Combined Cycle Gas Turbine Power Research Articles

A Surrogate Model Approach to Predict Operations and Maintenance Cost for Combined Cycle Power Plant

Abstract In the transition toward carbon neutrality by 2050, renewable energy sources are gaining prominence. The variability of renewable energy poses challenges for power grid stability. Gas turbine combined cycle (GTCC) power plants play a crucial role in grid stabilization, especially during peak loads. In GTCC power generation, operations and maintenance (O&M) cost is the next most important after fuel and initial investment cost, and it is necessary to predict O&M cost according to changes in the operating environment for efficient and stable operation of GTCC power plant. However, various uncertainties exist when estimating O&M costs because actual design information is limitedly disclosed due to maintenance contracts between operators and manufacturers, and it is difficult to obtain accurate variables according to the operation condition. In this paper, the correlation was analyzed considering the uncertainty of the factors affecting the O&M cost of the GTCC power plant through sensitivity analysis, and the main factors were defined. In addition, a surrogate model was proposed that can quickly calculate fixed and variable O&M cost according to changing operating scenarios such as shortening startup time, enhancing ramp rate, or lower minimum load. Through the case study, short-term and long-term O&M costs can be estimated in the operating environment of the GTCC power plant currently being operated. Additionally, the model facilitates cost projections for new hybrid GTCC facilities (combining gas turbines with energy storage systems), aiding long-term investment planning.

Studi Numerik Pengaruh Sudut Bukaan Damper dan Flue Gas Temperatur Terhadap Distribusi Temperatur Pada Heat Recovery Steam Generator (HRSG)

The Combined Cycle Gas Turbine Power Plant (PLTGU) utilizes the waste heat from the gas turbine to produce steam in a Heat Recovery Steam Generator (HRSG). The steam from the HRSG is then used to generate electricity in a steam turbine. In HRSG operation, several variables significantly impact its performance, including the damper angle and inlet temperature. At the Tanjung Uncang Power Plant in Batam, the manufacturer's standard operating procedure (SOP) requires that the exhaust gas temperature when the damper is open must be below 400°C. However, the gas turbine with an initial load of 5 MW has an exhaust gas temperature of 560°C - 580°C. Therefore, it is necessary to perform a gas turbine load release or FSNL (Full Speed No Load) to reduce the inlet temperature of the gas turbine. During FSNL, there are SOPs for diverter damper angles of 51°, 68°, and 90°. This leads to the need for analyzing the impact of diverter damper angles and inlet temperature on the flow pattern and temperature distribution. The analysis was conducted using CFD (Computational Fluid Dynamics) with ANSYS Fluent 2020 software. The variations used are diverter damper angles of 51°, 68°, and 90°, combined with inlet temperatures of 400°C and 580°C. The simulation outputs include velocity contours, temperature contours, and equivalent stress on the superheater tubes. The HRSG simulation results show that the flue gas is not distributed uniformly. The turbine exhaust gas only spreads along 4 – 11 meters, leading to slower steam production from the superheater. Additionally, when the superheater tubes are empty, the steady-state thermal and structural simulation results indicate that an inlet temperature of 580°C, whether at damper angles of 51°, 68°, or 90°, can cause a larger temperature difference between the inner and outer walls, ranging from 117.04°C to 125.5°C. This temperature difference can lead to thermal stress on the superheater tubes. This is shown in the S-N Curve for SA 213 T22 material, with a convection coefficient of 5 W/m² K (no steam), where the equivalent stress exceeds the endurance limit (infinite zone).

Onboard pre-combustion carbon capture with combined-cycle gas turbine power plant architectures for LNG-fuelled ship propulsion

