gas and produce the same amount of power.

A Study on the Thermal Physical Property Changes in Formation Rocks during Rapid Preheating of SAGD

The incorporation and application of SAGD rapid preheating technology effectively solve the problem of the long preheating cycle in the SAGD steam cycle. The thermal properties of reservoir rocks are an important factor affecting the heat transfer law governing their formation during the rapid preheating process of SAGD. During the rapid preheating process of SAGD, the expansion of the reservoir and the steam cycle process will cause changes in the pore permeability, oil-water saturation, and temperature of the reservoir rocks, which will inevitably lead to differences in the changes that occur in the thermal properties of the reservoir rocks, compared to those under the influence of a single factor. In this study, experiments were conducted to determine the thermal properties of reservoir rocks under the combined influence of pore permeability, oil-water saturation, and temperature, quantitatively characterizing the changes in the thermal properties of reservoir rocks. Using the orthogonal method to design and carry out experiments for determining the thermal properties of reservoir rocks, the main factors affecting the thermal properties of reservoir rocks and the significance of each factor’s impact on the thermal properties of reservoir rocks were determined through intuitive analysis and variance analysis of the experimental results. Finally, a regression equation that can characterize changes in the thermal properties of reservoir rocks under the influence of multiple factors was obtained through multiple nonlinear regressions of the experimental results.

Innovative biomass waste heat utilization for green hydrogen production: A comparative and optimization study of steam and organic rankine cycles

Today, designing a green hydrogen production process under an optimal, efficient, and economical configuration is one of the priorities of energy systems engineers. This research aims to explore the application of electricity produced by the steam Rankine cycle (S/RC) and Organic Rankine cycle (ORC) through biomass-based waste heat utilization in an alkaline electrolyzer (AE) system for the production of green hydrogen. The S/RC unit utilizes high-temperature waste heat, while the ORC system utilizes medium to low-temperature ones from the S/RC to improve overall system efficiency and hydrogen output. The study developed eight distinct configurations of the combined system, employing two organic fluids across four ORC designs. It aimed to assess the influence of integrating a recuperator or/and an OFOH (open feed organic heater), as well as varying the organic fluids, on the ORC unit's hydrogen production capability. A detailed thermodynamic, thermo-economic, and eco-economic analysis was conducted to assess key metrics. The environmental analysis quantified the carbon dioxide (CO2) emission reductions achieved through hydrogen production, using the emission rate from the steam methane reforming method as a benchmark. This approach underscored the environmental benefits of the AE system for hydrogen production. Further, the study quantified the financial gains from CO2 reduction, referred to as carbon credit gain (CCG), through an eco-economic analysis. From the outcomes, the highest hydrogen yield and the lowest LCOH (levelized cost of hydrogen) value were 94.65 tons/year and 1.724 US$/kg, respectively, related to Case (IV)-a (biomass waste heat-based S/RC- Regenerative& recuperator ORC system-AE system under R245fa). Lastly, optimization process for maximizing hydrogen production via the optimization methodology was established.

Thermo- economic feasibility of solar-assisted regeneration in post-combustion carbon capture: A diglycolamine-based case

The solvent regeneration in the post-combustion carbon capture process usually relies on steam from the power plant steam cycle. This heat duty is one of the challenges of energy consumption in PCC (Post-combustion Carbon Capture). However, this practice results in a significant energy penalty, leading to a substantial reduction in the capacity of the Power Plant, estimated to be between 19.5 and 40 %. This paper investigate the techno-economic feasibility of a solar-assisted regeneration process for the PCC industrial scale with diglycolamine solvent. The study aims to assess the impact of system configuration modifications, such as LVC (Lean Vapor Compression), SPCC (Solar Post-combustion Carbon Capture), and combinations of trough or compound solar collectors with LVC, on energy efficiency and overall plant performance. With 3E analysis for SPCC configuration results show that this configuration. However, reducing energy consumption and energy penalty factor, exhibits a decrease in exergy and exergoeconomic efficiency compared to the other configurations in terms of exergy and exergoeconomic aspects. However, the LVC + SCSS (Solar Combined Separator-Stripper) configuration demonstrates the best performance across the 3E aspects, resulting in a reduction energy penalty to 12.2 % and improvements of 38 % and 4.2 % in exergy and exergoeconomic factors, respectively.

