Natural Gas Combined Cycle Plants Research Articles

The long-term life cycle private and external costs of high coal usage in the US

Using four times as much coal in 2050 for electricity production need not degrade air quality or increase greenhouse gas emissions. Current SO x and NO x emissions from the power sector could be reduced from 12 to less than 1 and from 5 to 2 million tons annually, respectively, using advanced technology. While direct CO 2 emissions from new power plants could be reduced by over 87%, life cycle emissions could increase by over 25% due to the additional coal that is required to be mined and transported to compensate for the energy penalty of the carbon capture and storage technology. Strict environmental controls push capital costs of pulverized coal (PC) and integrated coal gasification combined cycle (IGCC) plants to $1500–1700/kW and $1600–2000/kW, respectively. Adding carbon capture and storage (CCS) increases costs to $2400–2700/kW and $2100–3000/kW (2005 dollars), respectively. Adding CCS reduces the 40–43% efficiency of the ultra-supercritical PC plant to 31–34%; adding CCS reduces the 32–38% efficiency of the GE IGCC plant to 27–33%. For IGCC, PC, and natural gas combined cycle (NGCC) plants, the carbon dioxide tax would have to be $53, $74, and $61, respectively, to make electricity from a plant with CCS cheaper. Capturing and storing 90% of the CO 2 emissions increases life cycle costs from 5.4 to 11.6 cents/kWh. This analysis shows that 90% CCS removal efficiency, although being a large improvement over current electricity generation emissions, results in life cycle emissions that are large enough that additional effort is required to achieve significant economy-wide reductions in the US for this large increase in electricity generation using either coal or natural gas.

Cost and performance of fossil fuel power plants with CO 2 capture and storage

CO 2 capture and storage (CCS) is receiving considerable attention as a potential greenhouse gas (GHG) mitigation option for fossil fuel power plants. Cost and performance estimates for CCS are critical factors in energy and policy analysis. CCS cost studies necessarily employ a host of technical and economic assumptions that can dramatically affect results. Thus, particular studies often are of limited value to analysts, researchers, and industry personnel seeking results for alternative cases. In this paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and current costs of fossil fuel power plants with CCS on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed for three major plant types: pulverized coal (PC) plants, natural gas combined cycle (NGCC) plants, and integrated gasification combined cycle (IGCC) systems using coal. In particular, we examine the effects of recent increases in capital costs and natural gas prices, as well as effects of differential plant utilization rates, IGCC financing and operating assumptions, variations in plant size, and differences in fuel quality, including bituminous, sub-bituminous and lignite coals. Our results show higher power plant and CCS costs than prior studies as a consequence of recent escalations in capital and operating costs. The broader range of cases also reveals differences not previously reported in the relative costs of PC, NGCC and IGCC plants with and without CCS. While CCS can significantly reduce power plant emissions of CO 2 (typically by 85–90%), the impacts of CCS energy requirements on plant-level resource requirements and multi-media environmental emissions also are found to be significant, with increases of approximately 15–30% for current CCS systems. To characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.

Use of experience curves to estimate the future cost of power plants with CO 2 capture

Given the dominance of power plant emissions of greenhouse gases, and the growing worldwide interest in CO 2 capture and storage (CCS) as a potential climate change mitigation option, the expected future cost of power plants with CO 2 capture is of significant interest. Reductions in the cost of technologies as a result of learning-by-doing, R&D investments and other factors have been observed over many decades. This study uses historical experience curves as the basis for estimating future cost trends for four types of electric power plants equipped with CO 2 capture systems: pulverized coal (PC) and natural gas combined cycle (NGCC) plants with post-combustion CO 2 capture; coal-based integrated gasification combined cycle (IGCC) plants with pre-combustion capture; and coal-fired oxyfuel combustion for new PC plants. We first assess the rates of cost reductions achieved by other energy and environmental process technologies in the past. Then, by analogy with leading capture plant designs, we estimate future cost reductions that might be achieved by power plants employing CO 2 capture. Effects of uncertainties in key parameters on projected cost reductions also are evaluated via sensitivity analysis.