This paper investigates the concept of pre-combustion carbon capture (Pre-CCS) with a combined cycle gas turbine (CCGT) propulsion system to achieve energy efficient carbon capture onboard a Liquid Natural Gas fuelled vessel. A basic CCGT model with energy efficiency of 51.6 % when using LNG as fuel was integrated with a Pre-CCS system composed of a steam methane reformer, water–gas shift reactors, pressure swing adsorption (SMR-PSA), and liquid CO2 storage. Various waste heat utilisation schemes integrated with the CCGT-reformer were modelled in Aspen HYSYS. The modelling of the waste heat recovery networks as energy streams integrating between various processes and unit of operations has facilitated a closed-loop simulation of various systems. It was concluded that a proper utilisation of the high-grade heat from the gas turbine (GT) exhaust and from the reformer is crucial to improve the overall energy efficiency and carbon capture rate, exemplified by a scheme where the heating needs for the SMR and the cooling needs from the water–gas-shift reactors are fully integrated. When optimised, the integrated system had an overall energy efficiency of 41.5 % and 43.2 % (i.e. an efficiency loss of 10.2–10.5 percentage points from the base CCGT system) accompanied with specific GHG emission reduction of 51.2 % and 52.3 % for operation of the GT at a turbine entry temperature of 1700 K and 1850 K, respectively. Intermediate levels of reforming, where the GT uses a mix of LNG and reformate gases, were also simulated, showing an almost linear evolution from the 100 % LNG feed to the GT to the 100 % reformate case. Such a strategy could be used for gradual evolution to meet the required CO2 reduction timeline. It was determined that the 100 % reformate case provides the highest CO2 capture rate. Estimates of other emissions from the GT assuming typical combustor residence times for the whole range of fuel blends were also carried out, showing that the overall greenhouse gas emission is dominated by CO2, given that the GT emits negligible N2O and unburnt methane. Some capital cost estimates were also made to determine the unit price of hydrogen fuel produced onboard, suggesting that the CAPEX was not prohibitive. These findings support the pre-combustion CCS − CCGT integrated system as a promising long-term decarbonisation and propulsion strategy to comply with emissions regulations, displaying good performance in terms of cost, energy consumption, and CO2 reduction. The scalability and adaptability of the proposed system for existing and new-built ships across the decarbonisation timeline is also discussed.

Zero carbon emission CCGT power plant with integrated solid fuel gasification

The development of a high-capacity power plant with zero CO2 emissions is an urgent task that will curb the increase in atmospheric temperature. It should have an efficiency comparable with existing TPPs, a low metal consumption rate, a high fuel versatility, and high flexibility. To meet these conditions, oxygen combustion is conducted in an environment of inert CO2, and most of the condensation heat from the combustion products is usefully utilized. This work presents a combined cycle gas turbine (CCGT) power plant with solid fuel gasification, oxy-fuel combustion, and a pressurized heat recovery steam generator (PHRSG). The two plant options are compared with the natural gas plant previously proposed. In the PHRSG, the low metal intensity is achieved by high average temperature differences, the pinch point value at 8–12 °C, and the intensification of heat transfer caused by the high pressure of combustion products and the condensation of water vapor in the tail surfaces. The developed plants are highly efficient when using coal, 51%, and 57.3% when using peat, and have acceptable CO2 avoidance costs of 72.7 €/t and 60.4 €/t. By combining these factors, and using well-developed materials, it will take less time to develop and implement this plant widely.

Techno-economic analysis on the balance of plant (BOP) equipment due to switching fuel from natural gas to hydrogen in gas turbine power plants

<abstract> <p>The concerns over greenhouse gas emissions, environmental impacts, climate change, and sustainability continue to grow. As a result of countermeasures, many modern gas turbine power plants and combined cycle power plants are considering to use hydrogen as a clean fuel alternative to fossil fuels in the power plant industry. We assessed the implications of such transition from natural gas to hydrogen as fuel in a gas turbine power plant's balance of plant (BOP) equipment. Using the DWSIM process simulation software and the methodology of compression power changes against different gas compositions, the impact of blending hydrogen with natural gas on temperature differentials, energy consumption, adiabatic efficiency, compression power, and economic implications in gas turbine power plants were examined in this paper. We discovered, through analysis, that there was not a noticeable boost in compression power or energy consumption when 50% hydrogen and 50% natural gas were blended. Similarly, there was no discernible difference in temperature differentials or adiabatic efficiency when 30% hydrogen and 70% natural gas were blended. Moreover, mixing 50% hydrogen and 50% natural gas did not result in a noticeable cost climb. In addition, the techno-economic analysis presented in this paper offered valuable insights for power plant engineers, power generation companies, investors in energy sectors, and policymakers, highlighting the nature of the fuel shift and its implications on the economy and technology.</p> </abstract>

