Long term creep properties and microstructure of SUPER304H,TP347HFG and HR3C for A-USC boilers

Abstract

SUPER304H (18Cr–9Ni–3Cu–Nb–N; ASME CC2328) and TP347HFG (18Cr–12Ni–Nb; ASME SA213) have been developed for high strength oxidation resistant steel tubes to operate at high steam temperatures and pressures. The longest creep rupture tests performed to date (600°C for 85 426 h for SUPER304H; 700°C for 55 858 h for TP347HFG) showed that the stable strength and microstructure were retained, with very little formation of σ-phase compared with conventional austenitic stainless steels and no other brittle phases. The alloy HR3C (25Cr–20Ni–Nb–N; ASME CC2115) has been developed for the high strength and high corrosion resistant steel tubes used in recent ultrasupercritical (USC) boilers with steam temperatures of ～600°C. The longest creep test conducted to date (700°C, 69 MPa for 88 362 h) confirmed a stable creep strength and microstructure at 600–800°C. Superheater and reheater tubes of these alloys installed in the Eddystone No.1 USC power plant since 1991 have been removed and investigated. Updated long term creep rupture properties of the steels and microstructural changes during service are reported. Three steel tubes have been successfully applied as standard materials for superheater and reheater tubes in newly built USC boilers.     

Hybrid clean energy technologies for power generation from sub-bituminous coals: a case of 250 MW unit

Major re-thinking is required on the conventional pulverized fuel conversion route of power generation wherein the ash and mineral burden in coals is transported through the entire flow passage of the boiler. For high-ash fuels, this has to be contained and the boiler must be clear of all mineral matter. The two independent clean coal candidate technologies for efficiency enhancement and emission controls – ultra-supercritical cycle (USC) and integrated gasification with combined cycle (IGCC) – both have limitations in adaptation to high-ash coals. While the USC is limited by the steam temperature up to 600°C (commercial scale) (700°C pilot scale) and boiler tube failure risks, IGCC is limited to high-quality fuels like diesel, naphtha, etc. (commercial scale) and high-grade coals (pre-commercial scale). The hybridization of the two technologies in their current form (ultra-supercritical cycle with gasification conversion) and carbon capture and storage (CCS) together with solar energy (solar thermal and solar photovoltaic) integration presents possibilities for immediate application to low-grade sub-bituminous coals to achieve the clean technology goals. The energy efficiency of the hybrid system is around 44.45%, which is of the order of the USC with pulverized coal combustion. But the predominant benefits of a clean operation override. The benefits are reduction in CO₂ generation from 0.86 to 0.70 kg/kWh and reduction in ash expelled from 0.20–0.24 to 0.12–0.18 kg/kWh besides elimination of dispersion of ash around the power station and facilitating CCS.     

Serbian energy development based on lignite production

Lignite, as an energy resource, is a mainstay of electricity generation in the Republic of Serbia. Installed capacity of lignite power plants represents 68% of the total installed capacity of Electric Power Industry of Serbia, the only company in Serbia, which manages electricity generation. In the future, with the increase in demand for electricity, both in Serbia and in Europe, we should expect more extensive and effective utilization of lignite as the main energy potential. In addition, due to increased emissions of CO₂, NO_X and other pollutants, the Republic of Serbia must accelerate the implementation of flexible mechanisms of Kyoto Protocol and the guidelines set by the European Union. Lignite in the future will retain its existential importance in the electricity generation in the Republic of Serbia.     

Distributed power generation via gasification of biomass and municipal solid waste: A review

The access to electricity has increased worldwide, growing from 60 million additional consumers per year in 2000–2012 to 100 million per year in 2012–2016. Despite this growth, approximately 675 million people will still lack access to electricity in 2030, indicating that electricity demand will continue to increase. Unfortunately, traditional large fossil power technologies based on coal, oil and natural gas lead to a major concern in tackling worldwide carbon dioxide emissions, and nuclear power remains unpopular due to public safety concerns. Distributed power generation utilizing CO₂-neutral sources, such as gasification of biomass and municipal solid wastes (MSW), can play an important role in meeting the world energy demand in a sustainable way. This review focuses on the recent technology developments on seven power generation technologies (i.e. internal combustion engine, gas turbine, micro gas turbine, steam turbine, Stirling engine, organic rankine cycle generator, and fuel cell) suitable for distributed power applications with capability of independent operation using syngas derived from gasification of biomass and MSW. Technology selection guidelines is discussed based on criteria, including hardware modification required, size inflexibility, sensitivity to syngas contaminants, operational uncertainty, efficiency, lifetime, fast ramp up/down capability, controls and capital cost. Major challenges facing further development and commercialization of these power generation technologies are discussed.     

