Natural Gas-fired Combined Cycle Power Research Articles

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Thermoexergetic analysis and response optimisation of selective exhaust gas recirculation with solvent-based CO2 capture in a natural gas-fired combined cycle power plant

Advancing power plant decarbonization with a flexible hybrid carbon capture system

Carbon dioxide capturing from natural gas-fired power plants is challenging due to high flow rate and the low carbon dioxide concentration of flue gas. This is an emerging field where many concepts and scientific principles are still in development. In this paper, a novel design is proposed for decarbonizing a natural gas-fired combined cycle power plant using a solar-assisted hybrid membrane-amine carbon capture and storage system. The design incorporates a solar field with thermal energy storage integrated with the capture plant reboiler along with multi-stage carbon dioxide selective membrane modules for selective exhaust gas recirculation (SEGR) combined with exhaust gas recirculation (EGR) to increase the concentration of Carbon dioxide in the flue gas. It is hypothesized that the proposed design could enhance the performance of the power plant integrated with carbon capture in terms of flexibility and sustainability. In this regard, a comprehensive process modeling and simulation framework is developed to accurately investigate the interactions between different components of the integrated process. The results show that the carbon dioxide concentration in the flue gas increases from 3.9 mol% in the conventional power plant to 10.87 mol% in the EGR + SEGR case (26 % of flue gas to EGR and 50 % to SEGR) and increases to 18.08 mol% by the SEGR case (76 % of flue gas to SEGR). Solar thermal energy is an efficient solution for reducing or eliminating the need for steam extraction for the stripper reboiler, resulting in a significant increase in net power output compared to the non-solar cases. The proposed designs lead to a 19.4 % increase in system power output in the SEGR case and a 13.8 % increase in the EGR + SEGR case compared to the baseline case. Also, the specific reboiler duty and required packing material volume in the absorber and stripper are significantly improved in the proposed designs. Moreover, the power plant carbon intensity in the proposed designs can be reduced by up to 10.3 %. The EGR + SEGR case offers an optimal solution as it requires a significantly smaller membrane area, approximately 71 % smaller membrane area compared to SEGR. The proposed designs and analysis have the potential to contribute significantly to the decarbonization of fossil-fueled power plants and enhance the sustainability and flexibility of the power sector.

Energy analysis of novel hybrid solar and natural gas combined cycle plants

The integration of renewable energy sources into standard energy systems is a fundamental step in the energy transition. The purpose of the paper is to investigate the integration of solar energy into a traditional natural gas-fired combined cycle power plant, while also evaluating the impact of intercooling, in terms of energy efficiency and CO2 emissions. Solar energy is integrated into the gas turbine topping cycle through parabolic trough collectors, with the aim of preheating the air leaving the compressor. Two additional configurations have been compared, based on one- and two-stage intercooled compression. The goal is to find the optimal hybrid configuration. To this purpose, a thermodynamic analysis of the overall plant has been performed, and a numerical model has been specifically developed to simulate the solar field. The model has been integrated into Thermoflex™ to simulate the overall combined cycle. Solar-to-electric conversion efficiency, based on solar energy input alone, has received specific attention to make relevant comparisons with conventional concentrated solar based power plants. Furthermore, net electric efficiency, electrical power share due to solar energy integration, natural gas savings, and CO2 emissions have been investigated. The solar-to-electric conversion efficiency has been shown to increase with the compression ratio while the net electric efficiency decreases. To achieve a trade-off between the need for high net electric efficiency and high solar integration, an optimization based on the Pareto front was carried out. The selected configuration consists of one intercooling stage and a compression ratio of 17.9, resulting in a solar conversion efficiency of 33%, which is much better than traditional solar-only power plants. Additionally, the net electric efficiency is 69.5%. To test this configuration under actual operating conditions, a one-year simulation was carried out in two cities with different climates: Messina and Torino. An average annual solar-to-electric efficiency of around 32% can be achieved in both cities, with natural gas savings of 7.7% and 5.8% per year for Messina and Torino, respectively.

