Gas-fired Combined Cycle Plants Research Articles

The Iberian exception: Estimating the impact of a cap on gas prices for electricity generation on consumer prices and market dynamics

As the volatility of short-term energy market prices increases due to exogenous shocks and the changing nature of the energy mix, market interventions are gaining importance in the policy debate. Accurate and robust quantification of their impact is becoming therefore essential. This paper conducts a causality analysis to evaluate the Spanish “gas cap” for electricity generation during the 2022 energy crisis. We use Bayesian structural time series models to isolate its impact on affected consumers, primarily those under the regulated tariff, from June to December 2022. Our results show that the mechanism successfully lowered prices compared to a counterfactual scenario without the intervention. However, the policy also led to an increase in electricity generation from gas-fired combined cycle plants. In addition, exports to France increased by over 80% after implementation, as Spanish wholesale prices became cheaper than French prices. Our analysis (1) provides an accurate quantification to date of one of the most consequential energy market interventions in recent years; (2) demonstrates the fruitful use of a novel evaluation method for energy policy; (3) highlights the trade-off between the short-term goal of consumer price relief and the long-term goals of fossil fuel reduction and decarbonisation.

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.

Impact of intermittent renewable energy production on specific CO2 and NOx emissions from large scale gas-fired combined cycles

The growing share of intermittent renewable energy sources in electricity production allows for a significant reduction of the emissions of CO2 and other pollutants from conventional, thermal power plants. As a side effect, it also leads to a noticeable increase of the number of start-ups and fast load transients encountered by those power plants used as back-up units. During such transient phases, the performances of those units in terms of pollutant emissions and thermal efficiency are however degraded, which results in a possible reduction of the environmental benefits of renewables that was not yet quantified. In this study, ten years of process data from a representative, large scale gas-fired combined cycle plant that underwent such a transition are analysed to assess the impact of frequent start-ups and load cycling on its average specific CO2 and NOx emissions (per produced MWhe). While start-up and fast transient phases historically contributed to less than 5% of the produced power, this share now reaches 5−20%. As a consequence of the increased occurrence of such transients, the average specific NOx emissions increase by 30 to 80%, from 140 up to 250 g/MWhe, and the average specific CO2 emissions, less impacted, increase by 2 to 4%, from 335 kg/MWhe up to 350 kg/MWhe. The impact of these findings on the expected reduction of CO2 and NOx emissions attributable to the deployment of renewables is assessed. NOx emissions reduction is significantly lower than expected, due to the increased transient operation of conventional units. For shares of renewable sources lower than 30%, the additional NOx emissions caused by peak demand operation of the thermal units compensate the emissions saved by decreasing their number of operating hours, resulting in a status quo in terms of global NOx emissions for the most optimistic scenario in terms of LCA emissions from renewable sources. For other scenarios, the global NOx emissions even increase for shares of renewables lower than 30%, up to 110% of the initial value (no renewables). As CO2 emissions are much less sensitive to transient phases, the expected CO2 emissions reduction is marginally affected by peak demand operation. Means of reducing both the occurrence of transient phases (at the level of the grid), and the related NOx emission peaks (at the level of the power plants) should be investigated, for a better integration of renewable sources and existing thermal assets.

Comparison of Natural Gas Combined Cycle Power Plants with Post Combustion and Oxyfuel Technology at Different CO2 Capture Rates

Within this work a natural gas-fired combined cycle plant is investigated with post-combustion CO2 capture (PCC) and as a semi-closed oxyfuel combustion combined cycle (SCOC-CC) using process simulation tools. In most studies the CO2 capture rate of PCC units is set to 90% while the SCOC-CC is often considered for zero emission plants. To allow a comparison between the processes the capture rate needs to be taken into account. If a certain CO2 emission value is required a different capture rate may be economically attractive. The effect of the capture rate is investigated from 60% to 97.5% for PCC and from 75% to 100% for the SCOC-CC. For PCC the capture rate has a strong influence on the efficiency penalty. For a broad range of capture rates the specific heat duty is found to be approx. constant. However, for very high capture rates the heat duty strongly increases. The efficiency penalty of the SCOC-CC is much less affected by the chosen capture rate, because the duty of the air separation unit (ASU) is independent on the capture rate. However to achieve a sufficient CO2 purity a reduced capture rate can be necessary.The processes are compared regarding the loss of electrical energy per kg CO2 captured. PCC has a significantly lower specific loss for low capture rates of approx. 0.38 kWhel/kg CO2 compared to the SCOC-CC with more than 0.48 kWhel/kg CO2. For capture rates of > 90% the losses of both processes approach each other. With high purity oxygen the SCOC-CC can achieve a capture rate of 100% as well as a CO2 purity of >96 vol.-% at a specific loss of 0.49 kWhel/kg CO2.