中国燃煤发电节能技术的发展及前景

我国一次能源结构决定了发电以煤电为主的基本格局,当前国内火力发电行业需要解决的两大突出问题是高能耗和严重的环境污染。2009年全国发电机组平均供电煤耗341g/(kW.h),高于330g/(kW.h)的国际平均水平。大力发展新型高效节能性火力发电技术,对进一步提高我国火力发电机组的发电效率,减少燃煤大气污染物排放具有十分重要的意义。发达国家正积极发展更高参数的超超临界火力发电技术(600℃/700℃),我国也把"超(超)临界燃煤发电技术"列入"863计划"。可以预见,在我国近中期电力事业的发展中,会把发展更高参数的超临界技术作为火电建设的主要方向。IGCC发电技术是未来煤炭能源系统的基础,被公认为是世界上最清洁的燃煤发电技术。随着煤气化技术和燃气轮机技术的不断发展和进步,IGCC将朝着大容量、高效率、低排放的方向发展。大型直接空冷发电技术是解决我国西北部富煤贫水地区火力发电的有效手段,以2×600MW机组为例,空冷机组比湿冷机组节水约80%左右。通过对火力发电机组各系统的集成与优化,可在现有超超临界机组技术不变的情况下,最大限度地利用余热回收,提高整个机组的发电效率,从而降低煤耗,实现机组在运行过程中的节能。     

3‐E analysis of advanced power plants based on high ash coal

The objective of the study is to identify the ‘best’ possible power plant configuration based on 3‐E (namely energy, exergy, and environmental) analysis of coal‐based thermal power plants involving conventional (subcritical (SubC)) and advanced steam parameters (supercritical (SupC) and ultrasupercritical (USC)) in Indian climatic conditions using high ash (HA) coal. The analysis is made for unit configurations of three power plants, specifically, an operating SubC steam power plant, a SupC steam power plant, and the AD700 (advanced 700°C) power plant involving USC steam conditions. In particular, the effect of HA Indian coal and low ash (LA) reference coal on the performance of these power plants is studied. The environmental impact of the power plants is estimated in terms of specific emissions of CO₂, SO_x, NO_x, and particulates. From the study, it is concluded that the maximum possible plant energy efficiency under the Indian climatic conditions using HA Indian coal is about 42.3% with USC steam conditions. The results disclose that the major energy loss is associated with the heat rejection in the cooling water, whereas the maximum exergy destruction takes place in the combustor. Further, the sliding pressure control technique of load following results in higher plant energy and exergy efficiencies compared to throttle control in part‐load operation. Copyright © 2009 John Wiley & Sons, Ltd.     

Future materials needs of industrial gas turbines

Abstract

Although there are many similarities between aircraft and industrial gas turbines, the operating environment for the industrial engine has placed different demands on materials development to enable industrial engines to operate continuously at full load on a wide range of gaseous and liquid fuels with high levels of reliability and availability. The demand for improved engine efficiency continues to drive cycle pressures and temperatures higher and this trend is expected to continue. Over the past 15 years, a major development theme for industrial gas turbines (IGTs) has been the reduction of NO_x emissions to improve air quality and this is now mandatory in many areas of the world. With a continuing need for fossil fuels and diminishing reserves, applications in power generation and in the oil and gas sectors increasingly require engines to operate in hostile environments and on poorer quality fuels. A new challenge is the requirement to reduce greenhouse gas emissions. The gas turbine forms an integral part of many of the zero emissions power plant concepts under development for large scale power generation and in smaller sizes is being developed to operate on renewable fuels. Materials and coating selection approaches to meet these diverse and often conflicting requirements are reviewed and the materials developments considered necessary for the next generation of IGTs are outlined.     