Thermodynamic and related analysis of natural gas combined cycle power plants with and without carbon sequestration

Thermodynamic and related 'exergoeconomic' performance criteria have been used to evaluate natural gas combined cycle (NGCC) power generation systems, with and without carbon dioxide (CO 2 ) removal technologies. These plants were previously studied by the US National Energy Technology Laboratory employing conventional energy and mass balance results, and have now been evaluated using detailed energy, exergy and exergoeconomic analyses. The plant consisted of a gas turbine together with a steam cycle having three pressure levels. Such NGCC plants show the least exergetic improvement potential amongst competing fossil fuel generators going forward, because they are already enhanced by use of a thermodynamic 'topping' cycle. Carbon capture was simulated on the basis of CO 2 recovery from the flue gas stream that leaves the heat recovery steam generator via a commercial amine process. Ninety per cent of the CO 2 was captured in this way, and then compressed into a high-pressure liquid. This was achieved with significant power penalty (some 21%) and increase in generating cost per MWh (44%). Combustion and heat transfer processes are the main sources of exergy degradation within power cycles. Fuel combustion accounted for some 32% of exergy destruction. Even with CO 2 sequestration, the NGCC system is still a thermodynamically attractive option compared with modern fossil fuel alternatives. Overall, the exergoeconomic results indicate that significant improvements can be achieved by considering the power generation systems as a whole, rather than concentrating on the improvement in performance of individual components (which is a common practice in exergoeconomic optimization studies).

Baseload wind energy: modeling the competition between gas turbines and compressed air energy storage for supplemental generation

The economic viability of producing baseload wind energy was explored using a cost-optimization model to simulate two competing systems: wind energy supplemented by simple- and combined cycle natural gas turbines (“wind+gas”), and wind energy supplemented by compressed air energy storage (“wind+CAES”). Pure combined cycle natural gas turbines (“gas”) were used as a proxy for conventional baseload generation. Long-distance electric transmission was integral to the analysis. Given the future uncertainty in both natural gas price and greenhouse gas (GHG) emissions price, we introduced an effective fuel price, p NGeff, being the sum of the real natural gas price and the GHG price. Under the assumption of p NGeff=$5/GJ (lower heating value), 650 W/m 2 wind resource, 750 km transmission line, and a fixed 90% capacity factor, wind+CAES was the most expensive system at ¢6.0/kWh, and did not break even with the next most expensive wind+gas system until p NGeff=$9.0/GJ. However, under real market conditions, the system with the least dispatch cost (short-run marginal cost) is dispatched first, attaining the highest capacity factor and diminishing the capacity factors of competitors, raising their total cost. We estimate that the wind+CAES system, with a greenhouse gas (GHG) emission rate that is one-fourth of that for natural gas combined cycle plants and about one-tenth of that for pulverized coal plants, has the lowest dispatch cost of the alternatives considered (lower even than for coal power plants) above a GHG emissions price of $35/tC equiv., with good prospects for realizing a higher capacity factor and a lower total cost of energy than all the competing technologies over a wide range of effective fuel costs. This ability to compete in economic dispatch greatly boosts the market penetration potential of wind energy and suggests a substantial growth opportunity for natural gas in providing baseload power via wind+CAES, even at high natural gas prices.

Are Renewables Portfolio Standards Cost-Effective Emission Abatement Policy?

Renewables portfolio standards (RPS) could be an important policy instrument for 3P and 4P control. We examine the costs of renewable power, accounting for the federal production tax credit, the market value of a renewable credit, and the value of producing electricity without emissions of SO2, NOx, mercury, and CO2. We focus on Texas, which has a large RPS and is the largest U.S. electricity producer and one of the largest emitters of pollutants and CO2. We estimate the private and social costs of wind generation in an RPS compared with the current cost of fossil generation, accounting for the pollution and CO2 emissions. We find that society paid about 5.7 cent/kWh more for wind power, counting the additional generation, transmission, intermittency, and other costs. The higher cost includes credits amounting to 1.1 cent/kWh in reduced SO2, NOx, and Hg emissions. These pollution reductions and lower CO2 emissions could be attained at about the same cost using pulverized coal (PC) or natural gas combined cycle (NGCC) plants with carbon capture and sequestration (CCS); the reductions could be obtained more cheaply with an integrated coal gasification combined cycle (IGCC) plant with CCS.