Development of Natural Gas Fired Combined Cycle Plant for Tri-Generation of Power, Cooling and Clean Water Using Waste Heat Recovery: Techno-Economic Analysis

Tri-generation is one of the most efficient ways for maximizing the utilization of available energy. Utilization of waste heat (flue gases) liberated by the Al-Hamra gas turbine power plant is analyzed in this research work for simultaneous production of: (a) electricity by combining steam rankine cycle using heat recovery steam generator (HRSG); (b) clean water by air gap membrane distillation (AGMD) plant; and (c) cooling by single stage vapor absorption chiller (VAC). The flue gases liberated from the gas turbine power cycle is the prime source of energy for the tri-generation system. The heat recovered from condenser of steam cycle and excess heat available at the flue gases are utilized to drive cooling and desalination cycles which are optimized based on the cooling energy demands of the villas. Economic and environmental benefits of the tri-generation system in terms of cost savings and reduction in carbon emissions were analyzed. Energy efficiency of about 82%–85% is achieved by the tri-generation system compared to 50%–52% for combined cycles. Normalized carbon dioxide emission per MW·h is reduced by 51.5% by implementation of waste heat recovery tri-generation system. The tri-generation system has a payback period of 1.38 years with cumulative net present value of $66 million over the project life time.

Optimisation Potentials for the Heat Recovery in a Semi-closed Oxyfuel-combustion Combined Cycle with a Reheat Gas Turbine

Abstract Semi-closed oxyfuel-combustion combined cycle plants are one possibility to realise CCS technologies with natural gas-fired power plants. Due to the recirculation of exhaust gas the working fluid in the gas turbine consists mainly of CO2. This leads to the necessity for an increased pressure ratio to achieve the efficiency and the exhaust gas temperatures of conventional gas turbines. In this work a conventional natural gas-fired combined cycle plant with a reheat gas turbine modified for oxyfuel operation will be presented. As it is assumed that the necessary pressure ratio is not realisable with axial compressors two different scenarios are considered. On the one hand the pressure ratio is the same as in the conventional process and on the other hand the pressure ratio is set to an assumed maximum of 60. The exhaust gas temperature lies significantly above the values of the conventional plant. Generally the higher pressure ratio results in a higher net efficiency of the plant. An unchanged heat recovery process results in a loss of efficiency of at least 9.3 to 10.8%-pts. depending on the pressure ratio. Increasing the steam parameters can achieve a reduction of this loss ranging from 0.5%-pts for the high pressure ratio to 1.0%-pts for the low pressure ratio. An alternative approach for the heat recovery is the application of an internal recuperator in the gas turbine. When the achievable pressure ratio is far from the optimum value, as in the low pressure ratio case, this approach can lead to significantly lower losses of 9.1%-pts. With a higher pressure ratio the effects of the optimisation options are similar.

Evaluation of Post-Combustion CO<sub>2</sub> Capture Technologies

This paper evaluates the results of two recent studies of advanced amine-based, post-combustion CO2 capture plant designs. The first study was conducted by the IEA Greenhouse Gas R&D Programme (IEA GHG), while the second study was conducted by Parsons for the US DOEs National Energy Technology Laboratory (NETL). Fluors improved monoethanolamine (MEA) process, known as the Econamine FG PlusSM technology, is utilised for both studies. Cost and performance estimates for both pulverized coal and natural gas-fired combined cycle plants are summarized. Differences between the design bases and assumptions for the two studies are discussed. The Econamine FG PlusSM technology, as an improved process in amine-based post-combustion CO2 capture described in this paper is leading to lower increases in the cost of electricity (COE). Both the DOE/Parsons and IEA GHG studies show that the increase is now down to 42 to 43% from as high as 60 to 70% indicated from previous studies for PC plants with CO2 capture.

Exergy-based method for analyzing the composition of the electricity cost generated in gas-fired combined cycle plants

The proposed method to analyze the composition of the cost of electricity is based on the energy conversion processes and the destruction of the exergy through the several thermodynamic processes that comprise a combined cycle power plant. The method uses thermoeconomics to evaluate and allocate the cost of exergy throughout the processes, considering costs related to inputs and investment in equipment. Although the concept may be applied to any combined cycle or cogeneration plant, this work develops only the mathematical modeling for three-pressure heat recovery steam generator (HRSG) configurations and total condensation of the produced steam. It is possible to study any n×1 plant configuration (n sets of gas turbine and HRSGs associated to one steam turbine generator and condenser) with the developed model, assuming that every train operates identically and in steady state. The presented model was conceived from a complex configuration of a real power plant, over which variations may be applied in order to adapt it to a defined configuration under study [Borelli SJS. Method for the analysis of the composition of electricity costs in combined cycle thermoelectric power plants. Master in Energy Dissertation, Interdisciplinary Program of Energy, Institute of Eletro-technical and Energy, University of Sao Paulo, Sao Paulo, Brazil, 2005 (in Portuguese)]. The variations and adaptations include, for instance, use of reheat, supplementary firing and partial load operation. It is also possible to undertake sensitivity analysis on geometrical equipment parameters.

