IGCC系统中空气气化炉与氧气气化炉的对比研究

目前国内对IGCC的研究形成一股热潮,发表了不少研究结果和文章,但都集中在纯氧气流床气化工艺。日本三菱公司近二十年来致力于空气气化IGCC系统的研究,其示范电厂将于2007年投运,但国内对这方面的信息和了解不多。本文基于文献和作者对开发空气气化IGCC系统的三菱长崎研究所的访问和调研,采用Aspen Plus软件,对此系统作了详细分析,并与Shell气化炉和IGCC系统作了对比,得出了一些有益的结论。     

生物质燃煤耦合发电技术应用现状及未来趋势

国务院"十三五"提出控制温室气体排放目标后,如何较大幅度地降低CO2排放成为燃煤电厂面临的巨大挑战之一。按照现有的煤电技术,仅通过提高煤电效率降低煤耗和CO2排放强度是非常困难的。燃煤电厂采用生物质与煤电耦合发电技术,是当前最可行的降低碳排放的措施。文章针对生物质替代煤炭发电应用的现状,介绍了现阶段燃煤耦合生物质发电的几种方式,及其在现有电厂中的应用情况,并简要分析其优缺点。结合耦合技术自身特性、经济成本及中国国情,提出生物质气化耦合发电是未来的发展趋势。     

大型煤气化技术在IGCC电站中的应用现状

介绍了国内外已投运燃煤IGCC电站所采用的气化技术的基本情况及气化炉在IGCC电站运行中获得的主要经验,总结了世界上处于建设或规划中的主要燃煤IGCC电站的基本情况和采用的气化技术。对燃煤IGCC电站气化技术应用现状的综述可为将来IGCC电站项目选择煤气化技术提供参考和借鉴。     

气化参数对IGCC系统中气化炉性能的影响

首先单独对气化炉出口合成气成分含量进行核算,计算结果与文献基本吻合.然后建立200 MW级整体煤气化联合循环(IGCC)系统模型,对基本参数下的IGCC系统进行计算,得出整个系统的性能参数.最后对不同气化参数温度、水煤浆浓度、氧气浓度、O/C比的气化炉性能及其整个IGCC系统效率进行比较,分析不同气化条件下的合成气成分体积含量、冷煤气效率、有效气(CO+H2)体积含量、比氧耗、比煤耗及整个IGCC系统效率的变化.结果表明:提高水煤浆的浓度,有利于提高气化炉的冷煤气效率;气化温度对IGCC系统性能影响较大;提高氧气浓度有利于提高气化冷气效率和系统的效率,本系统对应的最佳O/C比为1.02左右.     

天津将建造绿色电厂

据（GasTurbine World）2008年1—2月刊报道，华能集团领导的绿色发电公司计划设计、开发和运行一座燃煤的IGCC电厂，该电厂位于天津滨海新开发区的临港（Lingang）工业园附近。第一阶段将建造250MW的IGCC示范电厂，以开发和试验大型商业规模电厂CO2近零排放所需要的脱碳和CO2封存技术。     

钙基吸收剂捕集火电机组烟气中CO_2的热力性能分析

针对燃煤火电机组减排CO2的问题,以某1 000MW超临界机组为例,建立了钙基吸收剂循环煅烧/碳酸化法捕集CO2的系统流程,得到了CO2捕集率与弛放率、钙碳物质的量比和气固分离效率等参数的关系,基于Aspen Plus软件分析了关键参数对系统性能的影响.结果表明:捕集90%CO2和100%SO2使得机组的发电热效率比设计值降低了8.73个百分点;随着弛放率的提高或气固分离效率的降低,固体循环物料质量流量、煅烧能耗和发电热效率均下降;随着CO2捕集率的提高,固体循环物料质量流量和煅烧能耗呈逐渐增大的趋势,但发电热效率则降低.     

生物质直燃和混燃发电环境效益分析

利用生物质代替矿物燃料发电可以减少CO2和SO2的排放量。确定了燃煤机组CO2和SO2排放量基准,建立生物质发电的CO2和SO2的排放量模型及其偏差模型;计算不同发电方式下CO2和SO2的生成量及减排量;分析了气化炉气化效率对生物质发电CO2和SO2生成量的影响。结果表明,提高生物质发电效率和气化效率可以显著降低CO2和SO2的排放;生物质发电的环境效益明显优于燃煤发电,而生物质气化合成气与煤混燃发电的环境效益优于生物质直燃发电。     

氧气纯度对两段式煤粉气化炉气化特性的影响

降低氧气纯度可以显著地降低空分能耗,对于提高IGCC电厂整体效率有着积极的意义.不过氧气纯度过低(低于95％),偏离设计工况参数,会对IGCC两段式干煤粉气化炉内温度、合成气组分以及气化效率造成一定的影响.为了探究氧气纯度对于IGCC两段式干煤粉气化炉内气化特性的影响,采用流程仿真软件Aspen Plus和数值模拟软件...     

