Cycle Gas Turbine Power Plant Research Articles

Low-emissions hydrogen from MCH dehydrogenation: Integration with LNG regasification

Methylcyclohexane (MCH) is a promising organic hydride carrier for hydrogen transport and storage. Recovering hydrogen from MCH is an energy intensive process. An innovative idea of integrating this process with liquified natural gas (LNG) regasification is proposed in this study and demonstrated via modelling and simulation to substantially reduce external energy use. The synergistic benefits are twofold. In addition to providing a cold energy source for an effective high recovery cryogenic flash separation, the organic Rankine cycle based electrical power generation potential from LNG cold energy is fully exploited to reduce/eliminate external electricity demand for hydrogen compression to the high (end use) pressure. The results is a major reduction in carbon dioxide emissions. The proposed design for an integrated LNG-H2terminal can supply (1) 99.99 mol% pure hydrogen to a Combined Cycle Gas Turbine (CCGT) power plant and (2) commercial-grade natural gas to a gas-grid, both at the desired pressures and temperatures. Subsequently, rigorous simulation-based optimization was performed to minimize external energy inputs.A case study with 100 tph MCH and 100 tph LNG showed that integrating regasification with dehydrogenation produced 6.2 tph of hydrogen while gasifying LNG with a net power generation of 310 kW and a hydrogen recovery cost of 0.282 $/kg H2. Up to 7.3 tonnes of hydrogen can be produced per 100 tonnes of LNG without the use of external power. On the other hand, using external power, up to 11.3 tonnes of hydrogen can be produced per 100 tonnes of LNG without any external refrigeration. Overall, the superstructure proposed in this manuscript provides a generic initial approach for future MCH hydrogen supply chain projects, when considering integrations with LNG regasification plants.

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).

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.

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.

Thermodynamic Analysis and Improvement Potential of Helium Closed Cycle Gas Turbine Power Plant at Four Loads

This paper presents thermodynamic and improvement potential analyses of a helium closed-cycle gas turbine power plant (Oberhausen II) and dominant plant components at four loads. DESIGN LOAD represents optimal operating conditions that cannot be obtained in exploitation but can be used as a guideline for further improvements. In real plant exploitation, the highest plant efficiency is obtained at NOMINAL LOAD (31.27%). Considering all observed components, the regenerator (helium-helium heat exchanger) is the most sensitive to the ambient temperature change. An exact comparison shows that the efficiency decrease of an open-cycle gas turbine power plant during load decrease is approximately two and a half or more times higher in comparison to a closed-cycle gas turbine power plant. Plant improvement potential related to all turbomachines leads to the conclusion that further improvement of the most efficient turbomachine (High Pressure Turbine—HPT) will increase whole plant efficiency more than improvement of any other turbomachine. An increase in the HPT isentropic efficiency of 1% will result in an average increase in whole plant efficiency of more than 0.35% at all loads during plant exploitation. In the final part of this research, it is investigated whether the additional heater involvement in the plant operation results in a satisfactory increase in power plant efficiency. It is concluded that in real exploitation conditions (by assuming a reasonable helium pressure drop of 5% in the additional heater), an additional heating process cannot be an improvement possibility for the Oberhausen II power plant.

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.

Simulink modelling of Combined Cycle Gas Turbine (CCGT) power plant for performance analysis

A gas-fired plant and a steam-fired plant make up a combined cycle power station. The purpose of this research is to build a CCGT power plant and investigate the interaction between fuel and airflow using a simulink model. A mathematical model is used to predict how the CCGT power plant system will react. The goal of a turbine is to extract as much energy as possible from the working fluid and convert it into usable work. A large amount of heat energy from the gas turbine exhaust is wasted but has a lot of potential energy. The term total energy approach describes a system's capacity to use all of the energy at its disposal. To generate as little energy waste as possible, every watt of heat energy in a power system is supposed to be used to produce work, steam, or heat air or water. The creation of a mixed-cycle power plant is the most efficient and cost-effective way to accomplish this objective. The concept and early development of the mixed cycle were centred on the utilisation of thermal power plant waste heat. The temperature of the gas turbine exhaust can vary from 450°C to 650°C depending on the pressure ratio and turbine input temperature. It is wasteful to discard this energy into the environment. This wasted heat energy could be used to generate steam in the steam heat recovery generator (HRSG). By employing the Rankine cycle to expand the steam generated by the HRSG in a steam turbine, additional power may be created. One name for this configuration is a gas/steam mixed-cycle power plant. A gas turbine's exhaust temperature must be higher than 570°c. For the steam cycle to function properly and for the combined cycle efficiency to remain high.

