Search Results (12)

Recognizing the growing importance of natural gas as a transition fuel in Poland’s energy mix and the necessity of reducing CO₂ emissions, this article aims to assess the use of carbon capture and storage (CCS) technology to effectively reduce CO₂ emissions from combined cycle gas turbine (CCGT). The research employs the pressure–temperature swing adsorption (PTSA) to capture CO₂ from flue gases. Computer simulations, using IPSEpro (SimTech), are used to calculate the heat and mass balances for CCGT and PTSA units and assess their performance. In the first part of the research, the effect of sorbent type (Na-A and 5A) and flue gas share directed to the PTSA unit on the performance of the CCGT was investigated. Secondly, the parametric analysis regarding the adsorption and desorption pressures in the PTSA was carried out. The results showed that CO₂ emissions from CCGT can be reduced by 1.1 Mt (megatons) per year, but the use of PTSA was associated with a reduction in net electrical power and efficiency of the CCGT by up to 14.7% for Na-A and 11.1% for 5A sorbent. It was also found that the heat and electricity demand of the PTSA depends on the adsorption and desorption pressures. Full article

With the increase in the amount of new energy in new power systems, the response speed of power demand changes in combined cycle gas turbines (CCGTs) is facing new challenges. This paper studies an integrated operation strategy for the coupled molten salt energy storage of CCGT systems, and analyzes the system through simulation calculation. The advantages of the coupled system are determined by comparing the electrical output regulation capability, thermoelectric ratio, gas consumption rate, and peaking capacity ratio. In addition, using stored energy to maintain the temperature of the heat recovery steam generator (HRSG) can shorten the system’s restart time, improve the unit’s operating efficiency, and reduce the start-up cost. Our findings can be used as a reference for accelerating the performance improvement of CCGT systems, which is also crucial in technologies for waste heat recovery, molten salt energy storage technology, and promoting the sustainable development of energy systems. Full article

Today, most of the world’s electric energy is generated by burning hydrocarbon fuels, which causes significant emissions of harmful substances into the atmosphere by thermal power plants. In world practice, flue gas cleaning systems for removing nitrogen oxides, sulfur, and ash are successfully used at power facilities but reducing carbon dioxide emissions at thermal power plants is still difficult for technical and economic reasons. Thus, the introduction of carbon dioxide capture systems at modern power plants is accompanied by a decrease in net efficiency by 8–12%, which determines the high relevance of developing methods for increasing the energy efficiency of modern environmentally friendly power units. This paper presents the results of the development and study of the process flow charts of binary and trinary combined-cycle gas turbines with minimal emissions of harmful substances into the atmosphere. This research revealed that the net efficiency rate of a binary CCGT with integrated post-combustion technology capture is 39.10%; for a binary CCGT with integrated pre-combustion technology capture it is 40.26%; a trinary CCGT with integrated post-combustion technology capture is 40.35%; and for a trinary combined-cycle gas turbine with integrated pre-combustion technology capture it is 41.62%. The highest efficiency of a trinary CCGT with integrated pre-combustion technology capture is due to a reduction in the energy costs for carbon dioxide capture by 5.67 MW—compared to combined-cycle plants with integrated post-combustion technology capture—as well as an increase in the efficiency of the steam–water circuit of the combined-cycle plant by 3.09% relative to binary cycles. Full article

Since retrofitting existing natural gas-fired (NGF) power plants is an essential strategy for enhancing their efficiency and controlling greenhouse gas emissions, this paper compares the carbon footprint of natural gas-fired power generation from an NGF power plant in Brazil (BR-NGF) with and without retrofitting. The former scenario entails retrofitting the BR-NGF power plant with combined-cycle gas turbine (CCGT) technology. In contrast, the latter involves continuing the BR-NGF power plant operation with open-cycle gas turbine (OCGT) technology. Our analysis considers the BR-NGF power plant’s life cycle (construction, operation, and decommissioning) and the natural gas’ life cycle (natural gas extraction and processing, liquefaction, liquefied natural gas transportation, regasification, and combustion). Moreover, it is based on data from primary and secondary sources, mainly the Ecoinvent database and the ReCiPe 2016 method. For OCGT, the results showed that the BR-NGF power plant and the natural gas life cycles are responsible for 620.87 gCO₂eq./kWh and 178.58 gCO₂eq./kWh, respectively. For CCGT, these values are 450.04 gCO₂eq./kWh and 129.30 gCO₂eq./kWh. Our findings highlight the relevance of the natural gas’ life cycle, signaling additional opportunities for reducing the overall carbon footprint of natural gas-fired power generation. Full article