Disturbance size estimation in Great Britain power system including combined cycle gas turbine power stations

With the substantial popularity of combined cycle gas turbine (CCGT) power plants in the nowadays power systems, special care must be taken to regulate frequency due to unique frequency response characteristic of the full-loaded CCGT units. This unique feature is documented in the literature; however, its effect on determining frequency response of the power systems was not addressed in detail. This study proposes a new analytical method to achieve a more accurate estimated size of a loss-of-generation disturbance. This method considers demand-side power deviations and transmission lines power loss as well as unique frequency response of the CCGT units following the event. Firstly, it is exposed that there is an approximately linear relationship between power and frequency deviations of these plants in a real-world power system despite the complexity of the CCGT model. This relationship may be represented by a negative droop gain. Next, the derived CCGT’s linear characteristic is formulated in the disturbance size estimation process. Finally, the effectiveness of the proposed modifications is demonstrated through extensive simulations on a 36-zone Great Britain equivalent test system.

Application of deep learning modelling of the optimal operation conditions of auxiliary equipment of combined cycle gas turbine power station

Reasonable condition adjustment of the auxiliary machinery can optimize the operation performance of the Combined Cycle Gas Turbine (CCGT) power station. In this paper an optimization method for the operation control of the auxiliary equipment based on deep learning is proposed and applied to an F-class gas turbine generation unit. A database of the optimal operating conditions is established to achieve the best economic benefit based on the analysis of two years of historical operation data. The control optimization models are built using the machine learning algorithms including the Multi-Layer Perceptron (MLP), Supporting Vector Machine (SVM), Gaussian process regression and linear regression methods and their accuracy has been compared. The input parameters of these models consist of the load rate, the heating output and the ambient temperature, with the output parameters including the electrical currents for the mechanical draft cooling tower, the high pressure feed pump, the medium pressure feed pump and the condensate pump. The MLP model is designed with different network hidden layer structures and provides the highest calculation accuracy with the least average error of 1.82 %. Different training data sizes are compared and the optimal control trajectory is analyzed. The result can provide useful references for the optimization of auxiliary equipment operations.

Synergetic performance of gas turbine combined cycle unit with inlet cooled by quasi-isobaric ACAES exhaust

Gas power generation units are challenged with peak regulation in the new power system characterized by high proportion of renewables. In aim to enhance the part-load performance and the peak-regulation capacity of gas turbine combined cycle (GTCC) power units, a synergetic power system of GTCC integrated by an isobaric and adiabatic compressed air energy storage (IACAES) was proposed, where the compressor inlet air in the gas turbine was directly mixed and cooled by the ACAES exhaust. Based on the demand load distribution of a GTCC unit and the off-design performance, the parameters of the IACAES were designed for the proposed synergetic system (SS), and comparatively for the benchmark integrated system (BS) without compressor inlet cooling. The peak-regulation performances of the proposed synergetic system were investigated and compared with those of the standalone GTCC as well as the benchmark system. The case study in a 67.3 MW GTCC indicates that, in the range of the ambient temperature from 283.15 to 308.15 K, the GTCC operative efficiency considerably enhances by averagely 0.943% resulting from the power shifting. The IACAES discharging power and roundtrip efficiency in SS are 10.5% lower than those in BS. An average negative gap of system efficiency in SS reaches 0.199% versus BS. However, GTCC inlet cooling by IACAES exhaust enhances the power capacity of the unit averagely by 1330.88 kW, and the peak-regulation capacity increases averagely by 10.59% compared to that in the standalone GTCC. The peak-regulation capacity enhances by 1.98% versus BS. The synergetic cooling effect weakens with the reduction in the ambient temperature and the charging air pressure.

