水煤气沸腾煤气化炉荣获江苏省“佳利奖”金奖

江苏工学院专利事务所代理的“水煤气沸腾煤气化炉”发明专利，荣获江苏省第三届优秀专利实施项目“佳利奖”金奖。“水煤气沸腾煤气化炉”由王同章教授等发明。已在江阴、河北、沈阳、景德镇、云南、苏州、广西等地实施，实施金额达701万元。该炉以水蒸汽为气化剂，使用0～6mm的粉煤，制取中热值煤气，其煤气成份为：H2＞55％，Co＜25％，CH42～5％，CO210～15％，O2＜0．4，N2＜5％；煤的灰熔点≥1200℃；煤气热值9000～12290KJ／Nm3；气化强度1000Kg煤／m‘h。这种煤气不仅是理想的化工原料气，而且是理想的民用煤气，为广大中小城…     

人工煤气

<正>由煤、焦炭等固体燃料或重油等液体燃料经干馏、汽化或裂解等过程所制得的气体,统称为人工煤气。按照生产方法,一般可分为干馏煤气和汽化煤气(发生炉煤气、水煤气、半水煤气等)。人工煤气的主要成分为烷烃、烯烃、芳烃、CO和H2等可燃气体,并含有少量的CO2和N2等不可燃气体,热值为16 000 kJ/m3~24 000 kJ/m3。     

循环流化床煤气-蒸汽联产炉

介绍一种“八五”攻关新开发的循环流化床煤气-蒸汽联产炉工艺、试验结果及设计特点。它生产蒸汽及中热值煤气。煤气可供工业生产用也可民用。 联产炉工艺是在循环流化床燃烧锅炉基础上发展起来的。它有一个流化床燃烧室和一个热解室。燃烧室和热解室之间有热物料循环,并组成有机整体。煤在进入燃烧室之前先经热解室热解气化、产生煤气,剩余的半焦进入燃烧室燃烬。由于采用循环流化床燃烧技术,因而其燃烧效率可>98％。煤气化所需热量由循环热物料提供、热解过程不需氧气和空气,因而,有较高煤气热值和转换效率、热效率。 介绍一台10t/h蒸汽产量的工业用煤气-蒸汽联产炉工艺及其预测结果;还介绍一台35t/h蒸汽产量的联产炉设计方案及其预测结果。     

煤制气

<正>以煤为原料经过加压气化后,脱硫提纯制得的含有可燃组分的气体。根据加工方法、煤气性质和用途分为:煤气化得到的是水煤气、半水煤气、空气煤气(或称发生炉煤气),这些煤气的发热值较低,故又统称为低热值煤气;煤干馏法中焦化得到的气体称为焦炉煤气,属于中热值煤气,可供城市作民用燃料。煤气中的CO     

人工煤气

由煤、焦炭等固体燃料或重油等液体燃料经干馏、汽化或裂解等过程所制得的气体,统称为人工煤气。按照生产方法,一般可分为干馏煤气和汽化煤气（发生炉煤气、水煤气、半水煤气等）。人工煤气的主要成分为烷烃、烯烃、芳烃、CO和H2等可燃气体,并含有少量的CO2和N2等不可燃气体,热值为16 000 kJ/m3～24 000 kJ/m3。     

氧量对天然焦蒸汽气化特性的影响研究

在小型流化床(50mm、高1600mm)实验装置上对沛城煤矿天然焦-蒸汽气化反应进行实验研究,考察蒸汽中掺入氧气,共同作为气化介质对气化反应产气量、碳转化率、煤气热值和煤气组分等因素的影响,同时与ASPENPLUS软件对其气化过程的模拟结果进行了对比。实验中,天然焦试样量0.2kg/h,蒸汽量1.05kg/h,气化温度900℃,实验结果表明:气化介质中氧量明显影响天然焦蒸汽气化特性。随着氧含量的增加,初始阶段(0～0.2L/min)煤气产量提高了1.76倍,碳转化率提高了1.94倍,两者均显著增加;随着氧量的进一步增加(0.2～1.0L/min),其增加幅度趋缓,产气量增加1.16倍,碳转化率增加1.34倍。煤气中有效气体(H2+CO+CH4)的体积分数和煤气热值均持续减少,有效气体份额从76.9%下降到54.3%,煤气热值从9.01MJ/m3减少到6.34MJ/m3,而CO2体积分数增加明显,从23.1%增加到37.3%。Aspen模拟结果与实验结果基本一致,具有实际指导意义。     