Reserve provision of combined-cycle unit in joint day-ahead energy and reserve markets

With the continuous development of natural gas-fired combined cycle power generation technology, the combined cycle (CC) unit's installed capacity is gradually increasing in the power system because of its flexible operation characteristics. Participating in the energy and reserve markets and taking advantage of flexible mode transfer characteristics, the CC unit can provide the system with energy and sufficient reserve capacity. This paper proposes a bi-level strategic bidding model to study the CC unit’s bidding behavior in the day-ahead energy and reserve markets. The upper-level model is an optimal bidding model for the configuration-based CC unit aiming to maximize its profit. The lower-level model is the joint market clearing model of the energy and reserve markets managed by the independent system operator (ISO). CC unit and ISO in this model influence each other by the locational marginal electricity prices (LMEP) and the locational marginal reserve prices (LMRP) obtained from the lower-level market-clearing model. The CC unit submits the bids to the ISO and arranges the generation plan according to the market clearing results of the lower-level market-clearing model carried out by the ISO. The proposed bi-level optimization model is transformed into a mathematical equilibrium constraint (MPEC) problem by Karush-Kuhn-Tucker (KKT) conditions and duality theory. In this paper, the improved IEEE-6 bus and IEEE-57 bus systems are used as case studies to verify the effectiveness of the proposed bidding strategy for the CC unit. The results show that the proposed bidding strategy can effectively improve the profits of the CC unit in the electricity market. Compared with the case of the CC unit only participating in the energy market, the profits of the CC unit in the market increased by 8.84% and 12.3%.

Experimental study on CO2 separation using hydrophobic deep eutectic solvent based supported liquid membranes

Deep eutectic solvents (DESs) have been proposed as a viable and more sustainable solvent for CO2 capture, owing to their low volatility and tunable properties. In this work, polymer membranes were combined with hydrophobic DESs to prepare supported liquid membranes (DES-SLMs), and the potential of using SLMs for CO2/N2 separation was investigated. COSMO-RS model simulations, bond energy analysis as well as stability tests were used to select the polymeric porous support. Hydrophobic polyvinylidene fluoride (PVDF) with a nominal pore size of 0.1 μm was chosen to support three selected hydrophobic DESs. The gas permeabilities through three selected DES-SLMs were experimentally determined, where the thymol-coumarin (1:1) based SLM showed the best performance with a CO2 permeability of 175.0 Barrer and selectivity of 30.2 at room temperature. The separation capability was further improved by mixing the DES with traditional physical absorbents. In addition, the effects of water presence in the gas phase on the DES-SLM were investigated. The membrane was physically stable, but the ideal selectivity of CO2/N2 through the membrane deteriorated with time on steam. By predicting the permeabilities of CO2 and N2 through traditional organic liquid based SLMs, the prospects of developing DESs for SLM applications were demonstrated. Finally, an advanced membrane capture process for a natural gas-fired combined cycle (NGCC) power plant was studied with process simulation and economic analysis, where the SLMs are used to purify the CO2 product.

Prediction of NOx emissions from gas turbines of a combined cycle power plant using an ANFIS model optimized by GA

Combined cycle power plants, which combine gas and steam turbines, have negative impacts on surrounding populations and structures. Control of NOx emissions is an important issue for these gas-fired power plants. Accurate estimation of NOx emissions is critical for developing incinerators and reducing the environmental impact of existing plants. The objective of this study is to model ANFISGA and estimate NOx emissions from a natural gas-fired combined cycle power plant using emission monitoring system (PEMS) data. First, Adaptive Neuro Fuzzy Inference System (ANFIS) models were developed using fuzzy C-Means (FCM). Then, the parameters were optimized using a genetic algorithm (GA) to reduce the error. The proposed ANFISGA system was created, trained, and tested with PEMS datasets. The developed models were compared using several statistical performance criteria, including correlation coefficient (R2), mean squared error (MSE), error mean (EM), root mean square error (RMSE), standard deviation of error (STD), and mean absolute percentage error (MAPE). The obtained results show that the coefficient of determination varies between 0.79933 and 0.90363 for the data separated into test and training data with different rates. The minimum values of the criteria MSE, RMSE, EM, STD, and MAPE were found to be 24.8379, 4.9838, 3.4625e-05, 4.9839, and 5.1660, respectively, for the training data. The minimum values of these criteria for the test data were 26.5961, 5.1571, 0.065696, 5.157, and 5.3695, respectively. The collected results show that the proposed ANFISGA models have high potential for NOx prediction. Thus, the results show that GA has a great impact on the performance of ANFIS training and significantly improves the predictive accuracy of the model.