IGCC系统关键部件的选择及其对电厂整体性能的影响——(1)气化炉篇

采用GT PRO软件对配备不同气化炉的IGCC整体系统进行建模研究,对目前几种代表性气化技术对IGCC电厂的技术和经济性能的影响进行了分析和对比.结果表明:进料方式对系统效率和单位造价影响很大.可为IGCC系统中气化炉的选择提供参考.     

煤炭地下气化联合循环发电系统及煤气热值的调配方法

叙述了煤炭地下气化联合循环发电系统（UGCC）的流程,提出了UGCC系统中煤气热值的调配方法。通过对UGCC项目的分析,与传统煤粉锅炉发电（PFPG）及整体煤气化联合循环发电（IGCC）的对比,指出,UGCC与PFPG相比,可降低45%的CO2排放量,而成本仅增加了5%;与IGCC相比,UGCC项目的CO2排放量降低了20%,发电成本降低了34.4%。     

CO2 control technology effects on IGCC plant performance and cost

As part of the USDOE's Carbon Sequestration Program, an integrated modeling framework has been developed to evaluate the performance and cost of alternative carbon capture and storage (CCS) technologies for fossil-fueled power plants in the context of multi-pollutant control requirements. This paper uses the newly developed model of an integrated gasification combined cycle (IGCC) plant to analyze the effects of adding CCS to an IGCC system employing a GE quench gasifier with water gas shift reactors and a Selexol system for CO₂ capture. Parameters of interest include the effects on plant performance and cost of varying the CO₂ removal efficiency, the quality and cost of coal, and selected other factors affecting overall plant performance and cost. The stochastic simulation capability of the model is also used to illustrate the effect of uncertainties or variability in key process and cost parameters. The potential for advanced oxygen production and gas turbine technologies to reduce the cost and environmental impacts of IGCC with CCS is also analyzed.     

Hydrogen production from coal gasification for effective downstream CO2 capture

The coal gasification process is used in commercial production of synthetic gas as a means toward clean use of coal. The conversion of solid coal into a gaseous phase creates opportunities to produce more energy forms than electricity (which is the case in coal combustion systems) and to separate CO₂ in an effective manner for sequestration. The current work compares the energy and exergy efficiencies of an integrated coal-gasification combined-cycle power generation system with that of coal gasification-based hydrogen production system which uses water-gas shift and membrane reactors. Results suggest that the syngas-to-hydrogen (H₂) system offers 35% higher energy and 17% higher exergy efficiencies than the syngas-to-electricity (IGCC) system. The specific CO₂ emission from the hydrogen system was 5% lower than IGCC system. The Brayton cycle in the IGCC system draws much nitrogen after combustion along with CO₂. Thus CO₂ capture and compression become difficult due to the large volume of gases involved, unlike the hydrogen system which has 80% less nitrogen in its exhaust stream. The extra electrical power consumption for compressing the exhaust gases to store CO₂ is above 70% for the IGCC system but is only 4.5% for the H₂ system. Overall the syngas-to-hydrogen system appears advantageous to the IGCC system based on the current analysis.     

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.     

The Development of Coke Carried—Heat Gasification Coal—Fired Combined Cycle

INTRODUCTIONCoal is the main energy resource in China. Morethan 70% electric power is generated by coal-firedpower plants in the country. It will be continued to bedominant in next century. The need for new electricgenerating capacity is growing along with the growthof Chinese economy. Meanwhile, environment pollution caused by coal combustion is also concerned here.So, searching new technologies to burn coal cleanlyand efficiently to produce power is a very importanttask to the energy r…     

Life cycle GHG assessment of fossil fuel power plants with carbon capture and storage

The evaluation of life cycle greenhouse gas emissions from power generation with carbon capture and storage (CCS) is a critical factor in energy and policy analysis. The current paper examines life cycle emissions from three types of fossil-fuel-based power plants, namely supercritical pulverized coal (super-PC), natural gas combined cycle (NGCC) and integrated gasification combined cycle (IGCC), with and without CCS. Results show that, for a 90% CO₂ capture efficiency, life cycle GHG emissions are reduced by 75–84% depending on what technology is used. With GHG emissions less than 170 g/kWh, IGCC technology is found to be favorable to NGCC with CCS. Sensitivity analysis reveals that, for coal power plants, varying the CO₂ capture efficiency and the coal transport distance has a more pronounced effect on life cycle GHG emissions than changing the length of CO₂ transport pipeline. Finally, it is concluded from the current study that while the global warming potential is reduced when MEA-based CO₂ capture is employed, the increase in other air pollutants such as NO_x and NH₃ leads to higher eutrophication and acidification potentials.     