Determining marginal electricity for near-term plug-in and fuel cell vehicle demands in California: Impacts on vehicle greenhouse gas emissions

California has taken steps to reduce greenhouse gas emissions from the transportation sector. One example is the recent adoption of the Low Carbon Fuel Standard, which aims to reduce the carbon intensity of transportation fuels. To effectively implement this and similar policies, it is necessary to understand well-to-wheels emissions associated with distinct vehicle and fuel platforms, including those using electricity. This analysis uses an hourly electricity dispatch model to simulate and investigate operation of the current California grid and its response to added vehicle and fuel-related electricity demands in the near term. The model identifies the “marginal electricity mix” - the mix of power plants that is used to supply the incremental electricity demand from vehicles and fuels - and calculates greenhouse gas emissions from those plants. It also quantifies the contribution from electricity to well-to-wheels greenhouse gas emissions from battery-electric, plug-in hybrid, and fuel cell vehicles and explores sensitivities of electricity supply and emissions to hydro-power availability, timing of electricity demand (including vehicle recharging), and demand location within the state. The results suggest that the near-term marginal electricity mix for vehicles and fuels in California will come from natural gas-fired power plants, including a significant fraction (likely as much as 40%) from relatively inefficient steam- and combustion-turbine plants. The marginal electricity emissions rate will be higher than the average rate from all generation - likely to exceed 600 gCO₂ equiv. kWh⁻¹ during most hours of the day and months of the year - and will likely be more than 60% higher than the value estimated in the Low Carbon Fuel Standard. But despite the relatively high fuel carbon intensity of marginal electricity in California, alternative vehicle and fuel platforms still reduce emissions compared to conventional gasoline vehicles and hybrids, through improved vehicle efficiency.     

Critical factors in the design,operation and economics of coal gasification plants: The case of the flexible co-production of hydrogen and electricity

Power generation from wind and solar sources is growing in importance, but requires back up from fossil fuel plants, greatly compromising fossil fuel plant economics. This includes the economics of most proposed IGCC–Hypogen type plant schemes which are intended to produce hydrogen and electricity, as well as capturing CO₂. IGCC–Hypogen plants, however, that are able to change the ratio of hydrogen to electricity will be able to operate at maximum capacity all of the time, switching from power generation to hydrogen production as the demand for these two forms of energy changes. Because of the need to provide power to the IGCC–Hypogen ancillaries, some hydrogen from the plant will have to be utilised to supply some of this power. A preliminary economic study examines how the plant could produce electricity and hydrogen at competitive prices.     

Efficiency enhancement of pressurized oxy‐coal power plant with heat integration

The oxy‐coal combustion with carbon dioxide capture and sequestration is among the promising clean coal technologies for reducing CO₂ emissions. Because most of oxy‐coal power plants need to cope with energy penalties from air separation and CO₂ compressor units, the pressurized combustion is added to reduce the electricity demand for the CCS system, and the waste heat of the pressurized flue gas is recovered by the heat integration technique to increase the power generation from steam turbines. Finally, the efficiency enhancement of a 100 MW_e‐scale power plant is successfully validated by Aspen Plus simulation. Copyright © 2014 John Wiley & Sons, Ltd.     

Potential for flexible operation of pulverised coal power plants with CO2 capture

Abstract

Fossil-fired plants play an important role in electricity networks as mid-merit plants that can respond relatively quickly to changes in supply and demand. As a consequence, they are required to operate over a wide output range and play an important role in maintaining the quality and security of electricity supply by providing response and reserve capacity. Carbon dioxide capture and storage (CCS) has been identified as a critical technology for future electricity generation from coal in the UK. Although the performance of CCS schemes where CO₂ capture plants are operated at full load has been considered in detail, part load performance is less well understood. Developing a better understanding of part load performance of plants operating with CO₂ capture is crucial in determining their suitability to operate as mid-merit plants. This paper presents an assessment of the potential impact of adding post-combustion CO₂ capture at pulverised-coal power plants. Estimated performance of steam cycles working with post-combustion CO₂ capture plant are presented at full and part load, leading to performance predictions for pulverised-coal power plants operated over a range of loads and with varying levels of CO₂ capture. By adjusting the operation of the capture plant, as well as the boiler/steam cycle, an extended range of operation can be achieved including lower minimum stable generation levels and additional 'pumped storage like' capacity for times of high demand. For example, plant operators can alter the energy penalty for the CO₂ capture plant with an associated change in plant output by reducing the level of CO₂ capture. This can allow extra electricity to be generated and sold when electricity prices are high. With solvent storage it should also be possible to increase power plant output for a number of hours, but without associated increases in CO₂ emissions.     