Amidst the global energy crisis in 2022, the Spanish and Portuguese governments introduced a subsidy to natural gas (“the Iberian exception”), attempting to lower the wholesale electricity market prices, with the understanding that gas-fired-combined cycle gas turbines (CCGTs) are price-setting technologies most of the time, directly or indirectly. The subsidy succeeded in lowering the market price but induced several other effects, such as (1) the increase in cleared energy in the Spanish market (mostly produced with gas), (2) the bias in the import/export cross-border position between Spain and France (Spain became a net exporter to France immediately), or (3) the consequent increase in congestion rents, which serve to lightly finance the subsidy, among other effects. This paper provides a framework for clustering the different effects based on the market participation phases: the subsidy, the market bidding, the market results, and surplus and rents. Moreover, this paper builds on the theoretical market models, with and without subsidies, and with and without cross-border exchanges. Based on the real market bids, the subsidies, and the generators’ data, we reconstruct the supply and demand curves and simulate the counterfactual market scenarios in order to illustrate and quantify the effects. We highlight the quantification of the theoretical effect of the transfer of rents, from non-fossil to fossil fuel producers, induced by the gas subsidy. Full article

Energy price fluctuations pose a significant risk and uncertainty to financial investments for new developments in conventional power and freshwater cogeneration facilities. This study attempts to address the problem of making robust valuation for low-carbon energy project investments subject to multi-dimensional price risk, particularly looking at some key research questions: (a) how does the correlation structure, or independence, between the price risks affect the project value; and (b) does adding flexibility in investment enhance or worsen the project valuation, given (a). This study identified three price factors with significant fluctuations that impact conventional power generation, namely: wholesale electricity spot price, natural gas spot price, and CO₂ market price. The price factors were used to construct a multidimensional risk model and evaluate investment decisions for cogeneration project expansion in the future based on a low-carbon energy mix. To this end, five cogeneration configurations using combined-cycle gas turbine (CCGT) integrated with solar photovoltaics (PV) and carbon capture and storage (CCS) technologies were assessed. A combined price risk was initially estimated by transforming the given price factors representing maximum covariance using principal component analysis (PCA). The trend and volatilities in the major principal component scores (the combined price risk indicator) were modelled using the geometric Brownian motion stochastic process, whose parameters were determined and then used to perform time-series simulation and generate multiple realisations of the principal component. A back transformation was then applied to obtain the simulated values representing future uncertainties in the price factors. The effect of price risk and uncertainties were subsequently evaluated using a recombining binomial lattice model for real options analysis (ROA). There were financial gains when PV was mixed with conventional natural gas-fired technology. Investment in cogeneration configurations with (a) 25% PV share provided a 53% gain in the extended net present value (e–NPV); and (b) 50% PV share provided a 124% e–NPV gain when compared to the baseline cogeneration system with no PV shares. The analyses demonstrate that PV technology is a better hedging option than CCS against future market uncertainty and price volatility. Full article

Hydrogen is expected to play an important role in renewable power storage and the decarbonization of the power sector. In order to clarify the environmental impacts of power regenerated through hydrogen-fueled gas turbines, this work details a life cycle model of the greenhouse gas (GHG) and NOx emissions of the power regenerated by power-to-H₂-to-power (PHP) technology integrated with a combined cycle gas turbine (CCGT). This work evaluates the influences of several variables on the life cycle of GHG and NOx emissions, including renewable power sources, hydrogen production efficiency, net CCGT efficiency, equivalent operating hours (EOH), and plant scale. The results show that renewable power sources, net CCGT efficiency, and hydrogen production efficiency are the dominant variables, while EOH and plant scale are the minor factors. The results point out the direction for performance improvement in the future. This work also quantifies the life cycle of GHG and NOx emissions of power regenerated under current and future scenarios. For hydro, photovoltaic (PV) and wind power, the life cycle of the GHG emissions of regenerated power varies from 8.8 to 366.1 g_CO2e/kWh and that of NOx emissions varies from 0.06 to 2.29 g/kWh. The power regenerated from hydro and wind power always has significant advantages over coal and gas power in terms of GHG and NOx emissions. The power regenerated from PV power has a small advantage over gas power in terms of GHG emissions, but does not have advantages regarding NOx emissions. Preference should be given to storing hydro and wind power, followed by PV power. For biomass power with or without CO₂ capture and storage (CCS), the life cycle of the GHG emissions of regenerated power ranges from 555.2 to 653.5 and from −2385.0 to −1814.4, respectively, in g_CO2e/kWh; meanwhile, the life cycle of NOx emissions ranges from 1.61 to 4.65 g/kWh, being greater than that of coal and gas power. Biomass power with CCS is the only power resource that can achieve a negative life cycle for GHG emissions. This work reveals that hydrogen-fueled gas turbines are an important, environmentally friendly technology. It also helps in decision making for grid operation and management. Full article