A novel inlet air cooling system to improve the performance of intercooled gas turbine combined cycle power plants in hot regions

In hot climates, the entry of high-temperature air into the compressor of intercooled gas turbine power plants (IcGTCC) can lead to reduced electricity production during peak demand periods. To address this issue, this study proposes a novel inlet air cooling (IAC) system for improving the performance of IcGTCC in hot regions. This system utilizes waste heat from the intercooler to cool the compressor's inlet air via absorption chillers. The performance of this system was evaluated and compared to four popular IAC technologies: evaporative cooling, solar-powered absorption cooling, steam-operated absorption cooling, and vapor compression cooling. Additionally, the expected annual profit and payback period were estimated. Results show that the proposed IAC system resolves the drawbacks of IcGTCC in hot regions, increasing the power output by 19% and the overall efficiency by 2.3%. It is estimated that the proposed IAC system can improve plant efficiency by 8–18% compared to literature designs, leading to higher annual profits (66% and 10% higher than steam and mechanical cooling systems, respectively). Moreover, it has a short payback period of 1.74 years, which is 3%, 67%, and 85% shorter than mechanical, steam, and solar cooling systems, respectively, making it a highly cost-effective solution.

Comparison of model-driven soft measurement methods for compressor air flow in gas-steam combined cycle power units

The determination of the air flowrate at the compressor inlet is meaningful for the performance diagnosis of heavy-duty gas turbine combined cycle (GTCC) power units, whereas the compressor air flow generally cannot be directly obtained from the field data. In this paper, the procedures of three model-driven methods for soft measurement of compressor air flow were presented, including energy balance of the coupled HRSG (M1), static pressure at the compressor manifold (M2) and gas turbine joint operation line method (M3). In the case of a M701F4 GTCC power unit, the methods M1 and M3 were validated by the field and testing data; while the method M2 was calibrated and the effective area at the air manifold was decided as 12.606 m2 using M1 at the full load of gas turbine. The compressor air mass flow at overall loads was computed with the various methods. The comparative investigation to these methods shows that, the compressor inlet air flow is determined as 682.75 kg/s by M1 and 664.07 kg/s by M3, respectively, at the full load and at the ambient temperature 29.912 °C. The air flow obtained by M1 and M2 appears relatively higher than that by M3 at typical various loads of gas turbine; however, the method M3 shows a good accordance with the actual value of the air flow for turbine rotor cooling. Both M2 and M3 agree in the theoretical demonstration that compressor air flow is strongly related to the gas turbine load at certain conditions. The method M1 can be deemed as a reference for another two methods in the case of the steady operating state at full load; whereas it is not recommendable for the real-time measurement of compressor air flow, because of the large amounts of required input variables and the fluctuation in the flow meters.

The prospects of flexible natural gas-fired CCGT within a green taxonomy

Despite increased commitments toward net zero, there will likely be a continued need for natural gas to provide low carbon dispatchable power and blue hydrogen to balance the increased penetration of renewables. We evaluate the CO2 emissions intensity of electricity produced by (i)natural gas-fired combined cycle gas turbine (CCGT) power plants with carbon capture and storage (CCS), and (ii) blue hydrogen CCGT plants which uses steam methane reforming with CCS to supply H2. This study aims to determine whether these assets are able to meet a possible green taxonomy emissions threshold of 100kg CO2 eq/MWh. Key considerations include methane leakage, CO2 capture rate, and the impacts of start-up and shut down cycles performed by the CCGT-CCS plant. This study suggests that, in order for natural gas to play an enduring role in the transition toward net zero, managing GHG emissions from both the upstream natural gas supply chain and the conversion facility is key.

Analysis of CO2 capture process from flue-gases in combined cycle gas turbine power plant using post-combustion capture technology

