A techno-economic analysis of the application of continuous staged-combustion and flameless oxidation to the combustor design in gas turbines

The impact of NO_x reduction technologies upon a gas turbine power station has been investigated using the ECLIPSE process simulator. Technical, environmental and economic assessments were performed, based upon a model of the simple cycle gas turbine, fuelled by natural gas.The technologies assessed were: a) selective catalytic reduction (SCR); b) continuous staged air combustion (COSTAIR); and c) flameless oxidation method (FLOX).The SCR method produced a 90% reduction of NO_x emissions, at an additional penalty to the electricity cost of 0.19–0.20 p/kWh, over the base case of simple cycle with standard combustor.The COSTAIR method reduced 80.4% of NO_x emissions, at an additional electricity cost of 0.03–0.04 p/kWh, over the base case; but 0.16–0.17 p/kWh less than the SCR method at a slightly higher level of NO_x emissions.The FLOX method generated 92.3% less of NO_x emissions, at an additional electricity cost of 0.08–0.11 p/kWh, over the base case; but 0.09–0.11 p/kWh less than the SCR method at a lower level of NO_x emissions.A sensitivity analysis of the Break-Even Selling Price (BESP) of electricity and the Specific Investment (SI) versus the cost of different burner systems shows that the SCR system had the highest values for BESP and SI; and the COSTAIR system had the lowest.The results show that the use of these non-standard burners could offer an effective method of reducing NO_x emissions considerably for simple cycle gas turbine power plants with minimal effect on system capital cost and electricity selling price, and were also cheaper than using SCR.     

Panel discussion and symposium: Nonfood uses of coconut oil: Where are we headed?

Coconut oil prices will exert much influence on synthetic fatty acid commercialization; if domestic oil prices maintain at 12–13￠/lb, demand for coco acids and derivatives could triple during the next three years; however, at an oil price of 22–24￠/lb, about 90% of domestic research and development on lauric acid products would be dropped. Synthetic fatty acids could hold the market if they can be commercialized near present prices. Proportionally higher food uses will be evident for coconut oil for the next several years. Increased demand for short chain (C₅–C₉) acids in high temperature synthetic lubricants, estimated to grow from the present 25 million lb/year to 50 million lb/year by 1973, will exert an increased demand. Conducted at the AOCS Meeting, San Francisco, April 1969.     

Design and analysis of a diesel processing unit for a molten carbonate fuel cell for auxiliary power unit applications

Fuel cell-based auxiliary power units (APUs) are a promising technology for meeting global energy needs in an environmentally friendly way. This study uses diesel containing sulfur components such as dibenzothiophene (DBT) as a feed. The sulfur tolerance of molten carbonate fuel cell (MCFC) modules is not more than 0.5 ppm, as sulfur can poison the fuel cell and degrade the performance of the fuel cell module. The raw diesel feed in this study contains 10 ppm DBT, and its sulfur concentration should be reduced to 0.1 ppm. After desulfurization, the feed goes through several unit operations, including steam reforming, water-gas shift, and gas purification. Finally, hydrogen is fed to the fuel cell module, where it generates 500 kW of electrical energy. The entire process, with 52% and 89% fuel cell and overall system efficiencies, respectively, is rigorously simulated using Aspen HYSYS, and the results are input into a techno-economic analysis to calculate the minimum electricity selling price (MESP). The electricity cost for this MCFC-based APU was calculated as 1.57$/kWh. According to predictions, the cost reductions for fuel cell stacks will afford electricity selling prices of 1.51$/kWh in 2020 and 1.495$/kWh in 2030. Based on a sensitivity analysis, the diesel price and capital cost were found to have the strongest impact on the MESP.     

Pressurized Operation of a Planar Solid Oxide Cell Stack

Solid oxide cells (SOCs) can be operated either as fuel cells (SOFC) to convert fuels to electricity or as electrolyzers (SOEC) to convert electricity to fuels such as hydrogen or methane. Pressurized operation of SOCs provide several benefits on both cell and system level. If successfully matured, pressurized SOEC based electrolyzers can become more efficient both energy‐ and cost‐wise than PEM and Alkaline systems. Pressurization of SOFCs can significantly increase the cell power density and reduce the size of auxiliary components. In the present study, a SOC stack was successfully operated at pressures up to 25 bar. The pressure dependency of the measured current‐voltage (I–V) curves and impedance spectra on the SOC stack are analyzed and the relation between various system parameters and pressure is derived. With increasing pressure the open circuit voltage (OCV) and the reaction kinetics (electrode performance) increases for thermodynamic and kinetic reasons, respectively. Further, the summit frequency of the gas concentration impedance arc and the pressure difference across the stack and heat exchangers is seen to decrease with increasing pressure following a power‐law expression. Finally a durability test was conducted at 10 bar.     