Production of useful energy from solid waste materials by steam gasification

A steam gasification processes is an energy conversion pathway through which organic materials are converted to useful energy. In spite of the high energy content in organic waste materials, they have been mostly disposed of in landfills, which causes harmful environmental issues such as methane emissions and ground water pollution and contaminations. In this sense, organic solid waste materials are regarded as alternative resources for conversion to useful energy in the steam gasification process. In this study, three types of waste materials – municipal solid waste (MSW), used tires and sewage sludge – were used to generate syngas through the gasification process in a 1000 °C steam atmosphere. The syngas generation rates and its chemical compositions were measured and evaluated over time to determine the characteristics and dynamics of the gasification process. Also, carbon conversion, and mass and energy balances are presented which demonstrates the feasibility of steam gasification as a waste conversion pathway. The results show that the syngas contains high concentrations of H₂, around 41–55% by volume. The syngas generation rate was found to depend on the carbon content in the feedstock regardless of the types of input materials. Comparing to the hydrogen production from water splitting that requires extremely high temperatures at around 1500 °C, hydrogen production by steam gasification of organic materials can be regarded as equally effective but requires lower system temperatures. Copyright © 2016 John Wiley & Sons, Ltd.     

Energy performance and numerical optimization of a screw expander–based solar thermal electricity system in a wide range of fluctuating operating conditions

This paper provides fundamental principles to study the thermodynamic performance of a new screw expander–based solar thermal electricity plant. While steam turbines are generally used in direct steam generation solar systems without admitting fluid in two-phase conditions, steam screw expanders, as volumetric machines, can convert thermal to mechanical energy also by expanding liquid-steam mixtures without a decline in efficiency. In effect, steam turbines are not as competitive as screw expanders when the net power is smaller than 2 MW and for low-grade heat sources. The solar electricity generation system proposed in this paper is based on the steam Rankine cycle: Water is used as both working fluid and storage, parabolic trough collectors are used as a thermal source, and screw expanders are used as power machines. Since screw expanders can operate at off-design working conditions in several situations when installed in direct steam generation solar plants, studying expander performance under fluctuating working situations is a crucial issue. The main aim of the present paper is to establish a thermodynamic model to study the energetic benefits of the proposed power system when off-design operating conditions and variable solar radiation occur. This entails, first and foremost, developing overexpansion and underexpansion numerical models to describe the polytropic expansion phase, which considers all the losses affecting performance of the screw expander under real operating conditions. To assess the best operating conditions and maximum efficiency of the whole power system at part-load working conditions under fluctuating solar radiations, parametric optimization is then improved in a wide range of variable working conditions, assuming condensation pressures of water increasing from 0.1 to 1 bar, under an evaporation temperature rising from 170°C to 300°C.     

A review on the pattern of electricity generation and emission in Indonesia from 1987 to 2009