Combined cycle gas turbine power plants (CCGTs) are a combined cycle consisting of a gas turbine and a steam turbine to generate electricity. Sometimes CCGTs incorporate cogeneration to produce both heat and power. After the gas fuel combustion in the gas turbine combustion chamber, the flue gases are passed through the Heat Recovery Steam Generator (HRSG) to extract heat and generate additional electrical power using the steam turbine. The CCGT technology is recognized for its highest efficiency of 58% in electricity production among the power production technology. A highly efficient CCGT power plant with 60% efficiency produces even 2.5 times less CO2 than a modern coal power plant with an efficiency of 45% because of the use of gas fuel and electrical efficiency. The CO2 emission can be reduced further when the post-combustion CO2 capture methods are applied. To perform CO2 capture and to reduce the CO2 emission from power plants, the CO2 mass fraction in flue gas is the crucial parameter for the operation of the Post-combustion Carbon Capture and Storage (PCCS) technology. The PCCS technology uses solvents, which is the aqueous solution of amine that reacts with flue gas and absorbs the CO2, which is treated and separated later. The paper presents the results of the energy analysis of a post-combustion carbon capture process when integrated with a combined cycle gas power plant. The study considered two different gas fuels such as methane and syngas. Syngas composition was determined from the sewage sludge gasification process and can be treated as zero-emission CO2 gas fuel. When the flue gas produced from the syngas is used in PCCS at more than 50% of load conditions, the negative CO2 emission level in large-scale CCGT power plants can be reached. The paper presents the results of mass and energy balance analysis of HRSG of a CCGT integrated with PCCS to perform CO2 capture. The analysis of HRSG using flue gases from methane and syngas is performed by calculating the enthalpy of flue gas, rate of heat exchange, and temperature distribution of each component of HRSG. The comparison of the result shows slight differences due to the different composition and flow rates of flue gases. The flue gas at the outlet of two HRSG is used in the PCCS at different load conditions. An aqueous solution of 30 wt% Monoethanolamine (MEA) with rich loading of 0.5 mol-CO2/mol-MEA and a mixture of 16 wt% 2-amino-2-methyl-1-propanol (AMP) – 14 wt% Piperazine (PZ) with rich loading of 0.62 and 0.86 mol-CO2/mol-amine respectively are used in the PCCS. Due to the reboiler duty of amines, the steam consumed by the PCCS for AMP-PZ regeneration is less compared to MEA. Depending upon the flue gas and solvent used in the PCCS, the power consumed by the PCCS from CCGT power plant is measured from 9.6% to 11.6%. For the given operating condition of the CCGT and PCCS at more than 50% load condition, the negative CO2 emission level can be achieved.

Modeling, performance enhancement, and the NOx emission reductions of the triple-pressure reheat water-recuperated air-cooled gas turbine combined cycle power plant using interstage compressor water injection and optimization

Interstage compressor water injection (ICWI) reduces the work of an air compressor, air temperature at its outlet, adiabatic flame temperature, and NOx emissions. When ICWI is introduced to combined cycles, it decreases the surge margin for the air compressor and increases the mass flow rates of the gas through the gas turbine (GT) and generated steam for the heat recovery steam generator and, therefore, power output. For the combined cycle with ICWI, air with two distinct characteristics (before and after ICWI) is used to cool the GT and mix with the expanded gas. In this paper, ICWI was introduced to the triple-pressure reheat air-cooled GT combined cycle. Detailed modeling was carried out for the processes of compression, ICWI, combustion, and GT expansion. Constraints were imposed on the amount of injected water and its temperature and pressure leading to a practical application of ICWI and a safe surge margin for the air compressor. The efficiency of the combined cycle with ICWI was optimized relative to the pressure of ICWI, injected water temperature, and relative humidity of air at the outlet of the water injector at different values of turbine inlet temperatures and air compression ratios. The results indicated that ICWI and optimization could reduce the initial NOx emissions by more than 90% (the NOx emissions that are produced at the adiabatic flame temperature) and enhance cycle efficiency by 1.9 to 2.7 percentage points and power output by 27 to 34 percent. The water recovery system could produce a significant amount of water that exceeds twice the injected amount at no fuel cost and could be integrated into the cycle at no additional equipment costs if CO2 capture or exhaust gas recirculation was implemented.

Process synthesis for amine-based CO2 capture from combined cycle gas turbine power plant

The study provides technoeconomic evaluations of advanced MEA-based Post-Combustion CO2 Capture (PCCC) process configurations applied to a 750 MW Combined Cycle Gas Turbine (CCGT) power plant. Rigorous rate-based model of the PCCC process developed in Aspen Plus was validated and then used to study synergistic effects of combining three process configurations in one flowsheet using energy and levelized cost of capture as key performance indicators (KPIs). The results of the energy and economic analysis elucidate that Absorber Inter Cooling (AIC) + Rich Solvent Split (RSS) + Lean Vapor Compression (LVC) is the optimal combination of MEA-based PCCC process as it provided minimum regeneration energy (2.80 GJ/tCO2) and levelized capture cost (72.7 $/tCO2) representing an overall energy and cost savings of 6.25% and 8.95%, respectively. The study demonstrates that the usage of single KPI such as energy savings can provide misleading results. For example, combination of AIC + RSS + Inter Heated Stripper (IHS) provided maximum equivalent energy savings (3.50%), however, it did not result in highest cost savings due to high capital and operating costs of additional heater and pump. Overall, the study underlines the potential of advanced mature technologies on energy and cost reductions.