Prediction of de-NOx performance using monolithic SCR catalyst under load following operation of natural gas-fired combined cycle power plants

As variable renewable energy expands, natural gas-fired combined cycle (NGCC) power plants are expected to provide important functions for grid stabilization such as quick start-up, shutdown, and load following. However, transient operation of NGCC significantly increases the NO2 content of NOX in the exhaust gas and reduces de-NOx performance of selective catalytic reduction (SCR) with ammonia injection. The denitrification performance of SCR depends on transient mechanisms such as adsorption of ammonia in the catalyst and redox reactions on the catalyst surface. This study evaluates whether de-NOX performance can be maintained during expected operational fluctuations for grids with a high penetration of variable renewable energy. Simulations involving a modified de-NOX reaction scheme have been developed and validated for various NGCC exhaust gas compositions expected in both steady state and transient operation using a commercial, monolithic SCR catalyst. Results show that sudden output load changes cause a decrease in SCR catalyst performance due to changes in gas composition and temperature outpacing the adsorption/desorption of ammonia in the catalyst. It was found that adjusting the injection amount of ammonia several minutes prior to the output load change was effective in maintaining de-NOX performance.

Kinetic model of SCR catalyst-based de-NOx reactions including surface oxidation by NO<sub>2</sub> for natural gas-fired combined cycle power plants

Kinetic model of SCR catalyst-based de-NOx reactions including surface oxidation by NO<sub>2</sub> for natural gas-fired combined cycle power plants

Assessing the potential of molten carbonate fuel cell-based schemes for carbon capture in natural gas-fired combined cycle power plants

This work explores two configurations of natural gas-fired combined cycles (NGCC) with molten carbonate fuel cells (MCFC) for CO2 capture. Special attention is devoted to the selection of MCFC operating conditions (trade-off between CO2 capture and voltage losses), heat integration scheme, fuel use and CO2 purification. Two schemes are considered: (i) in the first “integrated” scheme, MCFC modules are installed between the gas turbine and the heat recovery steam generator (HRSG) to maximize the efficiency of the integrated power plant; (ii) in the second “non-integrated” layout, the MCFC is located downstream of the HRSG and a regenerative heat exchanger is designed to preheat cathode reactants up to the MCFC working temperature. This study includes a full techno-economic analysis of the two layouts based on a preliminary sizing of the key-components, and a sensitivity analysis on the CO2 utilization factor. Compared to a benchmark amine scrubbing process, the “integrated” configuration shows considerably better performance (Specific Primary Energy Consumption for CO2 Avoided - SPECCA = 0.31 MJ kgCO2-1; Cost of CO2 avoided - CCA = 50 $ tCO2−1), whereas the “non-integrated” solution shows higher energy penalties but similar CO2 avoidance cost (SPECCA = 2.4 MJ kgCO2−1; CCA = 76 $ tCO2−1).

Advancing CO2 Capture from Natural Gas Combined Cycle Power Plants with Piperazine Scrubbing

Carbon dioxide capture and storage is widely recognized as an essential technology for limiting the global temperature rise to 2 °C by the end of the century. Technology development efforts so far focus on coal-fired power plants and other industrial sources with relatively high CO2 partial pressures. However, natural gas is increasingly used in power generation because of its abundance and low greenhouse gas impacts among the fossil fuels. For deep decarbonization that is required in the future, fossil fuels with CCS continue to play a relevant role in scenarios that balance cost of energy with climate impacts. Carbon capture from natural gas sources has been an ongoing interest to CO2 Capture Project (CCP) and its members from the oil and gas industry. This paper describes the work related to solvent-based natural gas carbon capture sponsored by CCP and pilot studies performed in collaboration with University of Texas at Austin researchers. The collaboration with University of Texas at Austin (UT) is aimed at demonstrating the application of an aqueous piperazine solution-a second-generation solvent-in a pilot plant. The goal is to test CO2 separation from synthetic flue gas representative of the exhausts from natural gas-fired combined cycle power plant (i.e. ~4 mol% CO2). The low CO2 concentration in NGCC flue gas is considered to be a challenge for many capture technologies. This work tested the performance of 5m piperazine in the UT pilot plant at a range of operating conditions, including solvent loadings, gas and liquid flow rates, assessing two different absorber configurations. High CO2 capture rates above 90% were confirmed. The pilot test results were used to verify and extend the range of applicability of the thermodynamic model developed by UT. This work increases the confidence for the application of the process models to design CCS processes for low CO2 concentrations. The model’s predictions of the pilot plant tests at low concentrations are now as accurate and reliable as those for higher CO2 concentrations where much of the data have been collected until now. Further pilot tests at NCCC are being designed to supplement the model evaluation data set for NGCC flue gas as well as to address questions related to oxidation/corrosion and cooling scheme optimization for NGCC applications.