The level of energy demand plays a fundamental role in today's society. It is a vital input in supporting the physical and social development of a country, as well as national economic growth. Looking at the energy demand scenario in present time, the global energy consumption is likely to grow faster than the population growth across the world. Like any other energy sectors, electricity demand has significantly increased in Indonesia over the past years. Currently, there are six types of power plants in the country. The main sources of electrical energy are generated using the gas turbines, steam turbines, combined cycles, geothermal, diesel engine and hydro-powers. Most of Indonesia's power plants are using fossil fuel for electricity generation. Substantial growth in domestic energy demand, however, would be a major challenge for Indonesia's energy supply sector in the future. Over the past decade, thermal power plants generated about 86.69% of electricity and about 13.31% was generated by renewable energy such as hydro-power and geothermal in 2009. The purpose of this study is to chronicle and show a clear view of 23 years trend of Indonesia's electricity generation industry. Furthermore, the capacity of power generation installed and electricity generation from 1987 to 2009 has been gathered for this study. The total pollutant emissions and emission per unit electricity generation for each type of power plants have been also calculated using emission factors. Also, the pattern of electricity generation and emission has been presented. The results show that the implementation and contribution of combined cycle power plants should be increased together with renewable energy and natural gas which are recommended to reduce greenhouse gas emission.     

Physicochemical properties of Ba(Zr,Ce)O3-δ-based proton-conducting electrolytes for solid oxide fuel cells in terms of chemical stability and electrochemical performance

To enhance the power generation efficiency of solid oxide fuel cells (SOFCs), the use of proton-conducting solid solutions of doped BaCeO₃ and doped BaZrO₃, with formulas of the Ba(Zr_0.1Ce_0.7Y_0.1X_0.1)O_3-δ (X = Ga, Sc, In, Yb, Gd), was investigated as SOFCs electrolyte materials with respect to both chemical stability and electrical conductivity. Regarding chemical stability, the weight changes of each material were measured under a CO₂ atmosphere in a temperature range of 1200 °C–600 °C.Higher chemical stability was observed for dopant ions with smaller radii. Regarding conductivity, the dependences of the total conductivities on the oxygen partial pressure and temperature were measured in the temperature range of 600 °C–900 °C. In each material, the total conductivity was proportional to the oxygen partial pressure to the 1/4 power at high oxygen partial pressures, as previously observed for accepter-doped proton-conducting perovskite-type oxides. The derived conductivities for each type of charge carrier showed that the hole conductivity increased with the ionic conductivity. Based on the measured data, the leakage current densities were calculated for SOFCs with each of the investigated electrolyte materials and an area-specific resistance of 0.383 Ωcm². BZCYSc showed the minimum leakage current density, with a value of 3.7% of the external current density at 600 °C. Therefore, this study indicates that BZCYSc is the most desirable among the materials investigated for use as SOFCs electrolyte. However, for BZCYSc to be used as SOFCs electrolyte material, a protective layer is needed to ensure its chemical stability.     

Optimizing 100%‐renewable grids through shifting residential water‐heater load

A low‐carbon electricity supply for Australia was simulated, and the installed capacity of the electrical grid was optimized by shifting the electricity demand of residential electric water heaters (EWHs). The load‐shifting potential of Australia was estimated for each hour of the simulation period using a nationwide aggregate EWH load model on a 90 × 110 raster grid. The electricity demand of water heaters was shifted from periods of low renewable resource and high demand to periods of high renewable resource and low demand, enabling us to effectively reduce the installed capacity requirements of a 100%‐renewable electricity grid. It was found that by shifting the EWH load by just 1 hour, the electricity demand of Australia could be met using purely renewable electricity at an installed capacity of 145 GW with a capacity factor of 30%, an electricity spillage of 20%, and a generation cost of 15.2 ¢/kWh. A breakdown of the primary energy sources used in our scenario is as follows: 43% wind, 29% concentrated solar thermal power, and 20% utility photovoltaic. Sensitivity analysis suggested that further reduction in installed capacity is possible by increasing the load‐shifting duration as well as the volume and insulation level of the EWH tank.     