Optimization of energy usage for fleet‐wide power generating system under carbon mitigation options

This article presents a fleet‐wide model for energy planning that can be used to determine the optimal structure necessary to meet a given CO₂ reduction target while maintaining or enhancing power to the grid. The model incorporates power generation as well as CO₂ emissions from a fleet of generating stations (hydroelectric, fossil fuel, nuclear, and wind). The model is formulated as a mixed integer program and is used to optimize an existing fleet as well as recommend new additional generating stations, carbon capture and storage, and retrofit actions to meet a CO₂ reduction target and electricity demand at a minimum overall cost. The model was applied to the energy supply system operated by Ontario power generation (OPG) for the province of Ontario, Canada. In 2002, OPG operated 79 electricity generating stations; 5 are fueled with coal (with a total of 23 boilers), 1 by natural gas (4 boilers), 3 nuclear, 69 hydroelectric and 1 wind turbine generating a total of 115.8 TWh. No CO₂ capture process existed at any OPG power plant; about 36.7 million tonnes of CO₂ was emitted in 2002, mainly from fossil fuel power plants. Four electricity demand scenarios were considered over a span of 10 years and for each case the size of new power generation capacity with and without capture was obtained. Six supplemental electricity generating technologies have been allowed for: subcritical pulverized coal‐fired (PC), PC with carbon capture (PC+CCS), integrated gasification combined cycle (IGCC), IGCC with carbon capture (IGCC+CCS), natural gas combined cycle (NGCC), and NGCC with carbon capture (NGCC+CCS). The optimization results showed that fuel balancing alone can contribute to the reduction of CO₂ emissions by only 3% and a slight, 1.6%, reduction in the cost of electricity compared to a calculated base case. It was found that a 20% CO₂ reduction at current electricity demand could be achieved by implementing fuel balancing and switching 8 out of 23 coal‐fired boilers to natural gas. However, as demand increases, more coal‐fired boilers needed to be switched to natural gas as well as the building of new NGCC and NGCC+CCS for replacing the aging coal‐fired power plants. To achieve a 40% CO₂ reduction at 1.0% demand growth rate, four new plants (2 NGCC, 2 NGCC+CCS) as well as carbon capture processes needed to be built. If greater than 60% CO₂ reductions are required, NGCC, NGCC+CCS, and IGCC+CCS power plants needed to be put online in addition to carbon capture processes on coal‐fired power plants. The volatility of natural gas prices was found to have a significant impact on the optimal CO₂ mitigation strategy and on the cost of electricity generation. Increasing the natural gas prices resulted in early aggressive CO₂ mitigation strategies especially at higher growth rate demands. © 2009 American Institute of Chemical Engineers AIChE J, 2009     

Optimal coupling of waste and concentrated solar for the constant production of electricity over a year

In this article, a biogas-based Brayton cycle is integrated with a concentrated solar power facility. The gas turbine hot flue gas and the molten salts are used to generate steam for the regenerative Rankine cycle. The process model is solved as a nonlinear optimization problem within a multiperiod scheme to decide on the contribution of the energy resources and the operating conditions of the facility to meet a certain demand of power over a year mitigating the absence of solar availability. The steam turbine is responsible for power production while the gas turbine works mainly as a combustion chamber. In the South of Spain, an excess of biogas is available during summer yielding a production cost of electricity of 0.17 €/kWh with an investment of 380 M€ for a production facility of 25 MW. This plant is not yet economic.     

