Natural Gas-fired Power Plants Research Articles

Hot money: Illuminating the financing of high-carbon infrastructure in the developing world

SummaryMajor infrastructure financiers will have to significantly decarbonize their investments to meet mounting promises to cut carbon emissions to “net-zero” by mid-century. We provide new details about those needed shifts. Using two World Bank databases of infrastructure projects throughout the developing world, and applying a methodology for imputing the projects' likely future carbon output, we assess the emissions profile of power-plant projects executed from 2018 through 2020 — the three years immediately preceding the spate of net-zero pledges. We find that approximately half the generation executed in those years is too carbon-intensive to align with keeping Earth's average temperature from exceeding 1.5°C above pre-industrial levels, largely because of the prevalence of new natural-gas–fired power plants. We also find new evidence of host countries' agency in shaping carbon trajectories: Much of the climate-misaligned financing is not foreign but domestic. And we find different institutions are financing infrastructure portfolios with significantly differing carbon intensities.

Decarbonizing the Coal-Fired Power Sector in China via Carbon Capture, Geological Utilization, and Storage Technology.

Carbon capture, utilization, and storage (CCUS) is a critical technology to realize carbon neutrality target in the Chinese coal-fired power sector, which emitted 3.7 billion tonnes of carbon dioxide in 2017. However, CCUS technology is often viewed as an "alternative technology" option owing to common perceptions of relatively high cost and potential risks. This study indicates that coal power CCUS is likely to be a cost-effective and key technology for helping China reach the ambitious goal of carbon neutrality. This comprehensive, national-scale assessment of CCUS deployment on coal power in China is based on a unique bottom-up approach that includes site selection, coal plant screening, techno-economic analysis, and carbon dioxide source-sink matching. Analysis indicates that, based on 2017 costs and assumptions, more than 70% of coal power plants in this study could be cost-competitive with natural gas-fired power plants, and 22-58% would be cost-competitive with onshore wind generation. These insights suggest that the commercialization of CCUS technology in the coal power sector in China is a viable route toward decarbonizing the economy if a grid price policy similar to that of renewables and natural gas power is applied.

Modeling of a dry low nitrogen oxides burner using a three-dimensional computational fluid dynamics simulation

Nitrogen oxides are considered as one of the greenhouse gases. Among the most significant emission sources for this gas is a natural gas-fired power plant. The United Nations General assembly suggested in 1988 that human activities can negatively impact weather patterns, and thus they should be controlled. This control policy can improve the efficiency of final consumers such as power plants, cars, or other energy-intensive industries. In this paper, the existing strategies and explicitly making the dry low nitrogen oxides burner reduce greenhouse gases in power plants are explored. The geometry of the burner has been produced in a three-dimensional form in GAMBIT software, and the results of the simulation have been expressed through FLUENT software. Contours of pressure, temperature, and velocity of the fluid in the furnace are also derived. It is concluded that the dry low nitrogen oxides burners plan has a better result compared with other strategies.

Porous materials for carbon dioxide separations.

Global investment in counteracting climate change has galvanized increasing interest in carbon capture and sequestration (CCS) as a versatile emissions mitigation technology. As decarbonization efforts accelerate, CCS can target the emissions of large point-source emitters, such as coal- or natural gas-fired power plants, while also supporting the production of renewable or low-carbon fuels. Furthermore, CCS can enable decarbonization of difficult-to-abate industrial processes and can support net CO2 removal from the atmosphere through bioenergy coupled with CCS or direct air capture. Here we review the development of porous materials as next-generation sorbents for CO2 capture applications. We focus on stream- and sector-specific challenges while highlighting case studies within the context of the rapidly shifting energy landscape. We conclude with a discussion of key needs from the materials community to expand deployment of carbon capture technologies.