Fuel cell power trains for road traffic

Legal regulations, especially the low emission vehicle (LEV) laws in California, are the driving forces for more intensive technological developments with respect to a global automobile market. In the future, high efficient vehicles at very low emission levels will include low temperature fuel cell systems (e.g., polymer electrolyte fuel cell (PEFC)) as units of hydrogen-, methanol- or gasoline-based electric power trains. In the case of methanol or gasoline/diesel, hydrogen has to be produced on-board using heated steam or partial oxidation reformers as well as catalytic burners and gas cleaning units. Methanol could also be used for direct electricity generation inside the fuel cell (direct methanol fuel cell (DMFC)). The development potentials and the results achieved so far for these concepts differ extremely. Based on the experience gained so far, the goals for the next few years include cost and weight reductions as well as optimizations in terms of the energy management of power trains with PEFC systems. At the same time, questions of fuel specification, fuel cycle management, materials balances and environmental assessment will have to be discussed more intensively. On the basis of process engineering analyses for net electricity generation in PEFC-powered power trains as well as on assumptions for both electric power trains and vehicle configurations, overall balances have been carried out. They will lead not only to specific energy demand data and specific emission levels (CO₂, CO, VOC, NO_x) for the vehicle but will also present data of its full fuel cycle (FFC) in comparison to those of FFCs including internal combustion engines (ICE) after the year 2005. Depending on the development status (today or in 2010) and the FFC benchmark results, the advantages of balances results of FFC with PEFC vehicles are small in terms of specific energy demand and CO₂ emissions, but very high with respect to local emission levels.     

Achieving emissions reduction through oil sands cogeneration in Alberta’s deregulated electricity market

The province of Alberta faces the challenge of balancing its commitment to reduce CO₂ emissions and the growth of its energy-intensive oil sands industry. Currently, these operations rely on the Alberta electricity system and on-site generation to satisfy their steam and electricity requirements. Most of the on-site generation units produce steam and electricity through the process of cogeneration. It is unclear to what extent new and existing operations will continue to develop cogeneration units or rely on electricity from the Alberta grid to meet their energy requirements in the near future. This study explores the potential for reductions in fuel usage and CO₂ emissions by increasing the penetration of oil sands cogeneration in the provincial generation mixture. EnergyPLAN is used to perform scenario analyses on Alberta’s electricity system in 2030 with a focus on transmission conditions to the oil sands region. The results show that up to 15–24% of CO₂ reductions prescribed by the 2008 Alberta Climate Strategy are possible. Furthermore, the policy implications of these scenarios within a deregulated market are discussed.     

Assessment of cleaner electricity generation technologies for net CO2 mitigation in Thailand

The choice of electricity generation technologies not only directly affects the amount of CO₂ emission from the power sector, but also indirectly affects the economy-wide CO₂ emission. It is because electricity is the basic requirement of economic sectors and final consumptions within the economy. In Thailand, although the power development plan (PDP) has been planned for the committed capacity to meet the future electricity demand, there are some undecided electricity generation technologies that will be studied for technological options. The economy-wide CO₂ mitigations between selecting cleaner power generation options instead of pulverized coal-thermal technology of the undecided capacity are assessed by energy input–output analysis (IOA). The decomposition of IOA presents the fuel-mix effect, input structural effect, and final demand effect by the change in technology of the undecided capacity. The cleaner technologies include biomass power generation, hydroelectricity and integrated gasification combined cycle (IGCC). Results of the analyses show that if the conventional pulverized coal technology is selected in the undecided capacity, the economy-wide CO₂ emission would be increased from 223 million ton in 2006 to 406 million ton in 2016. Renewable technology presents better mitigation option for replacement of conventional pulverized coal technology than the cleaner coal technology. The major contributor of CO₂ mitigation in cleaner coal technology is the fuel mix effect due to higher conversion efficiency. The demand effect is the major contributor of CO₂ mitigation in the biomass and hydro cases. The embedded emission in construction of power plant contributes to higher CO₂ emission.     

Capacity commitment and price volatility in a competitive electricity market

The long lead time required to add new capacity in the electricity generation industry means that daily demands are necessarily served by capacity already installed. However, in a competitive market, even if the installed capacity was designed to serve the projected demands, frequent surpluses and occasional full utilization inevitably lead to price volatility. This paper develops a two-stage model of the generation market in which capacity construction occurs in stage 1, before demand realization, and price determination occurs in stage 2, when the equilibrium price ensures that the realized demand does not exceed the installed capacity. We show that price volatility and price spikes are inevitable, and that while price capping can mitigate high and volatile prices, it causes unmet demands and reduction in system reliability. This paper accentuates the interdependence among generating capacity, price volatility and service reliability, a primary cause of concern in the debate on electricity market reform.