Combined Cycle Gas Turbine Plant Research Articles

Techno-economic analysis of ammonia cracking for large scale power generation

The increasing interest in leveraging green ammonia to mitigate carbon emissions in fertilizer production is paralleled by an expanding acknowledgment of its potential as a fuel for decarbonizing the electricity sector, particularly in high-efficiency gas turbine power plants. Co-firing ammonia with hydrogen presents a promising method for integrating ammonia into existing infrastructures. Within this context, the development of efficient technology for ammonia cracking presents a potential avenue for deploying ammonia in gas turbines. The objective of this study is to conduct a preliminary techno-economic evaluation and uncertainty analysis of two cracking technologies namely a membrane reactor and a conventional FTR (Fired Tubular Reactor) for the co-firing of ammonia with hydrogen in a CCGT (Combined Cycle Gas Turbine) plant. The integration of a membrane reactor during the cracking stage demonstrates a remarkable improvement in the system's thermal efficiency, surpassing traditional approaches by over 25%. Additionally, it brings about an approximate 10% reduction in the levelized cost of hydrogen (LCOH), despite a higher initial capital expenditure (CAPEX). At the CCGT level, the discrepancy in levelized cost of electricity (LCOE) narrows, as it is strongly influenced by the cost of ammonia constituting 80% of the LCOE. Beyond LCOE, the widespread adoption of these systems also faces challenges due to material scarcity. Analysis reveals that revamping just 1 GWe of CCGT assets using membrane reactors would for example necessitate approximately 0.11% of the global palladium supply, and 10% of the global ruthenium production. Considering the limited availability of these resources, coupled with their high demand across multiple sectors and the possibility of external factors such as geopolitical tensions, this strategy seems unfeasible. To tap into this market, future research should prioritize the exploration of alternative membrane materials, such as carbon molecular sieves, and catalysts, like nickel.

Physically 100 % renewable electricity supply through hybrid electricity storage – A top-down modelling study for the case of Austria

A top-down model calculation based on real generation and demand data is presented for the hypothetical case of 100 % renewable electricity generation combined with hybrid electricity storage infrastructure in the Austrian control area (9 million inhabitants, electric demand ∼70 TWh per year). To reach 100 % physical coverage by renewables, the actual wind and photovoltaic generation curves in the selected reference year of 2022 were scaled by a factor of 2.8 and 30, respectively. In the scope of the presented system are lithium-ion battery storage (cyclic efficiency 90 %), pumped hydro storage (70 %) and power-to-gas storage with subsequent re-electrification in gas turbine combined cycle plants operated as combined heat and power (CHP) system (30 %). Our core aspect lies in the optimized operation of the hybrid storage system, where the charging and discharging of the storage technology with higher cyclic efficiency is given priority. A straightforward cascading control algorithm is applied with individual elements functioning as simple proportional controllers. The results show how a 100 % renewable electricity system in Austria could be configured, partially building upon existing electricity generation infrastructure (pumped hydro and gas turbine combined cycle plants) and on the implementation of new lithium-ion battery storage with a total capacity of 100 GWh and new electrolysis infrastructure with a power of 5 to 10 GW. To overcome existing limitations of the presented model, an extension to a more complex model with spatial differentiation and consideration of electricity grid characteristics and constraints is recommended.

An efficient methanol pre-reforming gas turbine combined cycle with integration of mid-temperature energy upgradation and CO2 recovery: Thermodynamic and economic analysis

An innovative design has been developed to optimize the performance of the gas turbine combined cycle (GTCC) by integration with a decarbonized methanol steam reforming (MSR-deCO2) system based on the principle of the cascade utilization of chemical and thermal exergy. In the integrated system, the primary fuel is reformed with the steam extracted from GTCC and decarbonized before combustion. The reforming process leads to a significant reduction of exergy loss in the combustor. Introducing methanol as a viable turbine fuel presents an opportunity for recuperating mid-temperature heat as chemical energy through endothermic MSR and redeeming it as high-grade thermal energy in the combustor. By such incorporation, the power generation of the mid-temperature heat in the bottoming cycle is significantly enhanced, and most of the CO2 is removed as the liquid phase. Based on a 530 MW GTCC plant, thermodynamic analysis reveals a 4.6% energy efficiency increase, a 4.3% exergy efficiency boost, and an 82.2% CO2 recovery with a 0.354 MJ/kgCO2 energy penalty. The proposed design yields 454.4 M$ more profit than the reference power plant throughout its lifespan. Additionally, sensitivity analysis indicates optimal conditions for MSR at approximately 250 °C, a 1:1 water-to-methanol ratio, and a higher reaction pressure preference.