Modeling wind turbine-related greenhouse gas payback times in Europe at high spatial resolution

An important metric for quantifying the greenhouse gas saving potential of wind turbine types is the greenhouse gas payback time. Previous studies revealed that wind speed and wind turbine size are negatively correlated with greenhouse gas payback times. However, so far, payback times were mostly estimated for wind turbine types with a hub height of less than 100 m and rated power below 2000 kW at coarse spatial resolution. It is unclear if the negative correlation with turbine size continues to hold at greater heights since, in general, the change in wind speed increase reduces with higher altitude. Thus, the hypothesis that the size of more giant wind turbine types is not negatively correlated with greenhouse gas payback times was tested. The main goal was to develop a high spatial-resolution atlas of European greenhouse gas payback times considering the small-scale wind resource variability for 33 generic wind turbine types. The greenhouse gas payback times were estimated by first calculating the average monthly energy yields for the wind turbine types with hub heights from 60 to160 m and rated power from 800 to 4200 kW at a 250 m × 250 m spatial resolution grid. Secondly, the wind turbine types’ anticipated greenhouse gas emissions were estimated based on their hub height and rotor diameter. The wind turbine type-related net greenhouse gas emissions were compared with the mean emissions of a natural gas-fired power plant (0.5 kg CO2,eq/kWh). It was found that wind turbine types with rated power and hub height of {2400 kW, 60 m} and {3600 kW, 80 m} have the shortest greenhouse gas payback times. The European median greenhouse gas payback time was estimated at 6.1 months including the wind turbine types with lowest payback times. In the hub height range of 60 to 160 m, the correlation between greenhouse gas payback times and hub height was found to be significantly positive.

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.

Part load operation of natural gas fired power plant with CO2 capture system for selective exhaust gas recirculation

• Model of gas power plant with CO 2 capture for selective gas recycle is presented. • Gas recycle offers stable combustion, higher CO 2 content, low gas flow and reboiler duty. • Part-load operation of gas plant at 80, 60, 40% is analyzed for the parallel and hybrid case. This work investigates base and part load operation of natural gas combined cycle power plant integrated with post-combustion CO 2 capture plant and selective exhaust gas recirculation scheme. Decarbonizing of natural gas combined cycle power plant is complex due to the higher flue gas flow rate with the least CO 2 content ~ 3–4 vol% with residual 20% O 2 and 77% N 2 content. Therefore, the effect of series, parallel and hybrid selective exhaust gas recirculation is examined, a concept where selectively CO 2 can be recycled back and mixed into the ambient air to the inlet feed of the compressor thereby reducing the flue gas flow rate and enhancing CO 2 content at the inlet of capture plant. The study is novel in a way that part-load performance at 80, 60 and 40% for parallel and hybrid scheme of selective exhaust gas recirculation is analyzed through process simulation in Aspen Plus for 606 MW commercial-scale natural gas combined cycle power plant coupled with an amine-based CO 2 capture plant. It is found that the simulation results of power plant and CO 2 capture plant model agrees well with the experimental results. Further, the performance results show the viability of base and part load operation of natural gas combined cycle power plant integrated with CO 2 capture plant by enhancing the CO 2 concentration for hybrid configuration to approximately 19 vol%. For parallel configuration, CO 2 content increases to around 13–14 vol% at 70% recirculation ratio in comparison to 6.6 vol% for simple EGR at 35% ratio. It is found that the selective exhaust gas recirculation offers more stable combustion by maintaining O 2 content at 19 vol% at combustor inlets for parallel and hybrid cases and the flue gas flow rate reduces to 68 and 70%, respectively thus reducing the size of the capture plant. The specific reboiler duty for hybrid, parallel, and series configuration reduces to 3.19, 3.25, and 3.31 MJ/kg CO 2 , respectively in comparison to 3.54 MJ/kg CO 2 for base case natural gas combined cycle power plant coupled with MEA-based CO 2 capture unit. Whereas for 80 to 40% load change, the specific reboiler duty drops from 1.78% to 1.14% for parallel and hybrid configurations, respectively. In conclusion, hybrid selective exhaust gas recirculation configuration shows less efficiency penalty from base load to 40% part load and results in a decrease in specific reboiler duty in comparison to parallel configuration. Therefore, the study is innovative in an aspect that part-load performance at 80, 60 and 40% is performed, and results show a similar pattern as of baseload operation.