Influence of various carbon capture technologies on the performance of natural gas-fired combined cycle power plants

Carbon capture and storage (CCS) technology has been studied actively in recent years to address global warming. This paper aimed to make a consistent comparison of different capture technologies applied to the natural gas-fired combined cycle (NGCC). Multiple power plant systems based on a standard NGCC using three different carbon capture technologies (post-combustion, pre-combustion, and oxycombustion) were proposed, and their net performance was compared. The optimal pressure ratio of the oxy-combustion technology system was obtained. The variations in the net cycle performance of the three systems were compared using the specific CO2 capture. The net power of the post-combustion capture scheme is lower than that of all other systems, but it has the highest efficiency. However, its biggest disadvantage is a much lower CO2 capture rate than the oxy-combustion capture which exhibits nearly 100 % capture rate. The conclusion is that the oxy-combustion capture would provide both the highest net efficiency and power output if a high capture rate of over 92 % was required.

ION 6-Month Campaign at TCM with its Low-Aqueous Capture Solvent Removing CO2 from Natural Gas Fired and Residue Fluid Catalytic Cracker Flue Gases

ION Engineering’s (ION) advanced solvent is one of the leading second-generation solvent systems currently under development for post-combustion carbon dioxide (CO2) capture. This paper discusses the results obtained at CO2 Technology Centre Mongstad (TCM) in Mongstad, Norway between September 2016 and April 2017, where ION captured over 14,800 tonnes of CO2 throughout the 2,775-hour testing campaign. The testing was done on flue gases from a natural gas-fired combined cycle heat and power facility (CHP) and a residue fluid catalytic cracker (RFCC) from the adjacent Statoil refinery at a scale comparable to 12 MWe. The CO2 concentrations in both flue gas types could be varied using recycle from the stripper or dilution by air. In this work, CO2 concentration settings of between 3.6% and 15.0% were tested. In the TCM plant, which is not optimized for ION’s solvent system, ION achieved a specific reboiler duty (SRD) as low as 3.2 MJ/kg CO2 during the testing at TCM while demonstrating 90% capture efficiency with low emissions and low corrosion. Furthermore, testing showed capturing 98% of the CO2 with ION’s solvent results in only a 10% increase in energy consumption. The results from ION’s campaign at TCM were then used to validate the ION process model in ProTreat® to high accuracy. Subsequent process design optimization shows ION’s solvent is capable of an SRD of less than 2.5 MJ/kg CO2 when incorporating ION’s key process operations. Throughout pilot testing, ION has confirmed its understanding of process improvements and analytics that will enable successful operation of its solvent system at significantly lower L/G circulation rates, packing heights, and regeneration energies than baseline mono-ethanolamine. ION anticipates that the recently completed demonstration at TCM, along with future projects, will facilitate further advancements in the field of CO2 capture and deployment of ION’s technology.

Coefficient determination of reaction rate equations over SCR catalyst used for deNOx system of natural gas-fired gas turbine combined cycle power plants

Coefficient determination of reaction rate equations over SCR catalyst used for deNOx system of natural gas-fired gas turbine combined cycle power plants