Exergy-based sustainability analysis of combined cycle gas turbine plant integrated with double-effect vapor absorption refrigeration system

Exergy-based sustainability analysis of combined cycle gas turbine plant integrated with double-effect vapor absorption refrigeration system

An efficient methanol pre-reforming gas turbine combined cycle with mid-temperature energy upgradation: Thermodynamic and economic analysis

A novel design has been developed to optimize the performance of the gas turbine combined cycle (GTCC) plant by integration with a methanol steam reforming (MSR) system based on the principle of the cascade utilization of chemical energy. In the integrated MSR-GTCC system, the methanol fuel releases its chemical energy through two successive processes: the thermal reforming reaction of primary fuel in the MSR, and the combustion reaction of reformate syngas in GTCC. The energy required for the endothermic MSR is provided by a portion of mid-temperature heat (MTH), which is extracted from the bottoming cycle of GTCC. By such incorporation, the loss in the conversion from chemical energy to physical energy is reduced and the power generation capability of MTH is improved effectively. Based on a 530 MW GTCC plant, the thermodynamic analysis reveals that the energy and exergy efficiencies are promoted by 7.3 % and 7.2 %, respectively. Besides, the profit of the integrated design is 193.9 M$ higher than that of the conventional system over the lifespan. Furthermore, sensitivity evaluation indicates that the non-reflux MSR process is suitable when the reaction temperature exceeds 250 °C and the optimal water-to-methanol ratio is approximately 1.0 for the integrated MSR-GTCC system.

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.

Feasibility Study of Scheme and Regenerator Parameters for Trinary Power Cycles

Natural gas-fired combined cycle plants are nowadays one of the most efficient and environmentally friendly energy complexes. High energy efficiency and low specific emissions are achieved primarily due to the high average integral temperature of heat supply in the Brayton–Rankine cycle. In this case, the main sources of energy losses are heat losses in the condenser of the steam turbine plant and heat losses with the exhaust gases of the waste heat boiler. This work is related to the analysis of the thermodynamic and economic effects in the transition from binary to trinary cycles, in which, in addition to the gas and steam–water cycles, there is an additional cycle with a low-boiling coolant. A method for the feasibility study of a waste heat recovery unit for trinary plants is proposed. The schematic and design solutions described will ensure the increased energy and economic performance of combined cycle power plants. Based on the results of the thermodynamic optimization of the structure and parameters of thermal schemes, it was found that the use of the organic Rankine cycle with R236ea freon for the utilization of the low-grade heat of a trinary plant’s exhaust gases operating from a GTE-160 gas turbine makes it possible to achieve a net electrical efficiency of 51.3%, which is a 0.4% higher efficiency for a double-circuit combined cycle gas turbine plant and a 2.1% higher efficiency for a single-circuit cycle with similar initial parameters. On the basis of the conducted feasibility study, the parameters and characteristics of the heat exchangers of the regenerative system of the waste heat recovery unit are substantiated. The use of plain fin-and-tube heat exchangers in the regenerative system of the utilization cycle is the most promising solution. It was found that the level of allowable pressure loss in the regenerator of 10 kPa and the degree of regeneration of 80% allow for maximum economic efficiency of the waste heat recovery unit.

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).

A General Overview of Combined Cycle Gas Turbine Plants

The Combined Cycle Gas Turbines (CCGT) has encountered a large diffusion over the last decades. Different researchers have focused on performance evaluation of CCGT through mathematical modeling techniques. Hence, there are some important factors which should be respected while modeling the CCGT. These factors include type of different components of the CCGT system, their configuration, the modeling methods, and the purpose of the modeling, the type and structure of the control system and the simulation objectives. Hence, a brief overview about CCGT design and technologies, mathematical modeling, simulation tools and methods are presented in this paper.

A virtual reality learning platform for steam generators

Virtual reality (VR) has proven to be an effective tool for industrial training, offering immersive and interactive learning experiences. However, it is important to accurately simulate the behavior of the equipment in order to provide realistic training activities to the users. On these premises, the PITSTOP project aims at developing an immersive learning tool, based on the integration of dynamic models and a VR environment. Following this methodology, the first learning platform for industrial-scale steam generators was created. Adopting a mixed physics-based data-driven approach, a fast but accurate dynamic model was developed and calibrated on real data of the auxiliary steam generator of the gas turbine combined cycle plant of Tirreno Power in Vado Ligure, Italy. Accessible through an Oculus Quest VR headset, the platform allows learners to interact with a virtual steam generator and adjust control parameters to observe the effects on the system. In this way, learners can gain a better understanding of steam generation principles and practice problem solving and decision-making skills in a safe, controlled environment. The platform also provides teaching materials and an evaluation mode such that learners can assess their knowledge and estimate the correctness of their actions. This article presents an overview of the VR learning platform, with a focus on the specific features of an industrial scale application. The capabilities of the tool are demonstrated through the recreation of real operational procedures of the Tirreno Power steam generator within the VR platform.