T HE MEXICAN POWER SECTOR AND ITS D EPENDENCE ON N ATURAL G AS

The price of electricity and fuels directly affects the competitiveness of energy-intensive industries. The expansion of the Mexican electric power sector is planned via natural gas combined cycle (NGCC) plants. This leaves the power sector more susceptible to the behavior of this particular fuel. In recent years, the price of natural gas showed high values and volatility. It would be wise to consider alternatives in order to have a reliable supply of energy. The integrated gasification combined cycle (IGCC) technology presents an opportunity to diversify the in- stalled capacity, its main disadvantage compared to NGCC is higher CO 2 emissions. Self-supply has been able to secure the electric power supply. However, in some cases it has not been successful at providing electric power at a lower rate than CFE.

The Mexican Power Sector and its Dependence on Natural Gas

ABSTRACT The price of electricity and fuels directly affects the competitiveness of energy-intensive industries. The expansion of the Mexican electric power sector is planned via natural gas combined cycle (NGCC) plants. This leaves the power sector more susceptible to the behavior of this particular fuel. In recent years, the price of natural gas showed high values and volatility. It would be wise to consider alternatives in order to have a reliable supply of energy. The integrated gasification combined cycle (IGCC) technology presents an opportunity to diversify the installed capacity, its main disadvantage compared to NGCC is higher CO2 emissions. Self-supply has been able to secure the electric power supply. However, in some cases it has not been successful at providing electric power at a lower rate than CFE.

The strategic technology options for mitigating CO 2 emissions in power sector: assessment of Shanghai electricity-generating system

In this paper, the strategic technology options, especially the potential role of natural gas combined cycle and nuclear power plants, in mitigation of CO 2 emission in electricity sector in China are assessed. We analyse the influence of different power generation technologies on CO 2 emission volume and abatement cost based on energy market and electricity demand prospects, and least-cost expansion of electricity generating system. In the latter model, we take into account electricity supply quality and CO 2 emission. The CO 2 abatement cost is estimated in a period of time rather than the traditional abatement cost estimation performed for a target year. The proposed model is applied to the case of Shanghai Municipality in China to assess potential role of natural gas combined cycle and nuclear power plants in mitigation of CO 2 emission. Impact of the baseline technology choice on CO 2 abatement cost is analysed through the formulation of three scenarios. For the first one (“Baseline” scenario), it is assumed that expansion of the electricity supply system is based only on coal-fired power plants; for the second scenario, it is supposed that the decision makers have already envisaged the use of natural gas combined cycle power plants (CCPP) in addition to coal fired ones; the third scenario mixes coal-fired, natural gas CCPP and nuclear power plants. It is found that on the horizon of the study (2020), maximum CO 2 emission mitigation potential of natural gas CCPPs can reach 42.4 million tons (MtCO 2), whereas maximum CO 2 emission reduction potential of nuclear power plants can be 298.2 MtCO 2. The CO 2 abatement cost estimation falls into the range from US$19/tCO 2 to US$51/tCO 2 depending on the level of imposed CO 2 penalty, volume of carbon emission reduction and baseline technology choice.

Carbon dioxide removal via a membrane system in a natural gas combined-cycle plant

Gas separation using polymeric membranes is generally believed to be poorly suited for CO2 capture from gas turbine based power plants, because the high air-to-fuel ratios produce large amounts of exhaust gas containing strongly diluted CO2. The driving force for selective permeation is obtained by compressing the entire exhaust stream, resulting in a significant energy penalty. Additional energy is required for permeate compression, which is impaired by the other gases emitted with CO2. In spite of these difficulties, the present study is concerned with membrane systems, which the authors believe warrant further investigation. The attention was focused on natural gas combined cycles (NGCC), so as to have a starting point with high energy efficiency and low baseline emissions. To reduce the exhaust gases and to concentrate the CO2, the NGCC is fitted with a flue gas recirculation system, which has proven to leave plant performance substantially unaffected. The energy requirements for exhaust gas compression are reduced by introducing a heat exchanger between the compressed and residual exhaust gas and recovering heat from the latter. The membrane separator has been modeled using conservative data reported in the literature. Various configurations, such as multiple compression-expansion and multistage membrane units, are considered. Permeate compression is also modeled, so as to highlight the influence of permeate purity on this process. The results show a rather moderate performance penalty. A specific emission of 100 g CO2/kWh corresponds to 48 percent efficiency. Admittedly a CO2 separator for a power plant would be larger than any other membrane system designed for other purposes. However, the system appears technically feasible and would offer valuable benefits in terms of emissions.