煤制气

以煤为原料经过加压气化后,脱硫提纯制得的含有可燃组分的气体。根据加工方法、煤气性质和用途分为：煤气化得到的是水煤气、半水煤气、空气煤气（或称发生炉煤气）,这些煤气的发热值较低,故又统称为低热值煤气;煤干馏法中焦化得到的气体称为焦炉煤气,属于中热值煤气,可供城市作民用燃料。     

气化煤气

<正>固体燃料的气化是热化学过程。煤可在高温时伴用空气(或O2)和水蒸气为气化剂,经过氧化、还原等化学反应,制成以CO和O2为主的可燃气体,采用这种生产方式生产的煤气,称为气化煤气。气化煤气按其生产方法(气化剂)的不同,主要可分为以下几种:a)混合发生炉煤气是生产混合发生炉     

煤气化特性分析

煤的分级转化技术不仅可以实现煤炭资源的高效利用,还可以有效解决煤燃烧过程中的环境污染问题。文中基于煤的分级转化,在小型流化床煤气化试验台上研究了富氧条件下汽煤比、氧煤比对床层温度、煤气成分、煤气热值等参数的影响,并与富氧气化的结果进行对比分析,研究表明:随着汽煤比的增加,煤气中CO和H2的含量显著增加;随着氧煤比的增加,煤气的热值显著提高;在富氧/水蒸气条件下产生的煤气的热值远高于富氧条件下产生的煤气的热值。     

煤转化为洁净燃料技术

正煤的气化技术,有常压气化和加压气化2种,它是在常压或加压条件下,保持一定温度,通过气化剂(空气、氧气和蒸汽)与煤炭反应生成煤气,煤气中主要成分是一氧化碳、氢气、甲烷等可燃气体。用空气和蒸汽做气化剂,煤气热值低;用氧气做气化剂,煤气热值高。煤在气化中可脱硫除氮,排去灰渣,因此,煤气就是洁净燃料了。     

Anthracite pretreatment for high-performance direct carbon solid oxide fuel cell — A green pathway for power generation

Coal-fueled direct carbon solid oxide fuel cell (DC-SOFC) is a very attractive electrochemical conversion device. However, coal contains a certain amount of ash, such as Al, Si, S, etc., which are toxicants for SOFC components. To solve the above problem, anthracite is pyrolyzed at 600 °C to obtain semi-coking coal results in better cell performance. The results show that the higher carbon gasification oxidation activity of semi-coking coal is due to the higher amount of fixed carbon and catalyst. Therefore, more fuel gas (CO) is available in the anode chamber for the Boudouard reaction. Also, the electrochemical performance of both coals as DC-SOFC fuel was compared using La_0·4Sr_0·6Co_0·2Fe_0·7Nb_0·1O_3-δ (LSCFN) as anode. The maximum power density (MPD) of the DC-SOFC with semi-coking coal is 596 mW cm⁻² at 850 °C, much higher than that of the SOFC using anthracite (396 mW cm⁻²) as the fuel. Furthermore, at the same fuel content, the cell fueled with semi-coking coal has a longer discharge time (30 h), which shows a better stability.     