Techno-economic evaluation of combined cycle gas turbine and a diabatic compressed air energy storage integration concept

More and more operational flexibility is required from conventional power plants due to the increasing share of weather-dependent renewable energy sources (RES) generation in the power system. One way to increase power plant's flexibility is integrating it with energy storage. The energy storage facility can be used to minimize ramping or shutdowns and therefore should lower overall generating costs and CO2 emissions.In this article, we examined the effects of a combined cycle gas turbine (CCGT) power plan and a compressed air energy storage (CAES) system integration. The main feature of the CCGT-CAES integration concept is using the CCGT installation as a heat recipient and provider for the CAES installation. This approach was applied to a real-life case study of the PGE Gorzów CCGT power plant. First, technical feasibility of itegrating a CCGT plant with a CAES system was verified and the restrictions on the operating conditions were identified. Next, the improvement in flexibility was quantified by the additional profits gained from the integration. Polish day-ahead electricity prices were used as a measure for remunerating flexibility.Two models were developed in the Python computer programming language: a thermodynamic one and an economic one. The former was buit without the use of flowsheeting software or purpose-built industry specific tool. The latter was implemented within the frame of the PuLP library and solved using its default solver (CBC). By means of mixed integer linear programming (MILP) optimal generation schedules and maximum profits were found for three cases: an independent operation of the CCGT, an integrated CCGT-CAES plant and an integrated CCGT-ES plant with 81% storage efficiency.The results of the computational simulations contradict the supposition that the integration is economically viable, even if mechanical energy storage efficiency of 81% is assumed. Regarding the impact of the integration on the optimal schedule, although it is negligible for the 56% mechanical energy storage efficiency case, a significant change in operation profiles is observed for the 81% case. The model developed here can be used either when making decisions about investment in flexibility improvements or for planning daily operation of a generating unit.

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.

Power-heat conversion coordinated control of combined-cycle gas turbine with thermal energy storage in district heating network

Thermal energy storage, with its low energy storage cost and wide distribution in industrial processes, is an effective way to improve the operational flexibility of power plants. Due to colossal energy storage capacity and small deployment costs, this article proposes connecting district heating networks to combined cycle gas turbine (CCGT) plants as a thermal energy storage capacity, improving the flexibility of CCGTs. The main focus here is on developing an appropriate control strategy to effectively control the power-heat conversion, meet the heat and power demands of the connected network, and the operational flexibility of the plant. The major problem is that the intrinsic static and dynamic conversion relationship of power and heat in the CCGT and district heating network and the buildings are multi-factor interactive and unknown. Therefore, the CCGT bottom cycle and district heating network, and building models were built to obtain the power-heat conversion parameters and the dynamic model for control design. Then, the energy storage coefficient of 0.105 MW/kg/s is obtained through the model simulation instead of a complex thermodynamic calculation, corresponding to the 113.22 GJ energy storage capacity of the district heating network. Based on the obtained conversion rules, a new control strategy called ‘conversion coordinated control’ is designed and applied, using load signal decomposition and synergistic load response of flue gas mass flow rate and steam extraction valve. The simulation results show that the proposed method can promote a ramping load rate of 8.6 MW/min in the first 30 s with only 0.3 °C building temperature variation. The control strategy can effectively reduce the gap between the grid demand and CCGT power and ensure grid stability without compromising thermal users’ comfort.

Techno-economic analysis of combined cycle power plants for electricity generation in Nigeria

This paper presents a techno-economic approach to readily assess the profitability or otherwise of combined cycle power plants (CCPPs) for increased electricity production in Nigeria. As a case study for this analysis, a combined cycle gas turbine plant with 650MW installed capacity at Afam VI power station is used to evaluate the installation of a 1000MW and 1500MW CCPP economically. The results and analysis determined a Levelized cost of electricity of N41.57k/KWh and N34.09k/KWh for the 1500MW and 1000MW CCPP, respectively. It signifies an increase of 33.33% and 66.67% in the cost of electricity per kWh between the 1000MW and 1500MW plant capacities respectively, relative to the 650MW CCPP. Therefore, the low LCOE makes it economically viable to install the 1000MW CCPP for electricity production in the country. The paper also proposes upgrading existing gas-fired power plants in the country into combined cycle power plants for improved electricity supply.