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.

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.

Ambient conditions impact on combined cycle gas turbine power plant performance

ABSTRACT Although evolution in electrical power generation now continuously focuses on renewable resources, thermal power plants depending on typical fuels cannot be neglected. Market demand and their operational flexibility are the reasons why this type energy generation is worth investigating. This paper estimates the impact of intake ambient conditions on a combined cycle power plant (CCPP). Particularly, the investigation evaluates the effects of intake air ambient temperature and relative humidity in the context of the energy and electricity systems in Syria, specifically for the Jandar power plant. For an ambient temperature change from 3°C to 42°C, a standard temperature variation in the middle of Syria, the thermal efficiency of the CCPP is reduced from 53.3% to 45.7% at constant relative humidity of 60%. The net power output produced decreases from 00 MW at 15°C to 252.6 MW at 42°C. Although the amount of fuel consumed by combustion in the plant is reduced, the heat rate as well as the specific fuel consumption (SFC) increases. The SFC increased by 2.4% with a 20% increase in temperature at a constant relative humidity. A 3°C increase in temperature results in a 2.7% increase in the heat rate.

Sustainable opportunities to recover power plants’ waste heat: a benchmark of techno-economically optimized heat pumps

Current climate targets, adopted worldwide, pursue the decarbonization of all energy sectors. In power generation, the spread of RES has caused the shift of the Combined Cycle Gas Turbine (CCGT) power plants’ traditional role from providing constant baseload power to flexible operations providing services and backup capacity to the grid, as a consequence, the revenues opportunities on the traditional electricity markets (e.g., day-ahead, and intra-day markets) are no longer certain. At the same time is urgent to address a significant carbon intensity reduction in the heating sector, which is responsible for a large part of the current greenhouse gas emissions. Exploiting the low-exergy waste heat of CCGT’s water-cooled condenser as a thermal source for vapor compression heat pumps can meet two targets. On one hand, the revenues from heat production enhance the viability of the CCGT power plant, often essential for the security of the electrical supply. On the other hand, the heat delivered to the user represents a low-carbon alternative to traditional gas-fired boilers or even to air-sourced heat pumps characterized by lower efficiency. This work assesses the recovery of thermal energy from the sea cooling water at the bottoming cycle condenser of Tirreno Power 794 MWel CCGT in Vado Ligure through a high-temperature heat pump using R600 as a working fluid. Cooling water represents a privileged heat source and the integration into the power plant’s site allows running the HP at a lower cost than the electricity retail price. The case study takes into account the new Vado Ligure sports hall, to size the HP and explore the economic and environmental performances. The proposed layout is compared with the main solutions available: air source heat pump, gas, and electric boilers. The results show that on a lifespan of 20 years such integration of a heat pump with a CCGT could lead to consistent economical savings and emissions cuts.

Near-Optimal Decentralized Diagnosis via Structural Analysis

Health monitoring of current complex systems significantly impacts the total cost of the system. Centralized fault diagnosis architectures are sometimes prohibitive for large-scale interconnected systems, such as distribution systems, telecommunication networks, water distribution networks, or fluid power systems. Confidentiality constraints are also an issue. This article presents a decentralized fault diagnosis method that only requires the knowledge of local models and limited knowledge of their neighboring subsystems. The method, implemented in the decentralized diagnoser design ( <inline-formula xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink"> <tex-math notation="LaTeX">$D^{3}$ </tex-math></inline-formula> ) algorithm, is based on structural analysis and can advantageously be applied to high-dimensional systems, linear or nonlinear. Using the concept of isolation on request, a hierarchy is built according to diagnostic objectives. The resulting diagnoser is based on analytical redundancy relations (ARRs) generated along the hierarchy. Their number is optimized via binary integer linear programming (BILP) while still guaranteeing maximal diagnosability at each level. <inline-formula xmlns:mml="http://www.w3.org/1998/Math/MathML" xmlns:xlink="http://www.w3.org/1999/xlink"> <tex-math notation="LaTeX">$D^{3}$ </tex-math></inline-formula> proves of lower time complexity than its centralized equivalent. It is successfully applied to a nonlinear combined cycle gas-turbine power plant.