Whilst various new technologies for power generation are continuously being evaluated, the owners of almost-new facilities, such as combined-cycle gas turbine (CCGT) plants, remain motivated to adapt these to new circumstances and avoid the balance-sheet financial impairments of underutilization. Not only are the owners reluctant to decommission the legacy CCGT assets, but system operators value the inertia and flexibilities they contribute to a system becoming predominated with renewable generation. This analysis therefore focuses on the reinvestment cases for adapting CCGT to hydrogen (H₂), synthetic natural gas (SNG) and/or retrofitted carbon capture and utilization systems (CCUS). Although H₂, either by itself or as part of SNG, has been evaluated attractively for longer-term electricity storage, the business case for how it can be part of a hybrid legacy CCGT system has not been analyzed in a market context. This work compares the power to synthetic natural gas to power (PSNGP) adaptation with the simpler and less expensive power to hydrogen to power (P2HP) adaptation. Both the P2HP and PSNGP configurations are effective in terms of decarbonizations. The best results of the feasibility analysis for a UK application with low CCGT load factors (around 31%) were obtained for 100% H₂ (P2HP) in the lower range of wholesale electricity prices (less than 178 GBP/MWh), but in the higher range of prices, it would be preferable to use the PSNGP configuration with a low proportion of SNG (25%). If the CCGT load factor increased to 55% (the medium scenario), the breakeven profitability point between P2HP and PSNGP decreased to a market price of 145 GBP/MWh. Alternatively, with the higher load factors (above 77%), satisfactory results were obtained for PSNGP using 50% SNG if with market prices above 185 GBP/MWh. Full article

The paper analyzes the main issues of power market development for clean energy production within the broader framework of ensuring the country’s energy security. In addition, special attention is paid to the technologies aimed at reducing emissions of toxic substances and greenhouse gases by the fossil-fired power plants. Even though the future electricity markets would most likely depend on the high shares of renewable energy sources (RES) in the electricity system, energy efficiency such as the one based on the near-zero emission technologies might also play a crucial role in the transition to the carbon-free energy future. In particular, there are the oxy-fuel combustion technologies that might help to reduce the proportion of unburned fuel and increase the efficiency of the power plant while reducing the emissions of flue gases. Our paper focuses on the role and the place of the near-zero emission technologies in the production of clean energy. We applied economic and mathematical models for assessing the prospects for applying oxy-fuel combustion technology in thermal power plants, taking into account the system of emission quotas and changes in the fuel cost. Our results demonstrate that at the current fuel prices, it is advisable to use economical combined cycle gas turbines (CCGT). At the same time, when quotas for greenhouse gas emissions are introduced and fuel costs increase by 1.3 times, it becomes economically feasible to use the oxy-fuel combustion technology which possesses significant economic advantages over CCGT with respect to the capture and storage of greenhouse gases. Full article

This paper presents an attempt to the valuation of the operational flexibility of the energy investment project based on the example of combined cycle gas turbine (CCGT). For this purpose, the real options approach (ROA), net present value (NPV) method, and the Monte Carlo (MC) simulation have been used. Motivations to take up such a topic result from the fact that traditional valuation methods neglect flexibility embedded in CCGT assets. Operational flexibility was defined as the switching option to dynamically shut down and restart gas units. Valuation of the operational flexibility, the project’s extended net present value (XNPV), was based on a discounted cash flow model. The Monte Carlo simulation, allowing for better replication of the stochastic nature of market factors and some technical parameters, was introduced to the valuation model. The obtained results indicate that the value of the options significantly influences the NPV of the analyzed technology and its risk profile. The NPV was calculated at −169.1 million USD, while the XNPV amounted to 102.5 million USD. This difference, compared to the NPV distribution range at a significance level of 0.05, was more than 8.1% (almost 10.4% for α = 0.1). The results achieved help to explain the significance of the operational flexibility in the modeling profitability of CCGT technologies. Full article

Power systems require a certain amount of flexibility to meet varying demand and to be able to cope with unexpected events, and this requirement is expected to increase with the emergence of variable power generation. In this paper, we focus on gas engine power plant technology and the beneficial influence its flexible operation can have on a power system. The study introduces the concept of a combined-cycle gas engine power plant (CCGE), which comprises a combination of several gas-fired combustion engines and a steam turbine. The operation of CCGE is then comprehensively analyzed in electricity and reserve production in the South African power system and compared with combined-cycle gas turbine (CCGT) technology. Even though CCGE is a form of technology that has already been commercialized, it is rarely considered as a source of flexibility in the academic research. That is the notion providing the motivation for this study. Our core contribution is to show that the flexibility of CCGE can be valuable in power systems. The methodology is based on the unit-level model of the studied system and the solving of a day-ahead unit commitment problem for each day of the simulated 11-year period. The simulation studies reveal how a CCGE is able to offer system flexibility to follow hourly load variations and capacity to provide reserve power effectively. Full article

CO₂ captured from fossil-fueled power generation plants is said to be economically transported via pipelines over long distances. The CO₂ must be compressed to pipeline specifications using compressors and pumps that are driven by gas turbine (GT) or other prime movers. This paper presents the evaluation of actual work transfer or required prime power by modeling the governing equations of compression using the Peng–Robinson equation of state (PR-EOS). A computer code was developed to carry out the modeling and subsequent simulation of the compression power requirement. The simulation of prime mover power was carried out for different technology (head per stage) of the compressor ranging from 10-staged compression to double stage compression. The results show that the current technology of the centrifugal compressor could require as much as 23MW of prime mover power to compress 1.5 million tonnes per year of CO₂—a projected equivalent CO₂ released from a 530MW combined cycle gas turbine (CCGT) power generation plant. Full article