CO2 capture from natural gas combined cycles by CO2 selective membranes

This paper performs a techno-economic analysis of natural gas-fired combined cycle (NGCC) power plants integrated with CO2 selective membranes for post-combustion CO2 capture. The configuration assessed is based on a two-membrane system: a CO2 capture membrane that separates the CO2 for final sequestration and a CO2 recycle membrane that selectively recycles CO2 to the gas turbine compressor inlet in order to increase the CO2 concentration in the gas turbine flue gas. Three different membrane technologies with different permeability and selectivity have been investigated. The mass and energy balances are calculated by integrating a power plant model, a membrane model and a CO2 purification unit model. An economic model is then used to estimate the cost of electricity and of CO2 avoided. A sensitivity analysis on the main process parameters and economic assumptions is also performed. It was found that a combination of a high permeability membrane with moderate selectivity as a recycle membrane and a very high selectivity membrane with high permeability used for the capture membrane resulted in the lowest CO2 avoided cost of 75US$/tCO2. This plant features a feed pressure of 1.5bar and a permeate pressure of 0.2bar for the capture membrane. This result suggests that membrane systems can be competitive for CO2 capture from NGCC power plants when compared with MEA absorption. However, to achieve significant advantages with respect to benchmark MEA capture, better membrane permeability and lower costs are needed with respect to the state of the art technology. In addition, due to the selective recycle, the gas turbine operates with a working fluid highly enriched with CO2. This requires redesigning gas turbine components, which may represent a major challenge for commercial deployment.

Performance of polyethyleneimine–silica adsorbent for post-combustion CO2 capture in a bubbling fluidized bed

The high performance of polyethyleneimine (PEI)-based solid adsorbent for CO2 capture has been well recognized in thermogravimetric analysis (TGA) and small-scale fixed bed reactors through the measurements of their equilibrium capacities but has not been really demonstrated on larger scales towards practical utilization. In the present study, a laboratory-scale bubbling fluidized bed reactor loaded with a few kg adsorbent is used to evaluate the adsorption performance of PEI–silica adsorbent under different working conditions including with/without the presence of moisture, different gas–solid contact times, initial bed temperatures, and CO2 partial pressures. The adsorption capacities have shown a clear degradation tendency under dry condition. However, they can be stabilized at a high level of 10.6–11.1% w/w over 60 cycles if moisture (ca. 8.8 vol%) is present in the gas flow during adsorption and desorption. Breakthrough capacities can be stabilized at the level of 7.6–8.2% w/w with the gas–solid contact time of 13 s. The adsorption capacities for the simulated flue gases containing 5% CO2 are only slightly lower than those for the simulated flue gases containing 15% CO2, indicating that the PEI–silica adsorbent is suitable for CO2 capture from flue gases of both coal-fired and natural gas-fired combined cycle power plants. The exothermal heat of adsorption is estimated by the energy balance in the fluidized bed reactor and found to be close (within 10%) to the measured value by TG-DSC. The regeneration heat for the as-prepared PEI–silica adsorbent is found to be 2360 kJ/kgCO2 assuming 75% recovery of sensible heat which is well below the values of 3900–4500 kJ/kgCO2 for a typical MEA scrubbing process with 90% recovery of sensible heat.

Post-combustion CO2 Capture from Natural Gas Combined Cycles by Solvent Supported Membranes

Among the CO2 separation technologies, CO2 membranes are currently receiving an increasing interest, largely thanks to the development of solvents such as ionic liquids and deep eutectic solvents, which are suitable for use in solvent supported membrane systems. The aim of this work is to perform a techno-economic analysis of a natural gas-fired combined cycle power plant integrating CO2 membranes. Such a configuration is based on a two-membrane system, the first one separating the CO2 for final sequestration, the second one used to generate a selective CO2-rich flue gas recycle. The techno-economic assessment uses three modelling tools: (i) process modelling of the complete power plant, performed with the in-house GS code and Aspen Plus, (ii) modelling of the membrane, performed with a finite difference method implemented in Matlab and (iii) economic modelling by a bottom-up approach. The final material balances show that using a moderate pressurization of the combined cycle flue gas results in the lowest energy loss and lowest capture cost.

Exergetic analysis and evaluation of coal-fired supercritical thermal power plant and natural gas-fired combined cycle power plant

The present work has been undertaken for energetic and exergetic analysis of coal-fired supercritical thermal power plant and natural gas-fired combined cycle power plant. Comparative analysis has been conducted for the two contestant technologies. The key drivers of ener- getic and exergetic efficiencies have been studied for each of the major sub-system of two contestant technologies. Overall energetic and exergetic efficiency of coal-fired supercritical thermal power plant are found to be 43.48 and 42.89 %, respectively. Overall energetic and exergetic efficiency of natural gas-fired combined cycle power plant are 54.47 and 53.93 %, respectively. The major energetic power loss has been found in the condenser for coal-fired supercritical thermal power plant. On the other hand, the major energetic power loss has been found in both the condenser and heat recovery steam generator for gas-fired combined cycle thermal power plant. The exergetic anal- ysis shows that boiler field is the main source of exergetic power loss in coal-fired supercritical thermal power plant and combustion chamber in the gas-fired combined cycle thermal power plant. It is concluded that natural gas-fired combined cycle power plant is better from energetic and exergetic efficiency point of view. These results will be useful to all involved in the improvement of the design of the existing and future power plants.