Graphical Prediction of Optimum Pinch Point Value with AEA Software Simulation and Validation Applied in Closed Cycle Gas Power Plant

Studying industries energy saving is very important prospect for many researchers in the last four decades. In this respect, better process heat transfer can be achieved to improve process operating and capital cost. Thereafter, obtaining higher amount of heat recovery, which will help to reach system optimum heat exchanger network design. Application of Pinch analysis (PA) in our current study, was found to be as an effective method towards economic solution and assessment for all system thermal processes. Whereby, minimizing energy losses, and thus, prediction of maximum energy saving. In addition, application of "Aspen Energy Analyzer (AEA)" simulation software assist our effort to optimize Heat Exchanger Network design (HEN), with various application scenario towards best design. This study represents a "Case study" as a Brayton closed cycle gas turbine power plant in Al-khairat district, which is one of a number of sites used to generate electricity for Iraq national grid. However, the plant original design is open cycle. This study, represent an attempt to apply (PA) in system closed cycle model with the same working conditions. The results predicted, on the contrary of open cycle, that using closed cycle (PA) with temperature difference ∆Tmin can be acceptable with several design propositions. The optimum (∆Tmin = 15℃) were evaluated in the closed cycle system pinch analysis, thereby the maximum Qrec. process that minimize the QHmin &amp; QCmin requirement were identified by the software simulation for the best HEN design. These results were found as Qrec. = 318.330 MW, QHmin = 88.607 MW and QCmin =39.564 MW.

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 the best and cost-efficient way is 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 utilization (CCU) or 5) replacement of power generation technology. 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).Option 1. In order to completely (100 % in energy values) replace natural gas by green hydrogen, we need electroliers with capacity of at least 2600 MW. Very roughly this is an investment of at least 2,6 billion EUR for hydrogen production, storage and supply. Additionally, we shall take into account necessary modernisation of CCGT plant to be capable for 100 % hydrogen firing as well as necessity to construct additional wind or solar capacity. Conversion efficiency from power to gas is approximately 60 %, while from gas to power – around 55-57 %. Overall conversion efficiency is 33-35 %. The main advantages of this option are a) possibility for wide use of renewable energy sources (wind and solar) in hydrogen production, b) avoidance of carbon dioxide emissions during the electricity production, c) possibility to supply a surplus of hydrogen to transport sector and industry, d) avoidance of all problems associated with CCS option, including the ban for geological storage of CO2. The main disadvantages of this option: a) very high costs of hydrogen production, b) very low conversion efficiency, c) necessity to convert CCGT plant for hydrogen combustion and to install considerable wind and solar capacity.

Multiparametric optimization of a reheated organic Rankine cycle for waste heat recovery based repowering of a degraded combined cycle gas turbine power plant

The study has conducted multiparametric optimization of a newly modified double stage reheated organic Rankine cycle configuration for the objective function of specific work output and its comparison with other conventional configurations of the organic Rankine cycle for the waste heat recovery-based repowering of a degraded combined cycle gas turbine power plant using R245fa, R113, and R141b as the working fluids. Thermodynamic performance of the triple cycle formed by integrating each organic Rankine cycle configuration with the combined cycle gas turbine unit is assessed in terms of repowering, specific fuel consumption and specific water consumption along with the associated greenhouse gas emissions. 24-hour performance variation of the combined cycle gas turbine unit has been incorporated in the analysis. It is found that the double stage reheated organic Rankine cycle configuration has outperformed other configurations in terms of thermodynamic performance. Triple cycle for the double stage reheated organic Rankine cycle has resulted in an average of 1.37% increase in net power output for the working fluid R141b, equivalent to 5.10 MW of additional power output. The thermal efficiency of the triple cycle for double stage reheated organic Rankine cycle has increased by 1.40%, whereas the specific fuel consumption and specific water consumption have reduced by 1.28% and 3.35%, respectively using R141b as the working fluid. The highest waste heat recovery potential is exhibited by the integrated basic organic Rankine cycle configuration for the working fluid R245fa, recovering 30,840 kW of waste heat, equivalent to the burning of 2467.2 kg/hr of CH4 and 6784.7 kg/hr CO2 emissions.