Effect of air-fuel ratio and pressure ratio on the exergetic performance of combined cycle gas turbine plant components

The performance of a combined cycle gas turbine power plant depends on multiple operating parameters, which are influential in distinct ways. These parameters are classified as gas turbine parameters and steam turbine parameters. This paper deals with the influence of two gas turbine operating parameters, i.e., pressure ratio and air-fuel ratio. The 2nd law of thermodynamics has been taken into consideration along with energy analysis to measure the performance of several components of a combined cycle gas turbine plant. Therefore, a comprehensive exergy analysis for each element and the plant has been carried out to overserve the trend of the given range of aforementioned parameters. It is observed from the results that exergy destruction increases in the compressor at a higher-pressure ratio if the compressor is subjected to increased airflow, but exergetic efficiency remains unchanged. Moreover, a similar increment has been observed in the combustion chamber, but the rate of change varies along with the increase in the Air-fuel ratio. For the lower pressure ratios (5-10), the exergy destruction rate for the steam turbine decreases along with increasing in air-fuel proportion, but the effect becomes nearly opposite for the higher-pressure ratios.

Decarbonisation options of existing thermal power plant burning natural gas

Nowadays power industry faces deepest crises ever with unprecedented prices shocks and climate challenges at the same time. From one hand we realise the need of energy transformation of power industry towards more sustainable future with climate neutral technologies. From the other hand it become obvious that this change could not happen immediately and transition period is needed with some fossil fuel technology still playing an important role as a back-up for renewable energy sources. The biggest question what is the best and cost-efficient way to decarbonise existing thermal power generation. We try to address it on the example of existing combined cycle gas turbine (CCGT) power plant fuelled by natural gas. Clearly the following possible options were identified: 1) replacement of natural gas with alternative gases, such as green hydrogen, bio or synthetic methane, 2) carbon capture and underground storage (CCS) in geological formations, 3) carbon capture, liquefaction and export, 4) carbon capture and utilisation (CCU). US giant General Electric in its publication “Decarbonizing gas turbines through carbon capture” is considering similar options for decarbonising of gas turbines. They divide it into two approaches: 1) pre-combustion by using a zero or carbon neutral fuels, such as hydrogen, synthetic methane, biofuels or ammonia and 2) post-combustion by removing carbon from the plant exhaust, using liquid or solid sorbents or oxy-fuel cycles. In this publication we try to compare these different options, despite they are not clearly comparable. For the analysis we take natural gas fired CCGT plant Riga TPP-2 in Latvia with installed capacity of 881 MW (in condensing mode).

Long-term atmospheric pollutant emissions from a combined cycle gas turbine: Trend monitoring and prediction applying machine learning

Carbon monoxide (CO) and oxides of nitrogen (NOx) are noxious pollutants associated with combined cycle gas turbine (CCGT) power plants that require careful monitoring and control. A publicly available dataset links five years of hourly CCGT emissions to nine recorded operational/environmental variables. This study applies twelve multi-linear regression (MLR) and machine learning (ML) models to rigorously predict CO and NOx for that dataset with a novel analytical sequence. Statistical distributions of the data reveal time shifts in the CO and NOx values that cannot be explained by the recorded variables. The relative variable weights applied to the variables by the certain MLR/ML models identifies that their relative importance in influencing CO and NOx predictions varies substantially. Multi-K-fold cross validation is applied to establish the prediction accuracy of each model and indicate the most suitable data-record splits for training and validation. Trained K-nearest neighbour (KNN) and extreme gradient boosting (XGB) ML models consistently provide the most reliable CO and NOx emission predictions with least errors when applied to unseen test data. Consideration of mean errors and predicted versus measured data trends make it possible to identify and partially correct MLR/ML predictions for systematic time shifts in the CO and NOx data. The best performing KNN models generate mean average errors of 0.8458 mg/m3 for CO (∼1.9 % of the CO data range) and 5.1234 mg/m3 for NOx (∼5.5 % of the NOx data range) for a two year period separate from the model’s training/validation period.