Bench-Scale Absorption Testing of Aqueous Potassium Lysinate as a New Solvent for CO2 Capture in Natural Gas-Fired Power Plants

This work reports the results of an experimental campaign aiming at the characterization of the CO2 absorption performance for different aqueous solutions of potassium lysinate (LysK). The solvent stands out as a promising amino acid for post-combustion CO2 capture from combustion flue gas and it has been selected based on the high values of the overall kinetic constant (kov) and CO2 absorption flow reported in the literature.Three different LysK concentrations (8.9, 17.4 and 32.9 %w/w) have been compared and benchmarked against aqueous MEA solution (30% w/w), via closed-cycle absorption tests conducted on a bench-scale column (D = 80 mm, Packed Height = 900 mm). Liquid to gas ratios (1.39 mol/mol) and synthetic flue gas conditions (4% CO2 concentration on a molar basis, the remainder being N2) target the solvent application of CO2 capture in natural gas combined cycles, and are consistent with previous tests conducted on MEA and Potassium prolinate (ProK) solutions.Results highlight that LysK attains faster loading increase rates compared to ProK and higher CO2 loadings at saturation (between 0.82 and 0.98 molCO2/molAlk depending on the test case) with respect to MEA (0.52 molCO2/molAlk) and ProK. Finally, according to the capacity trend measured in this work, an aqueous solution with 43.7% w/w LysK has been identified as a promising option to be further investigated, verifying potential savings in the absorber packing requirements (i.e. lower packing height in a full-scale application, due to the better kinetics of LysK) while ensuring the same absorption capacity level of 30% MEA.

Update of Techno-Economic Benchmarks for Fossil Fuel Power Plants with CO2 Capture

Carbon capture and storage (CCS) has long been recognized as a key component of an effective mitigation strategy to decarbonize the power and industrial sectors. For many reasons, however, the commercial deployment of CCS technologies has been slow and must accelerate to contribute effectively to mitigating climate change. This paper presents the outcome of a study that Amec Foster Wheeler Italiana, a Wood Company, performed on behalf of IEAGHG, aimed at updating the technical and economical assessment of coal and natural gas fired power plants with and without CO2 capture, considering the benefits of recent technology improvements. The work has focused on ultra-supercritical pulverized coal (USC PC) boiler and natural gas combined cycle (NGCC) power plants, with and without CO2 capture. Post combustion capture based on solvent scrubbing only has been considered; this is currently the commercially leading option for capture on both pulverized coal and natural gas-fired power plants. Two different capture unit designs are studied: a 90% CO2 recovery scenario, and a high capture rate scenario (around 99%). Starting from the benchmark NGCC cases described above, the work has also addressed: • The impacts of Flue Gas Recirculation (FGR) on power plant performances and economics. The recirculation of part of the flue gas back to the GT compressor has the beneficial effects of enriching the exhaust gas in CO2 and significantly reducing the gas throughput of the absorption section in the CO2 capture unit, but also shows some drawbacks, such as the cost of the recirculation system and a slight efficiency drop. • Improvements to the operational flexibility of both natural gas and coal fired power plants with carbon capture from a simplified techno-economic optimization standpoint, updating the main outcomes of the work presented in “Operating flexibility of power plants with CCS” (2011, Foster Wheeler) with state-of-the-art technologies. The trade-off between flexibility and efficiency is also analyzed for the coal cases, including a literature review of the possible impacts on operating flexibility of adopting Advanced-Ultra Super Critical (A-USC) technologies (700°C). • Consideration of mid-term future advancements on power generation technologies for the NGCC plant, including the use of novel improved materials in the hot gas path of the for the gas turbine and integration with Molten Carbon Fuel Cells (MCFCs), in which hydrogen is provided via natural gas steam reforming (using MCFC waste heat). The MCFC, besides contributing to power generation, allows separation of CO2 from the NGCC flue gas and its release into a syngas stream that needs a relatively simple purification method to remove the CO2 (like cryogenic technology) and can then be re-covered as auxiliary fuel to the power island.