Optimization-based investigation of different repurposing concepts for Austrian coal-fired power plants

Even though the current war in Ukraine has led to a short-time renaissance of coal-fired power plants, the age of coal-based power generation is about to end. Nevertheless, the coal-fired power plants no longer needed for their original purpose are still valuable assets. In this paper, we consider three technological approaches for repurposing them: gas-to-power (operation of combined cycle gas turbine plants), power-to-gas (operation of electrolysis plants for feeding hydrogen into the gas grid), and a combination of the two technologies mentioned above. Our aim is to find optimal operating modes in terms of profit for the three approaches. For this, we use a mixed-integer linear multi-variable optimization model and time-resolved price forecasts for electricity and gas for 2030 and 2040. Our results show that, also in future energy systems, gas-to-power plants allow for economic benefits: In times of district heat demand, they operate in the spot market and profit from dual revenues. Balance and ancillary markets allow for additional revenues from the capacity provision. Power-to-gas plants do not show the same good economic performance. However, they allow for an economically sound operation and gain most of their profits in the spot market. Compared to the others, combined plants do not offer economic advantages. In our paper, we also investigate the currently high energy price situation. It allows for payback periods of power-to-gas plants as anticipated for 2040. For this reason, long-term high prices may accelerate the deployment of such future technologies.

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.

Improvement of Governing Control System Using Fuzzy Logic Controller in a CCGT Plant

In recent decades, there are considerable progressions research in modelling, simulation and control strategies. The advanced technologies in the combined cycle power plants offers more effectiveness and lower environmental effect compared to the conventional systems. Fuzzy logic control is one of the frequently advanced controllers may well improve the performance of the control system in the power plant. This study focuses on the improvement of governing control system by using fuzzy logic controller. Thus, a combined cycle gas turbine plant has been modelled and simulated on MATLAB/Simulink, and a fuzzy logic controller was implemented. The simulation results are compared with that of conventional PID controller tuned by Ziegler Nichols method.

Research and Development of the Combined Cycle Power Plants Working on Supercritical Carbon Dioxide

Today, the use of combined cycle gas turbine (CCGT) plants allows the most efficient conversion of the chemical heat of fossil fuels for generating electric power. In turn, the combined cycle efficiency is largely dependent on the working flow temperature upstream of a gas turbine. Thus, the net electric efficiency of advanced foreign-made CCGT plants can exceed 63%, whereas the net efficiency of domestic combined-cycle power plants is still relatively low. A promising method to increase the heat performance of CCGT plants may be their conversion from a steam heat carrier to a carbon dioxide one. In this paper, we have presented the results of thermodynamic research of a promising combined plant with two carbon dioxide heat recovery circuits based on the GTE-160 gas turbine plant (GTP). We have determined the pressure values that are optimal in terms of the net efficiency upstream and downstream of Brayton cycle turbines using supercritical carbon dioxide with recompression (30 and 8.5 MPa) and base version (38 and 8.0 MPa). The percentage of recompression was 32%. Based on the results of mathematical simulation of heat circuits, we have found out that the use of the solutions suggested allows the increase of the power plant’s net efficiency by 2.4% (up to 51.6%).

Comprehensive economic analysis of PV farm -A case study of Alkarsaah PV farm in qatar

Countries around the world are rapidly deploying renewable energy generation to reduce carbon emissions. Countries in the Gulf Cooperation Council (GCC) are investing heavily in PV generation due to their rich solar resources. As PV technology becomes more mature, future PV developments will largely depend on the cost of the PV generation but there is currently very limited published work that shows a detailed design and in particular the economic analysis of large-scale PV farms. Therefore, this paper uses the Qatar’s first PV farm, the 800MWp Alkarsaah PV farm as a case study to explain the design considerations and especially the economic benefits of large-scale PV farms. Economic comparisons will be made with the most efficient CCGT (combined cycle gas turbine) plants in the network to highlight the economic benefits of PV farms. The results show that the Levelized cost of electricity (LCOE) for this PV farm is 14.03$/MWh, much lower than the LCOE of 39.18$/MWh and 24.6$/MWh from the most efficient CCGTs in the network, highlighting the significant economic benefits of developing PV farms in a low carbon power networks in the future.