99/02608 Structural properties of amorphous semiconductors

The decarbonization of power systems is among the primary actions to fight air pollution and climate change. In this study, we evaluate the costs of a gradual transition towards a new power system in which the oldest coal plants are replaced with low-carbon power plants. We developed the Wind Energy Integration Cost Advisor Model (WEICAM) to analyze different strategies for this energy transition and determine the most cost-effective roadmap, with and without externalities. The test case is the PJM Interconnection, one of the power systems in the United States with the largest fraction of coal. Different strategies to replace coal plants are evaluated: 1) installing only new, high-efficiency, natural-gas combined-cycle plants (control case), 2) installing new wind farms in combination with natural-gas combined-cycle plants used as spinning reserves (wind case), and 3) same as the wind case but boosting up the production of existing baseload plants that work with a capacity factor between 50% and 60%–80% before installing new wind farms. All three strategies have similar costs (∼54 $/MWh), but the latter is slightly more cost-effective, with a total of 19 GW of coal capacity decommissioned and an increase in the levelized cost of electricity from 49.1 to 53.6 $/MWh (without externalities). In addition, selecting the windiest sites – even far away from the PJM region – is cheaper than selecting local but less windy sites. When externalities due to human health and environmental pollution are accounted for, the two wind-based strategies become the most advantageous, reducing the levelized cost below 104 $/MWh from the initial 110 $/MWh. We conclude that adding new wind farms from the windiest locations, accompanied by a better management of existing plants and a small addition of new natural-gas reserve capacity, is the most economic and the most environmentally responsible pathway to replace retiring coal-fired power plants in PJM.

Hot gas cleaning—materials and performance

Hot gas cleaning systems for the removal of contaminants from combustion and gasification gas streams are critical components in the next generation of advanced coal/biomass/waste-fired combined cycle plants. The contaminants of concern are those environmental pollutants which would otherwise exceed emissions legislation and those which would directly impact on the life or operability of the gas turbine used in the cycle. It is essential that these ‘solid fuel’ plants can provide gases suitable for the advanced, high inlet temperature gas turbines being developed currently for natural gas combined cycle plants. Regardless of the gas turbine, the application of hot gas cleaning in solid fuel combined cycle plants leads to increased cycle efficiencies over those achievable with conventional wet scrubbing techniques and greatly reduces any waste water disposal problems. The introduction of systems for particulate removal, alkali reduction, H2S/SOx, reduction, NH3/NOx(reduction, HCI removal etc. into the advanced solid fuel processes leads to problems of integration as well as those of the materials and performance issues associated with the individual components. This paper reviews the major hot gas cleaning systems under development, identifies the materials challenges that these present and discusses possible consequences of their integration into solid fuel combined cycle processes.

High speed engine meets medium speed requirements

The decarbonization of power systems is among the primary actions to fight air pollution and climate change. In this study, we evaluate the costs of a gradual transition towards a new power system in which the oldest coal plants are replaced with low-carbon power plants. We developed the Wind Energy Integration Cost Advisor Model (WEICAM) to analyze different strategies for this energy transition and determine the most cost-effective roadmap, with and without externalities. The test case is the PJM Interconnection, one of the power systems in the United States with the largest fraction of coal. Different strategies to replace coal plants are evaluated: 1) installing only new, high-efficiency, natural-gas combined-cycle plants (control case), 2) installing new wind farms in combination with natural-gas combined-cycle plants used as spinning reserves (wind case), and 3) same as the wind case but boosting up the production of existing baseload plants that work with a capacity factor between 50% and 60%–80% before installing new wind farms. All three strategies have similar costs (∼54 $/MWh), but the latter is slightly more cost-effective, with a total of 19 GW of coal capacity decommissioned and an increase in the levelized cost of electricity from 49.1 to 53.6 $/MWh (without externalities). In addition, selecting the windiest sites – even far away from the PJM region – is cheaper than selecting local but less windy sites. When externalities due to human health and environmental pollution are accounted for, the two wind-based strategies become the most advantageous, reducing the levelized cost below 104 $/MWh from the initial 110 $/MWh. We conclude that adding new wind farms from the windiest locations, accompanied by a better management of existing plants and a small addition of new natural-gas reserve capacity, is the most economic and the most environmentally responsible pathway to replace retiring coal-fired power plants in PJM.