An open-access, detailed description of post-combustion CO2 capture plant

Bechtel National (Reston, VA) have undertaken a FEED study for retrofitting a 2x2x1 natural gas-fired gas turbine combined cycle power plant with post-combustion carbon capture (PCC) for CO2 storage/utilization. The comprehensive programme of work covers the integration of the retrofitted carbon capture and compression plant to the combined cycle power plant, together with the detailed design of an amine-based conventional absorber-stripper scrubbing system with a non-proprietary solvent, 35% w/w MEA. Supporting studies have analysed options for single- and two-stage thermal reclaiming and also examined discrepancies between process modelling packages and the possible scope for alternative trade-offs between capital and operating costs. Given that modelling alone cannot predict commercially-important factors such as solvent management costs a long-term pilot test programme is strongly recommended, with outline details supplied for pilot size and the testing period.

A long-term pilot-scale algal cultivation on power plant flue gas – Cultivation stability and biomass accumulation

A long-term culture of a selected freshwater microalgal assemblage on power plant flue gas was realized using a pilot-scale photobioreactor. Different culture conditions of light cycle, harvesting amount, pH stabilization, and sulfur addition were tested during a 12-month continuous operation at a natural gas fired power plant. The results concluded that the daily harvesting amount of 60% with no light-cycle and NH4NO3 as the nitrogen source and pH stabilization agent, resulted in optimal cultivation performance. Biomass concentration and biomass productivity reached 1.07 ± 0.23 g L−1 and 0.43 ± 0.14 g L−1 d−1, respectively. During the year-long cultivation period, the algal assemblage was relatively stable with average abundances of 88 ± 4% and 12 ± 4% for algae and bacteria, respectively, and no significant differences between individual case scenarios. The stable culture fostered a stable biomass composition. Protein, carbohydrate, and lipid contents of the algal biomass were 58.60 ± 2.41%, 19.5 ± 2.44%, and 9.70 ± 1.68%, respectively.

An updated assessment of technical efficiency and returns to scale for U.S. electric power plants

This paper utilizes cutting-edge panel stochastic frontier electricity production models to measure the impact of state and federal regulations on United States (U.S.) natural gas fired power plants from 1994 to 2016. Using an expansive dataset, I simultaneously account for plant specific heterogeneity as well as time varying and persistent inefficiency. Previous studies of electricity generation in the U.S. have ignored at least one of these components. The ability to control for unobserved heterogeneity is important in assessing long-term managerial effectiveness.Deploying a translog functional form, I extract firm specific information on returns to scale (RTS). For the preferred model, results indicate that mean persistent technical efficiency (TE) for natural gas fired power plants is 71 percent, transient TE is 72 percent, and RTS are 0.94. I find an inverse relationship between RTS and plant output level, but a positive relationship between TE and output level. For a given plant, the regulatory variables under consideration tend to increase plant efficiency, along the lines of the Porter hypothesis. Furthermore, plants with higher transient TE have significantly lower costs per kWh.

Utility-specific projections of electricity sector greenhouse gas emissions: a committed emissions model-based case study of California through 2050

The environmental profile of electricity is changing rapidly, motivating a need for provider- and time-specific estimates for accurate environmental assessment. This work shows that defensible, provider- and time-specific emissions projections can be derived from two major factors: committed emissions from existing power plants and policy restrictions on future system characteristics. This letter introduces a bottom–up, power plant-based model that projects utility-specific annual average greenhouse gas (GHG) intensity of electricity in the U.S. state of California for 2018–2050, believed to be the first openly available GHG emissions model with utility-specific projections. California is a useful case study for testing in part because of its strict regulatory GHG targets and the complexity of its electricity system, including limited asset ownership by utilities and substantial reliance on imported electricity. This plant-based approach to emissions projections bounds uncertainty in a way that less infrastructurally grounded approaches cannot. For example, emissions from unspecified sources of power can be estimated based on available plants. Based on historical power plant lifetimes, existing policy, and default model assumptions, the CO2 intensity of Californian electricity is projected to drop from 175 kg CO2/MWh (sales + losses, 2020) to 95 kg CO2/MWh by 2030, operationally decarbonizing by 2047. Upstream methane leakage increases GHG intensity of natural gas-fired power plants by about 30%, assuming a 100 year time horizon and national average estimates for leakage (which likely underestimate leakage for California). Although drivers like market conditions also affect future outcomes, California’s current policy targets do not appear to require early retirement for utility generation assets, though up to about two gigawatts of extant in-state merchant capacity might be affected. Under current policy, new generating assets must either comply with the 100% clean electricity standard by 2045 or stop selling in California before the end of their expected useful life.