A novel hybrid feedstock to liquids and electricity process: Process modeling and exergoeconomic life cycle optimization

This article proposes a novel hybrid low‐rank coal (LRC)/biomass/natural gas process for producing liquid fuels and electricity. The hybrid process highlights coexistence of indirect and direct liquefaction technologies, cogasification of char and biomass, and corefinery of LRC syncrude and Fischer–Tropsch syncrude. A process simulation based on detailed chemical kinetics is present to illustrate its feasibility. In addition, we propose an exergoeconomic life cycle optimization framework that seeks to maximize the primary exergy saving ratio, primary total overnight cost saving ratio, life cycle waste emissions avoidance ratio, and primary levelized cost saving ratio by comparing the proposed hybrid process to its reference stand‐alone subsystems. From the results, we can determine four optimal designs which yield competitive breakeven oil prices ranging from $1.87/GGE to $2.13/GGE. © 2014 American Institute of Chemical Engineers AIChE J, 60: 3739–3753, 2014     

Greenhouse gas emissions of bioenergy from agriculture compared to fossil energy for heat and electricity supply

Increasing the use of bioenergy is one promising option to reduce greenhouse gas emissions. Hence it is important to know the greenhouse gas emissions of bioenergy systems in comparison to fossil fuel systems. A life cycle analyses of biomass and fossil fuel energy systems is made to compare the overall greenhouse gas emission of both systems for heat and electricity supply. Different bioenergy systems to supply electricity and heat from agriculture are analysed for the Austrian situation in 2000. Total emissions of greenhouse gases (CO₂, N₂O, CH₄) along the fuel chain, including land use change and by-products, are calculated. The systems taken into consideration are different conversion technologies and different fuels from agriculture. The methodology was developed within the International Energy Agency (IEA) Bioenergy Task 25 on `Greenhouse Gas Balances of Bioenergy Systems'. In this paper the results of selected bioenergy systems for heat supply and combined supply of electricity and heat shown as emission of CO₂-equivalents per kWh for bioenergy systems in comparison to fossil fuel systems, and as a percentage of CO₂-equivalent reduction. The results demonstrate that some of the bioenergy systems reduce greenhouse gas emission already because of avoided emissions of the reference biomass use and/or because of certain substitution effects of by-products. In general the greenhouse gas emissions of bioenergy systems are lower compared to the fossil systems. Therefore a significant reduction of greenhouse gases is possible by replacing fossil energy systems with bioenergy systems. This comparison should help policy makers, utilities and industry to identify effective agricultural biomass options in order to reach emission reduction targets. This revised version was published online in August 2006 with corrections to the Cover Date.     

Nationwide energy supply chain analysis for hybrid feedstock processes with significant CO2 emissions reduction

Integrating diverse energy sources to produce cost‐competitive fuels requires efficient resource management. An optimization framework is proposed for a nationwide energy supply chain network using hybrid coal, biomass, and natural gas to liquids (CBGTL) facilities, which are individually optimized with simultaneous heat, power, and water integration using 162 distinct combinations of feedstock types, capacities, and carbon conversion levels. The model integrates the upstream and downstream operations of the facilities, incorporating the delivery of feedstocks, fuel products, electricity supply, water, and CO₂ sequestration, with their geographical distributions. Quantitative economic trade‐offs are established between supply chain configurations that (a) replace petroleum‐based fuels by 100%, 75%, and 50% and (b) utilize the current energy infrastructures. Results suggest that cost‐competitive fuels for the US transportation sector can be produced using domestically available coal, natural gas, and sustainably harvested biomass via an optimal network of CBGTL plants with significant GHG emissions reduction from petroleum‐based processes. © 2012 American Institute of Chemical Engineers AIChE J, 2012     

Hybrid energy storage system based on supercapacitors and Li-ion batteries

Energy storage systems (ESS) have a wide spectrum of functions. They must provide power quality, shaving of load change, coordination of distributed power systems, bulk energy storage, and end-user reliability, e.g., uninterrupted power supply. In present paper the configuration and design of experimental ESS based on both Li-ion batteries and supercapacitors have been proposed. Such a hybrid energy storage system (HESS) includes three main components: Li-ion batteries, supercapacitors, and grid interconnection consisting of two invertors and control and monitoring system. Energy storage capacity of developed HESS prototype is 100 kWh, nominal power—100 kW, peak power—200 kW. HESS was created and tested within the experimental facility also including 1.5 MW gas turbine power plant, 200 kW controllable active and reactive loads, and control and measurement system. Experimental results showed that HESS successfully provides the following advantages: (i) suppression of voltage, current, and frequency disturbances in the grid; (ii) compensation of reactive power in the circuit; and (iii) uninterrupted power supply. Cost analysis of proposed hybrid system has also been carried out. In comparison with battery ESS without supercapacitors, HESS showed longer life time, lower cost, and higher peak power.     