Economic and Technical Assessing the Hybridization of Solar Combined Cycle System with Fossil Fuel and Rock Bed Thermal Energy Storage in Neom City

Rising energy demands, the depletion of fossil fuels, and their environmental impact necessitate a shift towards sustainable power generation. Concentrating solar power (CSP) offers a promising solution. This study examines a hybridization of a combined cycle power plant (CCPP) based on solar energy with fossil fuel and energy storage in rock layers to increase Saudi Arabia’s electricity production from renewable energy. The fuel is used to keep the temperature at the inlet of the gas turbine at 1000 °C, ensuring the power produced by the Rankine cycle remains constant. During the summer, the sun is the main source of power generation, whereas in the winter, reliance on fuel increases significantly. The Brayton cycle operates for 10 h during peak solar radiation periods, storing exhaust heat in rock beds. For the remaining 14 h of the day, this stored heat is discharged to operate the Rankine steam cycle. Simulations and optimizations are performed, and the system is evaluated using a comprehensive 4E analysis (energy, exergy, exergoconomic, and environmental) alongside a sustainability assessment. A parametric evaluation examines the effect of key factors on system performance. The rock bed storage system compensates for solar intermittency, enabling power generation even without sunlight. The study reveals that the system generated 12.334 MW in June, achieving an energy efficiency of 37% and an exergy efficiency of 40.35%. The average electricity cost during this period was 0.0303 USD/kWh, and the carbon footprint was 0.108 kg CO2/kWh. In contrast, during January, the system produced 13.276 MW with an energy efficiency of 37.91% and an exergy efficiency of 44.16%. The average electricity cost in January was 0.045 USD/kWh, and the carbon footprint was 0.1 kg CO2/kWh. Interestingly, solar energy played a significant role: it contributed 81.42% of the heat in June, while in January, it accounted for 46.77%. The reduced electricity costs during June are primarily attributed to the abundant sunshine, which significantly powered the system.

Thermodynamic and economic analyses of the retrofit of existing electric power plants with fusion reactors

Electricity generation will need to reach net zero emissions globally in 2050. This will require an increase in share of renewable energy and the implementation of a controllable carbon-free base-load source. Nuclear fusion is a promising option to decarbonize base-load electricity production but its capital cost still doubles the one of technologically more mature alternatives such as large photovoltaic fields or off-shore wind installations. Within this framework, the retrofit of a dismissed power-plant could allow significant cost savings, thus facilitating the realization of a fusion electricity demonstrator. Among fusion reactors, stellarators are a valid alternative to tokamaks thanks to the higher blanket temperature and inherent continuous operation. In this scenario, we posit the challenge to use a nuclear fusion stellarator-based reactor to retrofit conventional power plants (PPs). Specifically, we select a nuclear fission plant in France and a supercritical coal fired site in Italy, by constructing 4 different retrofit scenarios as a function of the re-used components. We compare each option with a greenfield and optimized plant with the same reactor thermal power. through a thermodynamic, economic, and investment analysis.The results proves significant savings by retrofitting an existing plant, with a CapEx reduction up to 50% compared to the greenfield plants. Specifically, the most convenient retrofit strategy is to select a site that already implements cutting edge thermodynamic parameters while reusing the most existing systems (i.e. buildings, steam cycle, electricity generation, and heat rejection). This is the case of the 2 x 660 MWe supercritical coal-fired plant in Italy. Therein, the LCOEs are 39 $/MWh and 51 $/MWh, calculated with an interest rate of 2.7% and 6%, respectively, and compare with the conventional energy technologies. Moreover, such costs are competitive in the current European energy markets and yield significant net present values at the plant end of life.