Expansion of multi-jet bed with large particles

An experimental investigation under cold conditions was made to study the effect of some operating parameters on average porosity in a 1·1 m long, 0·35 m wide and 1·2 m high multi-jet bed (Ingnifluid type) with air flow rate varying from 1200 m³ h⁻¹ to 3500 m³ h⁻¹ and total bed inventory from 26 kg to 45 kg. Rice, peas and one rice-pea mixture (mass ratio 70–30) of sizes 1·95 mm, 5.0 mm and 2·44 mm, respectively, were used as bed material to simulate coal particles. Average bed porosity was estimated based on pressure drop along the bed height. It was found to be in the range 0·58 to 0·72, 0·51 to 0·62 and 0·55 to 0·65 for rice, peas and rice-pea mixture, respectively. One mathematical correlation has been developed from the experimental results to predict average porosity as a function of air flow rate, total bed inventory and particle size used. This correlation is developed for hydrodynamic modelling of an industrial multi-jet combustor.     

Design and application of a novel coal-fired drum boiler using saline water in heavy oil recovery

In this paper, the design and operation of a novel coal-fired circulating fluidized bed (CFB) drum boiler that can generate superheated steam using saline water were introduced. The natural circulation water dynamics with a drum was adopted instead of the traditional once-through steam generator (OTSG) design, so that superheated steam can be generated for the better performance of the steam assisted gravity drainage (SAGD) technology in heavy oil recovery. The optimized staged evaporation method was proposed to further decrease the salinity of water in the clean water section of the boiler. The evaporating pipes of the salted water section were rearranged in the back pass of the boiler, where the heat load is low, to further improve the heat transfer safety. A CFB combustion technology was used for coal firing to achieve a uniform heat transfer condition with low heat flux. Pollutant control technologies were adopted to reduce pollutant emissions. Based on the field test, the recommended water standard for the coal-fired CFB drum boilers was determined. With the present technology, the treated recovery wastewater can be reused in steam-injection boilers to generate superheated steam. The engineering applications show that the boiler efficiency is higher than 90%, the blowdown rate is limited within 5.5%, and the superheat of steam can reach up to 30 K. Besides, the heavy oil recovery efficiency is significantly improved. Moreover, the pollutant emissions of SO₂, NO_x and dust are controlled within the ranges of 20–90 mg/(N·m³), 30–90 mg/(N·m³) and 2–10 mg/(N·m³) respectively.     

Effect of supplementary firing options on cycle performance and CO2 emissions of an IGCC power generation system

Supplementary firing is adopted in combined‐cycle power plants to reheat low‐temperature gas turbine exhaust before entering into the heat recovery steam generator. In an effort to identify suitable supplementary firing options in an integrated gasification combined‐cycle (IGCC) power plant configuration, so as to use coal effectively, the performance is compared for three different supplementary firing options. The comparison identifies the better of the supplementary firing options based on higher efficiency and work output per unit mass of coal and lower CO₂ emissions. The three supplementary firing options with the corresponding fuel used for the supplementary firing are: (i) partial gasification with char, (ii) full gasification with coal and (iii) full gasification with syngas. The performance of the IGCC system with these three options is compared with an option of the IGCC system without supplementary firing. Each supplementary firing option also involves pre‐heating of the air entering the gas turbine combustion chamber in the gas cycle and reheating of the low‐pressure steam in the steam cycle. The effects on coal consumption and CO₂ emissions are analysed by varying the operating conditions such as pressure ratio, gas turbine inlet temperature, air pre‐heat and supplementary firing temperature. The results indicate that more work output is produced per unit mass of coal when there is no supplementary firing. Among the supplementary firing options, the full gasification with syngas option produces the highest work output per unit mass of coal, and the partial gasification with char option emits the lowest amount of CO₂ per unit mass of coal. Based on the analysis, the most advantageous option for low specific coal consumption and CO₂ emissions is the supplementary firing case having full gasification with syngas as the fuel. Copyright © 2008 John Wiley & Sons, Ltd.     