Integration of low-temperature transcritical CO2 Rankine cycle in natural gas-fired combined cycle (NGCC) with post-combustion CO2 capture

When integrating a natural gas-fired combined cycle (NGCC) with post-combustion CO2 capture, an efficiency penalty is induced. In the current work the penalty was a reduction of net plant efficiency from 58.5% to 50.6%. The largest part of this penalty is related to the reduction of power output from the power plant due to steam consumption for CO2 capture solvent regeneration. The potential of recovering low-temperature un-used thermal energy is limited as this low-grade energy is at a temperature below the low-pressure pinch-point of the steam boiler. In this work, heat sources located in the CO2 capture process and CO2 compression process have been identified and integrated with a low-temperature Rankine cycle utilizing CO2 as working fluid. The approach presented in this paper is novel in the sense that it has not been applied on power plants operating with post-combustion CO2 capture.Results show that integration of the low-temperature CO2 Rankine cycle can increase the net plant efficiency of a natural gas-fired Combined Cycle power plant by 1.6%-points (50.6–52.2%) when using a conventional Monoethanolamine (MEA)-based CO2 capture process. Capture process modifications (Lean Vapour Recompression) in combination with application of the CO2 Rankine cycle can increase the efficiency by 1.8%-points (50.6–52.4%). The contribution from the CO2 Rankine cycle for the latter case is 0.9%-points.

Energy and economic analysis of different heat pump systems for space heating

The consumption of natural gas as a primary energy source in Italy has increased during recent years, mainly due to more widespread use of modern natural gas-fired combined cycle power plants. It is generally accepted that such an increased use of natural gas is beneficial, particularly in summer, due to the 'take-or-pay' contracts that often regulate energy supply. Conversely, the use of electrical energy should be decreased, in order to limit the 'peak demand' problem that has become prevalent in Italy. Therefore, besides electrically driven heat pumps (EHPs) that achieve good efficiencies, it is interesting to also consider the option of combustion engine-driven GEHPs for space heating purposes. In the latter type of HPs, losses attributed to the production and transport of electricity are eliminated and, in addition, there is the possibility to re-use the heat from the combustion engine. This article presents an assessment of the annual economic and energy profiles of electric and internal combustion engine HPs for space heating purposes. Due to the dependency of the performance of such technology on the source and sink (heating circuit) temperature levels, a comparison is performed of air-to-water HP systems (the most widely used) in two cases of maximum flow temperatures. The calculations show that natural gas-driven HPs can achieve approximately the same efficiency as electrically driven HPs that are powered with electricity from modern natural gas-fired combined cycle power plants. Within this study, the efficiencies of such systems are also compared with those that utilize conventional boiler technologies.

Comparison of natural gas driven heat pumps and electrically driven heat pumps with conventional systems for building heating purposes

Electrically driven heat pumps achieve good efficiencies for space heating. If heat pumps are driven directly by a combustion engine instead of an electric motor, losses attributed to the production and transport of electricity are eliminated. Additionally, the use of the combustion engine's heat leads to a reduced temperature difference across the heat pump. This article presents annual efficiencies of these systems and compares internal combustion engine and electrically driven heat pumps in terms of primary energy consumption and CO2 emissions. Because heat pump performance depends strongly on the heating circuit's flow temperature level, the comparison is performed for air-to-water and geothermal heat pump systems in two cases of maximum flow temperatures (40 °C and 60 °C). These temperature levels represent typical modern buildings with large heating surfaces and older buildings with high-temperature radiators, respectively. In addition to the different heat pump setups, conventional space heating systems are included in the comparison. The calculations show that natural gas-driven heat pumps achieve about the same efficiency and CO2 emissions as electrically driven heat pumps powered with electricity from the most modern natural gas-fired combined cycle power plants. The efficiency of such systems is about twice that of conventional boiler technologies.