Aspen plus-based techno-economic assessment of a solar-driven calcium looping CO2 capture system integrated with CaO sorbent reactivation

Given the gradual nature of the energy transition, retrofitting coal-fired power plants with carbon capture technology is crucial. The calcium looping (CaL) process is a promising solution, with challenges like absorbent deactivation and reduced thermal efficiency mitigated by absorbent reactivation and heat recovery systems. This study evaluated the techno-economic feasibility of integrating a novel wet extraction and precipitation process for absorbent reactivation within a solar-assisted CaL system, alongside an existing coal power plant. The process incorporated a secondary steam cycle and an ammonia absorption chiller for enhanced heat recovery and district cooling. The integrated project could increase daily power generation by 50% and reduce CO2 emissions from 820.4 g/kWh to 54.5 g/kWh. Over its lifespan, the reactivation facility could reduce limestone extraction by 21 Mt with 90% capture efficiency. With a levelized cost of electricity (LCOE) of 116.1 €/MWh and breakeven electricity selling price (BESP) of 56.6 €/MWh, the system demonstrated promising commercial viability, with the reactor and concentrated solar heating (CSH) system making up over 60% of investment costs. CSH cost and solar abundance were identified as key factors, indicating potential feasibility even in higher latitude regions. At CO2 revenues of 150 €/t, a stand-alone capture project can break even based solely on CO2 sales, demonstrating its potential for expansion to other areas. A case study highlighted the benefits of integrating absorbent reactivation and an ammonia absorption chiller, improving both economics and carbon capture efficiency. The study also confirmed the viability of solar-assisted projects in high-latitude regions, with optimistic future CO2 revenues and advancements in carbon capture technology enhancing feasibility.

A case study of thermal performance of gas-steam combined cycle with gas turbine inlet air cooling and condenser deep cooling

To enhance power generation during high summer temperatures and address the power supply and demand imbalance in gas-steam combined cycle, this study explored the exhaust gas waste heat refrigeration scheme, along with the optimal scheduling of cooling capacity between the precooling of inlet air for the gas turbines and deep cooling for condenser in steam cycle. Using the Ebsilon software, we investigate the thermal performance of the gas cycle, steam cycle, and the overall gas-steam combined cycle under various off-design operating conditions, including varying cooling capacity distributions, ambient temperatures, and generation loads. Based on our calculations, it is advisable to prioritize cooling capacity for precooling the ambient air for the gas cycle, balancing power generation and thermal efficiency. After the transformation, the power generation of the gas-steam combined cycle remains relatively stable across varying ambient temperatures, achieving a significant 10.9 % increase compared to pre-transformation levels under a 39 °C ambient temperature and 100 % generation load. Furthermore, the thermal efficiency of the gas-steam combined cycle improves by 1.11 % under a 40 % generation load condition. As ambient temperatures rise, the benefits of the inlet air cooling scheme become more apparent, validating its effectiveness in addressing the inherent summer power supply and demand challenges.

Thermodynamic Optimization of Trigeneration Power System

Worldwide, the growing demand for energy has been largely met through power cycles utilizing fossil fuels. Combined cycles, which integrate a gas turbine with a steam cycle, prove to be the best alternative due to their power generation capacity and high efficiencies. This efficiency is primarily attributed to the ability to harness exhaust gases to generate steam in the heat recovery boiler, allowing additional power generation through the steam turbine. Currently, there is a quest for the integration of low-temperature power cycles to maximize the utilization of residual thermal energy flows for power generation. Therefore, this work conducts an exergetic optimization of a power trigeneration system aimed at maximizing exergetic efficiency. This system includes a gas turbine and a steam cycle coupled with three different configurations of the Organic Rankine Cycle (ORC): a simple ORC, a supercritical ORC, and an ultracritical ORC. The ORC configurations are analyzed using eight organic working fluids, namely R1234yf, R290, R134a, R1234ze, R152a, R600a, R245fa, and R123. The results show that the maximum exergetic efficiency is achieved by using R152a in the ultracritical ORC configuration coupled with the combined cycle, achieving an exergetic efficiency of 55.79%. Furthermore, the maximum power generated is attained by the steam cycle with 85,600.63 kW and 3101.21 kW for the ultracritical ORC.