Thermodynamic performance of a double-effect absorption heat-transformer using TFE/E181 as the working fluid

Trifluoroethanol(TFE)–tetraethylenglycol dimethylether (TEGDME or E181) is a new organic working-pair which is non-corrosive, completely miscible and thermally stable up to 250 °C. It is suitable for upgrading low-temperature level industrial waste-heat to a higher temperature level for reuse. In this paper, the thermodynamic performance of the double-effect absorption heat-transformer (DEAHT) using TFE/E181 as the working fluid is simulated, based on the thermodynamic properties of TFE/E181 solution. The results show that, when the temperature in the high-pressure generator exceeds 100 °C and the gross temperature lift is 30 °C, the coefficient of performance (COP) of the DEAHT is about 0.58, which is larger than the 0.48 of the single-stage absorption heat-transformer (SAHT), the increase of COP is about 20%. But it is still less than 0.64 of the DEAHT using LiBr–H₂O as the working fluid. Meanwhile, the COP of the DEAHT decreases more rapidly with increases of the absorption temperature than that for the SAHT. The range of available gross temperature-lift for the DEAHT is narrower than that of the SAHT. The higher the temperature in the high-pressure generator, the larger the gross temperature-lift could be. So the double-effect absorption heat-transformer is more suitable for being applied in those circumstances of having a higher-temperature heat-resource and when a higher temperature-lift is not needed.     

An experimental study of coal gasification

Experiments were carried out on a 2 m diameter gas generator for a ceramics factory to study the effects of air-supply pressure, steam-saturation temperature and generator-gas exit temperature on fuel heating value. A total of 64 gasification experiments was performed using a standard coal mixture. Gaseous fuels with heating values ranging from 1100 to 1400 cal/liter were obtained. The heating value of the gas could be raised by up to 27% by maintaining the three process variables close to their optimum values, i.e. air-supply pressure=43 cm of H₂O, steam-saturation temperature=55°C, and generator gas-exit temperature=160°C.     

Thermodynamic evaluation of integrated gasification combined cycle: Comparison between high‐ash and low‐ash coals

In the present study, a coal‐integrated gasification combined cycle power plant is simulated. A high‐ash coal and low‐ash coal are considered to compare the performance of the plant. The combined cycle is in typical commercial size with 450 MW capacity. The feeds are Tabas and Illinois #6 coals which approximately contain more than 30% and 10% ash and have higher heating values of 22.7 MJ/kg and 26.8 MJ/kg, respectively. Energy and exergy analyses are done by aspen plus ^® and ees , respectively. Energy analysis shows that the overall efficiencies of power plants using high‐ash and low‐ash coals are 33% and 28%, respectively. The result shows that in high‐ash case, 52 kg/s coal, 10 kg/s water, and 1050 kg/s air and in low‐ash case, 48 kg/s coal and 820 kg/s air are required for providing mentioned power, approximately. Exergy analysis shows that maximum exergy destruction is in heat recovery steam generator unit. Investigating the emissions shows that high percent of ash in the coal composition has slight effects on the IGCC pollution. Finally, from thermodynamic viewpoint, it is concluded that the high‐ash coal, like the conventional one, can be used as thermally efficient and environmentally compatible feed of IGCCs. Copyright © 2016 John Wiley & Sons, Ltd.     

The integration of hybrid hydrogen networks for refinery and synthetic plant of chemicals

Hydrogen is the core source to both refinery and synthetic plant of chemicals. Refinery consumes high purity hydrogen while synthetic plant of chemicals needs syngas consists of hydrogen and carbon oxides. As main hydrogen production technologies, industrial coal gasification and steam methane reforming based pathways generate H₂, CO and CO₂, which is actually the mixture of hydrogen and carbon oxides. Hence, the gases demand of refinery and synthetic plant of chemicals and their supply from hydrogen production can form hybrid hydrogen networks. On the basis of complementary reuse, this paper firstly proposes integration of hybrid hydrogen network for refinery and synthetic plant of chemicals. Superstructures of individual and hybrid hydrogen networks are employed as problem illustration and corresponding linear programming (LP) mathematical models are formulated. Practical refinery and synthetic plant of chemicals cases are employed to demonstrate its application. Compared with individual networks, the natural gas conservation case can recover 8660.4 Nm³·h^-1 hydrogen in purge gas, reduce 1386.6 Nm³·h^-1 CO₂ emission, equaling to reduction of 278.11 kmol·h^-1 natural gas feedstock and 14.8% of total gas production load; the coal conservation case can even waive the total coal consumption and extra 104.1 kmol·h^-1 natural gas, recover 8660.4 Nm³·h^-1 hydrogen in purge gas, reduce 5255.8 Nm³·h^-1 of CO₂ emission and decrease 21.2% of the total gas production load. Furthermore, economic evaluation is also placed to account for the economic advantage of hybrid network.     