Simulating Combined Cycle and Gas Turbine Power Plant under Design Condition using Open-Source Software DWSIM

Nowadays, clean and high-power generation is essential matters worldwide. To be improved and optimized, power plants require accurate models that can be introduced to process simulators. There is various commercial software for industrial simulation which is not accessible to everyone. The open-source DWSIM process simulator is the first chemical engineering code that offers many tools for the better study of industrial plants. In this paper, we employ DWSIM software to simulate a combined cycle gas turbine (CCGT) power plant under design conditions for three cases. The generic models are predicted for multistage compressors and compressor maps. In the first case, two models developed in ASPEN HYSYS and GateCycle will be considered. The achieved results by DWSIM are acceptably comparable for thermal efficiency and power generation. The DWSIM result is 3.5% lower than the ASPEN HYSYS for thermal efficiency, and the power generation is completely the same. In the second case, rigorous simulation was carried out using actual field data from the local CCGT power plant. The DWSIM outcomes are very close to the practical data. The power generation of GT and CC is very close; the variety is nearly 0.45%. In the third case, the simulation of CCGT with a cogeneration system is precisely accomplished, and the outcomes of DWSIM are shown in excellent agreement. The DWSIM prediction shows lower values by 0.26%, 4.79%, and 0.72% for the HP turbine, LP turbine, and plant net power, respectively.

Creep-Fatigue Interaction on Small Crack Propagation in a Single Crystal Superalloy under Thermomechanical Fatigue Condition

Recently, the high-efficiency gas turbine combined cycle power generation has become essential in operation as a backup power supply of renewable energy sources. In turbine blades and vane of the gas turbine operated as a backup power supply, there is growing concern about the damage due to thermo-mechanical fatigue (TMF) loading because of expecting increased starting/stopping cycle and frequent load fluctuation. This study investigated the small crack propagation behavior in single crystal Ni-based superalloy under the in-phase TMF loading cycle. The creep-fatigue interaction on the small crack propagation behavior was discussed based on the relationship between the crack growth rate and the creep J-integral, considering the small-scale creep at the crack tip. The experimental results indicated that the crack growth rates under the in-phase TMF loading cycle were significantly higher than those under the out-of-phase TMF condition at a given fatigue J-integral range. In addition, introducing the tension holding at the maximum temperature in the in-phase TMF loading cycle accelerated the crack growth rates. The small-scale creep stress field at the crack tip might dominate the small crack propagation behavior under the in-phase TMF loading with the high-temperature holding as the creep-fatigue interaction.

Modelling, scale-up and techno-economic assessment of rotating packed bed absorber for CO2 capture from a 250 MWe combined cycle gas turbine power plant

The huge sizes and costs of the packed bed (PB) absorbers and strippers in solvent-based post-combustion carbon capture are part of the challenges limiting its commercialization. The rotating packed bed (RPB) absorbers and strippers have the potential to reduce the size and cost of the CO2 capture process when used to replace their PB counterparts. However, the size and cost have not been quantified for a large-scale RPB. Therefore, this paper is devoted to providing detailed technical and economic assessments of a large-scale RPB absorber operated with concentrated (55-75 wt%) monoethanoamine (MEA). To achieve this, a steady-state rate-based model of the RPB absorber was developed and validated in Aspen Custom Modeller®. The model was scaled up to capture CO2 from the flue gas of a 250 MWe CCGT power plant using an iterative scale-up methodology proposed in this study. Technical assessments of the large-scale RPB absorber indicated that a 4–11 times volume reduction factor was achieved with 55 wt% MEA concentration compared to PB absorbers. The highest volume reduction factors of 5–13 times were achieved in RPB absorber operated with 75 wt% MEA. Economic assessments show that the capital expenditures of the RPB absorbers were lower by 3–53%. The CO2 capture cost was also lower ($6.5/tCO2–$9/tCO2) compared to $15/tCO2–$24/tCO2 obtained for the PB absorbers.