Understanding of tri-reforming of methane over Ni/Mg/Al hydrotalcite-derived catalyst for CO2 utilization from flue gases from natural gas-fired power plants

Abstract Tri-reforming of methane was examined over Ni/Mg/Al hydrotalcite-derived catalyst for CO2 utilization directly from simulated flue gas mixtures from natural gas-fired power plants. This catalyst showed promising results for the studied experimental conditions, revealing the following order of CH4 conversion: TRM3 (75.9 %)

Same-plant trends in capacity factor and heat rate for US power plants, 2001–2018

This note uses electricity generator level 2001–2018 US capacity, generation, and heat input data to evaluate trends in same-plant capacity factor (how much plants run) and heat rate (how efficiently plants run) as plants age. Based on compound annual growth rates for capacity factor and, for thermal plants, heat rate, and based on the subset of US plants that have been operating since 2010 or earlier, same-plant capacity factors increased slightly, and heat rates decreased slightly, between 2001–2018 (weighted average based on 2018 plant capacity). Trends vary by region, fuel, and plant age. Notably, US natural gas-fired power plants tended to run more, and more efficiently, as they aged, while coal-fired power plants tended to run less, and less efficiently. Potential drivers include relative plant age, policy, financial competitiveness, and an anticipated tendency for plant operators to react to the effects of equipment aging with maintenance, repair, replacement, and optimization. These observations can inform committed emissions-based research, which requires making assumptions about how plant operational characteristics change (or do not) as they age.

Early retirement of power plants in climate mitigation scenarios

International efforts to avoid dangerous climate change aim for large and rapid reductions of fossil fuel CO2 emissions worldwide, including nearly complete decarbonization of the electric power sector. However, achieving such rapid reductions may depend on early retirement of coal- and natural gas-fired power plants. Here, we analyze future fossil fuel electricity demand in 171 energy-emissions scenarios from Integrated Assessment Models (IAMs), evaluating the implicit retirements and/or reduced operation of generating infrastructure. Although IAMs calculate retirements endogenously, the structure and methods of each model differ; we use a standard approach to infer retirements in outputs from all six major IAMs and—unlike the IAMs themselves—we begin with the age distribution and region-specific operating capacities of the existing power fleet. We find that coal-fired power plants in scenarios consistent with international climate targets (i.e. keeping global warming well-below 2 °C or 1.5 °C) retire one to three decades earlier than historically has been the case. If plants are built to meet projected fossil electricity demand and instead allowed to operate at the level and over the lifetimes they have historically, the roughly 200 Gt CO2 of additional emissions this century would be incompatible with keeping global warming well-below 2 °C. Thus, ambitious climate mitigation scenarios entail drastic, and perhaps un-appreciated, changes in the operating and/or retirement schedules of power infrastructure.

A new concept for generating mechanical work from gas permeation

Large amounts of energy are available from gas concentration gradients in thermal power plant exhaust. For example, the energy potential of carbon dioxide and water vapor gradients from flue gas and cooling towers of coal-fired and natural gas-fired power plants represents 1–2% of the plant's overall capacity. In this paper, we introduce a novel membrane-based gas permeation process for using concentration gradients of gas mixture to generate useful mechanical work in the form of compressed gas flow. The concept is experimentally validated using a simple binary gas mixture of nitrogen and water vapor with commercially available polydimethylsiloxane membranes. Power density from water vapor flux of 57 mW/m2 and power density from net gas flux of 11.5 mW/m2 are observed under relatively conservative laboratory test conditions. Fundamental transport dynamics are modelled and used to simulate the response of the system to membrane properties and feed concentrations, and up to 600 mW/m2 is reported for the cases considered. The possibility of recovering energy from exhaust gases may open up new opportunities for improving power plant efficiency and sustainability.