Performance comparison of sCO[formula omitted] and steam cycles for waste heat recovery based on annual semi-transient modeling under complex industrial constraints

The increasing demand for energy efficiency is compelling industries to seek ways to save energy. Waste heat recovery plays a crucial role by optimizing fuel usage through combined heat and power generation. In recent decades, sCO2 technologies have emerged as potential contenders to traditional steam cycles. However, there is a noticeable gap in literature regarding case studies on integrating off-design behaviors of components in complex industrial environments. To address this gap, this study focuses on a specific scenario involving a waste incinerator already linked to a steam generator within a cogeneration setup, alongside a flue gas cleaning unit. The conventional steam bottoming cycle is innovatively replaced with an sCO2 cycle, and a comparison between the performance of the existing steam technology and a numerical sCO2 model is conducted. This comparison involves modeling the off-design behaviors of each component run hourly over a one-year period. Results show that the sCO2 setup increases the electric power generation by 25% with the global efficiency around 43%, compared to the initial 37.3%. These outcomes answer a need in literature by showing that, even in off-design, the higher exergy efficiency of the sCO2 setup is more advantageous. Unlike steam evaporation at constant temperature, sCO2 is less constrained by temperature limitations in the heater and allows for higher turbine inlet temperatures. Additionally, an economic assessment reveals a levelized cost of electricity between 8.5 and 16.7 $/MWhe. However, further advancements in component modeling and enhanced energy recovery from cooler/exhaust gases are identified as areas for future research.

Optimal modes of operation and product cost allocation in sugarcane steam cogeneration plants

Sugar and ethanol production from sugar cane is one of the most competitive sectors of Brazil’s economy. The bagasse generated during the production process is used as fuel in cogeneration plants that provide thermal and electrical energy to the process. In the last decades, many sugar cane factories have produced a surplus of electricity that may be sold to the grid as a new product. This paper applies energy billing optimization and thermoeconomic analysis to a sugarcane steam cogeneration plant to determine the optimal operating mode of the plant, unveils the cost formation process of its internal products (refinery heat, process heat, and consumed electricity), and examines how the results are affected by: (i) the demand for the plant’s energy services, (ii) the availability of bagasse, and (iii) the selling price of surplus electricity. The thermoeconomic analysis involves a detailed study of the cost formation process, which is achieved through the decomposition of the steam cycle of the cogeneration plant into subcycles. Three main subcycles, in addition to the deaeration cycle and other auxiliary subcycles, have been identified: the cogeneration cycle generating work in the high-pressure turbine and refinery heat (subcycle one), the cogeneration cycle generating work in the high- and medium-pressure turbines and process heat (subcycle two), and the condensing cycle that generates only work in the high-, medium-, and low-pressure turbines (subcycle three). These subcycles make up the productive structure of the steam cogeneration plant and explain how water/steam goes through energy conversion processes from the bagasse energy to the heat and electricity produced. Both the optimization model and the thermoeconomic analysis serve as valuable tools for planning in response to potential changes in bagasse and electricity market prices, as well as fluctuating product demand conditions. In the base case, combining optimization with thermo-economic analysis, the unit monetary cost of the final products has been determined: heat for refinery (8.85 R$/MWh), electricity sold (183.60 R$/MWh), internally consumed electricity (41.51 R$/MWh), and process heat (8.85 R$/MWh).

The Hybrid Concept of Turboshaft Engine Enhanced by Steam Cycle Using Waste Heat Recovery—Combined Analytical and Numerical Calculation of Its Efficiency

<div>The article presents a hybrid concept of a turboshaft engine that fits into the area of PGE (pressure-gained combustion). It combines the advantages and elements of a piston engine and a turbine engine. The combustion takes place in isochoric chambers. The proposed timing system of the engine efficiently realizes the Humphrey cycle. Additionally, the main gas cycle engine was enhanced by the Clausius–Rankine steam cycle to achieve effective power of engine equal to 1231.3 kW. It was supplied by waste heat recovery from the exhaust gas. The enhancement of the engine by the secondary steam cycle significantly improved engine effective efficiency with a final value reaching 0.446. The effective efficiency and specific fuel consumption of the engine were calculated using merged analytical–numerical CFD (computational fluid dynamics) analysis. The centrifugal compressor, gas turbine, and steam turbine can work on the common shaft whose rotational velocity is 35,000 rpm. Because of additional weight, it could have potential applications for stationary use or heavy military units.</div>