加压流化床煤气化计算模型研究

为了探索大型加压流化床煤气化的最佳操作条件和设计参数,建立了针对加压流化床气化方式的计算模型,包括颗粒模型、气相模型、气泡模型和焓平衡模型,分析了单位给煤量、氧量和水蒸气等操作参数对碳转化率、产气量和冷煤气效率等参数的影响,并确定了给煤量的最佳操作范围.结果表明:初期碳转化率均保持在99%以上,对于相同床面积的气化炉,可通过提高反应压力来提高气化炉处理量;反应压力由1.5MPa提高到2.1MPa时(提高40%),单位煤产气量可增加34%以上;反应压力为2.1 MPa时,给煤量的最佳操作范围为2.0~2.5kg/(m2·s);氧煤比为0.6~0.7时,冷煤气效率可达到77%;生成气体的热值与水蒸气比成正比.     

Parametric techno‐economic studies of coal/biomass co‐gasification for IGCC plants with carbon capture using various coal ranks,fuel‐feeding schemes,and syngas cooling methods

Because of biomass's limited supply (as well as other issues involving its feeding and transportation), pure biomass plants tend to be small, which results in high production and capital costs (per unit power output) compared with much larger coal plants. Thus, it is more economically attractive to co‐gasify biomass with coal. Biomass can also make an existing plant carbon‐neutral or even carbon‐negative if enough carbon dioxide is captured and sequestered (CCS). As a part of a series of studies examining the thermal and economic impact of different design implementations for an integrated gasification combined cycle (IGCC) plant fed with blended coal and biomass, this paper focuses on investigating various parameters, including radiant cooling versus syngas quenching, dry‐fed versus slurry‐fed gasification (particularly in relation to sour‐shift and sweet‐shift carbon capture systems), oxygen‐blown versus air‐blown gasifiers, low‐rank coals versus high‐rank coals, and options for using syngas or alternative fuels in the duct burner for the heat recovery steam generator (HRSG) to achieve the desired steam turbine inlet temperature. Using the commercial software, Thermoflow^®, the case studies were performed on a simulated 250‐MW coal IGCC plant located near New Orleans, Louisiana, and the coal was co‐fed with biomass using ratios ranging from 10% to 30% by weight. Using 2011 dollars as a basis for economic analysis, the results show that syngas coolers are more efficient than quench systems (by 5.5 percentage points), but are also more expensive (by $500/kW and 0.6 cents/kW h). For the feeding system, dry‐fed is more efficient than slurry‐fed (by 2.2–2.5 points) and less expensive (by $200/kW and 0.5 cents/kW h). Sour‐shift CCS is both more efficient (by 3 percentage points) and cheaper (by $600/kW or 1.5 cents/kW h) than sweet‐shift CCS. Higher‐ranked coals are more efficient than lower‐ranked coals (2.8 points without biomass, or 1.5 points with biomass) and have lower capital cost (by $600/kW without using biomass, or $400/kW with biomass). Finally, plants with biomass and low‐rank coal feedstock are both more efficient and have lower costs than those with pure coal: just 10% biomass seems to increase the efficiency by 0.7 points and reduce costs by $400/kW and 0.3 cents/kW h. However, for high‐rank coals, this trend is different: the efficiency decreases by 0.7 points, and the cost of electricity increases by 0.1 cents/kW h, but capital costs still decrease by about $160/kW. Copyright © 2016 John Wiley & Sons, Ltd.