Fabrication and operational experiences of a 6 kW molten carbonate fuel cell stack

An MCFC stack consisting of 20 unit cells with an effective electrode area of 3,000 cm₂ was prepared and operated to verify the performance and reliability of the cells. All the porous cell components such as anode, cathode and matrix including electrolyte sheets were manufactured by the tape casting method. Hard-rail type separator made with AISI 316 L stainless steel was used for separating fuel and oxidant gases and conducting electricity between unit cells as well. When fuel gas (H₂: CO₂: H₂O = 72: 18: 10) and oxidant gas (Air: CO₂ = 70: 30) were supplied at a flow rate of 40% utilization to the stack at 650 °C, the output power of the stack was measured as 7.6 kW at its peak time. This was much higher than the design value of 6 kW. In addition to this high performance, the standard deviation of cell voltage among 20 unit cells was a mere 3 mV. The stack showed little performance decay up to 1,800 hours of operation time. After an unexpected thermal cycle due to the failure of the pre-heater for fuel gas around 2,000 hours, however, the decay rate became larger accordingly with operating time. The total operation time reached 5,600 hours including 4,800 hours under load in which a total of 23,202 kWh was generated. The evaluation of the stack was quite satisfactory in general except for the difficulty in temperature control under full load. This paper was presented at the 8th APCChE (Asia Pacific Confederation of Chemical Engineering) Congress held at Seoul between August 16 and 19, 1999.     

车用燃料电池关键材料技术研发应用进展

车用燃料电池系统成本的不断降低和电堆耐久性能的提高促进了燃料电池汽车的快速发展。燃料电池堆是车用燃料电池系统的核心单元,电催化剂、质子交换膜和气体扩散层是制造燃料电池堆的基本材料,决定了电堆的成本和耐久性能。本文从应用角度对国内外电催化剂、质子交换膜和气体扩散层制造技术的应用发展进行了回顾,分析了国内发展燃料电池电催化剂、质子交换膜和气体扩散层制造技术的重要性和国内产业化水平落后的原因,提出了发展的建议,为这些关键材料加快国产化提供参考,以期尽快提高国产燃料电池堆耐久性能、降低制造成本。     

The Benefits of Small Quantities of Nitrogen in the Oxygen Feed to Ozone Generators

This paper reports the ozone generation in pulsed multichannel dielectric barrier discharge. The influence of nitrogen addition (0.1%–10%) on ozone concentration and ozone generation efficiency in nitrogen–oxygen gas mixtures is studied. Results show that adding 0.1% N₂ would not seriously increase the ozone production. Meanwhile, 1% N₂ content exhibits the highest ozone production efficiency in low SIE (J/L, defined as the ratio of power to gas flow rate) region (0–200 J/L) while adding 0.3% N₂ would lead to the highest ozone generation efficiency in high SIE region (300–800 J/L). The increase of ozone production induced by N₂ addition is more significant in low SIE region compared with that in high SIE region. At 100 J/L, ozone production efficiency increases 26.9% to 201.6 g/kWh with 1% N₂ addition when compared with that in oxygen. At 18 J/L, the observed maximum ozone generation efficiency reaches 252 g/kWh at 1.3 g/Nm³ with 1% N₂ addition. An increase of ozone production can be obtained with 0.3%–2% N₂ addition in all explored SIE ranges.     

Technical and economic analysis of solvent-based lithium-ion electrode drying with water and NMP

Processing lithium-ion battery (LIB) electrode dispersions with water as the solvent during primary drying offers many advantages over N-methylpyrrolidone (NMP). An in-depth analysis of the comparative drying costs of LIB electrodes is discussed for both NMP- and water-based dispersion processing in terms of battery pack $/kWh. Electrode coating manufacturing and capital equipment cost savings are compared for water vs. conventional NMP organic solvent processing. A major finding of this work is that the total electrode manufacturing costs, whether water- or NMP-based, contribute about 8–9% of the total pack cost. However, it was found that up to a 2?×?reduction in electrode processing (drying and solvent recovery) cost can be expected along with a $3–6?M savings in associated plant capital equipment (for a plant producing 100,000 10-kWh Plug-in Hybrid Electric Vehicle (PHEV) batteries) using water as the electrode solvent. This paper shows a different perspective in that the most important benefits of aqueous electrode processing actually revolve around capital equipment savings and environmental stewardship and not processing cost savings.     