Cooperative carbon capture and steam regeneration with tetraamine-appended metal-organic frameworks.

Natural gas has become the dominant source of electricity in the United States, and technologies capable of efficiently removing carbon dioxide (CO2) from the flue emissions of natural gas-fired power plants could reduce their carbon intensity. However, given the low partial pressure of CO2 in the flue stream, separation of CO2 is particularly challenging. Taking inspiration from the crystal structures of diamine-appended metal-organic frameworks exhibiting two-step cooperative CO2 adsorption, we report a family of robust tetraamine-functionalized frameworks that retain cooperativity, leading to the potential for exceptional efficiency in capturing CO2 under the extreme conditions relevant to natural gas flue emissions. The ordered, multimetal coordination of the tetraamines imparts the materials with extraordinary stability to adsorption-desorption cycling with simulated humid flue gas and enables regeneration using low-temperature steam in lieu of costly pressure or temperature swings.

Dynamic Optimal Dispatch of Energy Systems with Intermittent Renewables and Damage Model

With the increasing penetration of intermittent renewable energy sources into the grid, there is a growing need for process systems-based strategies that integrate dispatchable and variable energy systems for supplying the demand while maintaining grid reliability. The proposed framework corresponds to a dynamic mixed-integer linear programming optimization approach that integrates coal-fired and natural gas-fired power plants, NaS batteries for energy storage, and solar/wind energy to supply the demand. This optimization approach considers an economic goal and constraints to provide power balance while maintaining the overall damage of the natural gas combined cycle (NGCC) power plant drum under a maximum stress as well as avoiding the overheating of the NGCC superheater and reheater. Renewable curtailment levels are also retained at minimum levels. Case studies are analyzed considering different loads and renewable penetration levels. The results show that the demand was met for all cases. Grid flexibility was mostly provided by the NGCC, while the batteries were used sparingly. In addition, considering a CO2 equivalent analysis, the environmental performance was intrinsically connected to grid flexibility and the level of renewable penetration. Stress analysis results reinforced the necessity for an equipment health-related constraint.

Parametric Process Design and Economic Analysis of Post-Combustion CO2 Capture and Compression for Coal- and Natural Gas-Fired Power Plants

For the envisaged large number of commercial-scale carbon capture and storage (CCS) projects that are to be implemented in the near future, a number of issues still need to be resolved, the most prominent being the large capital and operational costs incurred for the CO2 capture and compression process. An economic assessment of the capture and compression system based on optimal design data is important for CCS deployment. In this paper, the parametric process design approach is used to optimally design coal and natural gas monoethanolamine (MEA)-based post-combustion CO2 absorption–desorption capture (PCC) and compression plants that can be integrated into large-scale 550 MW coal-fired and 555 MW natural gas combined cycle (NGCC) power plants, respectively, for capturing CO2 from their flue gases. The study then comparatively assesses the energy performance and economic viabilities of both plants to ascertain their operational feasibilities and relative costs. The parametric processes are presented and discussed. The results indicate that, at 90% CO2 capture efficiency, for the coal PCC plant, with 13.5 mol.% CO2 in the inlet flue gas, at an optimum liquid/gas ratio of 2.87 kg/kg and CO2 lean loading of 0.2082 mol CO2/mol MEA, the CO2 avoidance cost is about $72/tCO2, and, for the NGCC PCC plant, with 4.04 mol.% CO2 in the inlet flue gas, at an optimum liquid/gas ratio of 0.98 kg/kg and CO2 lean loading of 0.2307 mol CO2/mol MEA, the CO2 avoidance cost is about $94/tCO2.