Influence of massive heat-pump introduction on the electricity-generation mix and the GHG effect—Belgian case study

To evaluate the environmental impact of massive heat-pump introduction on greenhouse gas (GHG) emissions, dynamic simulations of the overall electricity-generation system have been performed for Belgium. The simulations are carried out with Promix, a tool that models the overall electricity-generation system. For comparison, three heating devices are considered, namely conventional boilers, heat pumps and electrical resistance heating. The introduction of electric heating at the expense of classic heating increases the demand for electricity and generates a shift of emissions from fossil-fuel heating systems to electrical power plants. The replaced classic fossil-fuel-fired heating represents emissions of about 300 kton. With regard to the heat-pump scenarios, both direct heat-pump heating with a coefficient of performance (COP) of 2.5 and accumulation heat-pump heating with a COP of 5 are investigated. The results of the simulations reveal that the massive introduction of heat-pump heating is favourable to the environment. In Belgium, the largest reductions in GHG emissions occur with heat pumps for direct heating, combined with newly commissioned combined cycle (CC) gas-fired plants or with accumulation heat-pump heating. These scenarios bring about overall GHG emission reductions of approximately 200 kton compared with the reference case with conventional heating for the years 2000 and 2010. The amount of additional electricity-related emissions depends on the considered heating device. In 2010, the scenario with accumulation heat pumps results in an overall decrease of Belgian GHG emissions by 0.15% compared with the reference scenario. The expansion of the electricity-generation system with new CC plants has an important favourable impact on GHGs as well. In most cases, the combination of higher electricity demand and the construction of new gas-fired CC plants will lead to lower overall GHG emissions. Copyright © 2007 John Wiley & Sons, Ltd.

Life cycle assessment study of solar PV systems: An example of a 2.7 kW p distributed solar PV system in Singapore

In life cycle assessment (LCA) of solar PV systems, energy pay back time (EPBT) is the commonly used indicator to justify its primary energy use. However, EPBT is a function of competing energy sources with which electricity from solar PV is compared, and amount of electricity generated from the solar PV system which varies with local irradiation and ambient conditions. Therefore, it is more appropriate to use site-specific EPBT for major decision-making in power generation planning. LCA and life cycle cost analysis are performed for a distributed 2.7 kW p grid-connected mono-crystalline solar PV system operating in Singapore. This paper presents various EPBT analyses of the solar PV system with reference to a fuel oil-fired steam turbine and their greenhouse gas (GHG) emissions and costs are also compared. The study reveals that GHG emission from electricity generation from the solar PV system is less than one-fourth that from an oil-fired steam turbine plant and one-half that from a gas-fired combined cycle plant. However, the cost of electricity is about five to seven times higher than that from the oil or gas fired power plant. The environmental uncertainties of the solar PV system are also critically reviewed and presented.

A novel methodology for comparing CO 2 capture options for natural gas-fired combined cycle plants

Three concepts for capturing CO 2 from natural gas-fired combined gas/steam turbine power plants are evaluated and compared in this paper: (A) separation of CO 2 from exhaust gas coming from a standard gas turbine power plant, using chemical absorption by amine solutions. (B) Gas turbine combined cycle (CC) using a semi-closed gas turbine with near to stoichiometric combustion using oxygen from an air separation unit as an oxidizing agent. This produces CO 2 and water vapour as the combustion products. The gas turbine working fluid is mainly CO 2. (C) Decarbonization, which comprises an autothermal reforming reactor with air-blown catalytic partial oxidation of gas natural gas, a water-shift reaction and a high-pressure CO 2 capture process. The hydrogen-rich reformed fuel gas is combusted in a gas turbine CC, which is integrated (air, steam and heat) with the decarbonization process. A novel method is presented that compares power plant concepts including CO 2. Instead of using extensive thermodynamic calculations for these concepts, reaction equations for the conservation of molecular species together with specific energy consumption numbers for the different process sections are used to characterize the concepts with respect to fuel-to-electricity conversion efficiency. With a combined gas/steam turbine power plant giving 58% total fuel-to-electricity conversion efficiencies (no CO 2 capture), calculations for the concepts with CO 2 capture including CO 2 compression gave: (A) 49.6%; (B) 47.2%; and (C) 45.3%. The mechanisms leading to a reduced efficiency for concepts A–C are discussed and quantified and compared to combined gas/steam turbine with no capture of CO 2.