Recovery of CO2 from flue gas using an electrochemical membrane

A novel process has been designed for the economic production of very pure carbon dioxide from flue gas. Using a molten carbonate fuel cell stack as an electrically-driven membrane concentrator, a portion of the carbon dioxide in the flue gas, along with some oxygen, is emitted as a product stream. The oxygen is recycled to enrich the flue gas entering the concentrator. Preliminary economics appear favorable, with carbon dioxide produced at $21 per ton, this product is, however, in a binary mixture with oxygen and must be separated for final use, this mixture is suitable for standard means of separation. The cost is sensitive to the cost of electricity and the installed cost of the fuel-cell stack, as can be seen in Table 1. The projected cost, however, is significantly below the typical $70 per ton sales price for carbon dioxide, so that the process could be viable at higher electricity and equipment charges.     

On the integration of CO2 capture with coal-fired power plants: A methodology to assess and optimise solvent-based post-combustion capture systems

Amine and other liquid solvent CO₂ capture systems capture have historically been developed in the oil and gas industry with a different emphasis to that expected for fossil fuel power generation with post-combustion capture. These types of units are now being adapted for combustion flue gas scrubbing for which they need to be designed to operate at lower CO₂ removal rates - around 85-90% and to be integrated with CO₂ compression systems. They also need to be operated as part of a complete power plant with the overall objective of turning fuel into low-carbon electricity.The performance optimisation approach for solvents being considered for post-combustion capture in power generation therefore needs to be updated to take into account integration with the power cycle and the compression train. The most appropriate metric for solvent assessment is the overall penalty on electricity output, rather than simply the thermal energy of regeneration of the solvent used.Methodologies to evaluate solvent performance that have been reported in the literature are first reviewed. The results of the model of a steam power cycle integrated with the compression system focusing on key parameters of the post-combustion capture plant - solvent energy of regeneration, solvent regeneration temperature and desorber pressure - are then presented. The model includes a rigorous thermodynamic integration of the heat available in the capture and compression units into the power cycle for a range of different solvents, and shows that the electricity output penalty of steam extraction has a strong dependence on solvent thermal stability and the temperature available for heat recovery. A method is provided for assessing the overall electricity output penalty (EOP), expressed as total kWh of lost output per tonne of CO₂ captured including ancillary power and compression, for likely combinations of these three key post-combustion process parameters. This correlation provides a more representative method for comparing post-combustion capture technology options than the use of single parameters such as solvent heat of regeneration.     

Integrated Adsorbent Process Optimization for Minimum Cost of Electricity Including Carbon Capture by a VSA Process

Assessing vacuum swing adsorption (VSA) technology for postcombustion CO₂ capture and concentration (CCC) using energy and productivity indicators are useful, but its ultimate test must be the cost of electricity from a power plant including CCC. Here, our integrated optimization platform (Khurana and Farooq, AlChE J. 2017;63:2987–2995) developed earlier to simultaneously obtain the optimum adsorbent and process conditions is extended to include a comprehensive costing framework. The framework is complete with scale-up design and column scheduling, and compliant with National Energy Technology Laboratory costing guidelines for carbon capture. This is the ultimate tool that enables integrated optimization to minimize the cost of electricity. The Shell Cansolv CO₂ capture system is used as the benchmark for evaluating the best performance of two VSA cycles for two adsorbents. The operating conditions and isotherm shapes necessary to achieve the lowest possible cost of electricity for the two VSA cycles are also presented to facilitate designing or searching the best adsorbent for CCC. © 2018 American Institute of Chemical Engineers AIChE J, 65: 184–195, 2019     

70kt/a硫铁矿制酸废热发电装置运行情况小结

介绍广西岑溪市佳宝矿业有限公司70 kt/a硫铁矿制酸装置配套8.5 t/h废热锅炉和1 500 kW汽轮发电机组运行情况。废热锅炉生产3.82 MPa、450℃中压蒸汽供汽轮机发电,发电量达1 200 kWh/h。除满足企业自身用电外,有300 kWh/h送入外电网,大大降低了硫酸装置生产成本,创造了较好的经济效益和社会效益。