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

Using four times as much coal in 2050 for electricity production need not degrade air quality or increase greenhouse gas emissions. Current SO_x and NO_x emissions from the power sector could be reduced from 12 to less than 1 and from 5 to 2 million tons annually, respectively, using advanced technology. While direct CO₂ emissions from new power plants could be reduced by over 87%, life cycle emissions could increase by over 25% due to the additional coal that is required to be mined and transported to compensate for the energy penalty of the carbon capture and storage technology. Strict environmental controls push capital costs of pulverized coal (PC) and integrated coal gasification combined cycle (IGCC) plants to $1500–1700/kW and $1600–2000/kW, respectively. Adding carbon capture and storage (CCS) increases costs to $2400–2700/kW and $2100–3000/kW (2005 dollars), respectively. Adding CCS reduces the 40–43% efficiency of the ultra-supercritical PC plant to 31–34%; adding CCS reduces the 32–38% efficiency of the GE IGCC plant to 27–33%. For IGCC, PC, and natural gas combined cycle (NGCC) plants, the carbon dioxide tax would have to be $53, $74, and $61, respectively, to make electricity from a plant with CCS cheaper. Capturing and storing 90% of the CO₂ emissions increases life cycle costs from 5.4 to 11.6 cents/kWh. This analysis shows that 90% CCS removal efficiency, although being a large improvement over current electricity generation emissions, results in life cycle emissions that are large enough that additional effort is required to achieve significant economy-wide reductions in the US for this large increase in electricity generation using either coal or natural gas.     

Shell coal IGCCS with carbon capture: Conventional gas quench vs. innovative configurations

The Shell coal integrated gasification combined cycle (IGCC) based on the gas quench system is one of the most fuel flexible and energy efficient gasification processes because is dry feed and employs high temperature syngas coolers capable of rising high pressure steam. Indeed the efficiency of a Shell IGCC with the best available technologies is calculated to be 47–48%. However the system looses many percentage points of efficiency (up to 10) when introducing carbon capture. To overcome this penalty, two approaches have been proposed. In the first, the expensive syngas coolers are replaced by a “partial water quench” where the raw syngas stream is cooled and humidified via direct injection of hot water. This design is less costly, but also less efficient. The second approach retains syngas coolers but instead employs novel water–gas shift (WGS) configurations that requires substantially less steam to obtain the same degree of CO conversion to CO₂, and thus increases the overall plant efficiency. We simulate and optimize these novel configurations, provide a detailed thermodynamic and economic analysis and investigate how these innovations alter the plant’s efficiency, cost and complexity.     

A proposed scheme for coal fired combined cycle and its concise performance

For IGCC, the primary investment is too high due to the demand of high gasification efficiency. For PFBCC, the thermal efficiency is too low due to the relatively low turbine inlet temperature and the hot working medium of the gas turbine is not easy to clean. A new scheme is proposed for coal fired combined cycle to overcome the main drawbacks of IGCC and PFBCC. The research targets are developing a new cycle construction of coal fired combines cycle to raise the efficiency and reduce the primary investment. Actually, the new scheme is a synthesis of some existing proposals. It adopts partial gasification to reduce the primary investment of the gasification equipment. The un-gasified surplus solid is then feed to a pressurized fluidized bed boiler, but adopting Curtiss Wright type external combustion to lower the ash content in the working medium. The gas fuel from the partial gasifier is combusted in a top combustor to further increase the working medium temperature. An extremely concise performance estimation method for the new scheme and its equations is proposed in order to easily understand the basic physical meaning of the new system. Some typical calculations based on this concise method are given. Then, a more detailed computation is accomplished with Aspen Plus code. The basic feasibility of this scheme is proven to be favorable. The efficiency is higher than the existing coal fired IGCC plants. The advantage of the new scheme comes from the better utilization of coal energy. Almost all the energy of coal is first utilized in the top cycle, and then the bottom cycle, just like the gas fueled combined cycle does. The primary investment is lower than the ordinary IGCC due to the lack of air separation unit and the adoption of partial gasification. The ash content is much lower than that of the existing PFBCC plants. If no any harmful ash in working medium is required, the atmospheric fluidized bed can be applied rather than the pressurized fluidized bed. A similar proposal with atmospheric fluidized bed and its performance estimation are also given. However, its efficiency will be lower than the pressurized fluidized bed scheme.     

Performance evaluation of integrated gasification solid oxide fuel cell/gas turbine systems including carbon dioxide capture

In this study, system layouts for integrated gasification solid oxide fuel cell/gas turbine (IG-SOFC/GT) systems were proposed and their performance was comparatively evaluated. A baseline IGCC was simulated, and the calculation models were validated. Based on the IGCC system, two IG-SOFC/GT system layouts with different SOFC thermal management methods were established, and their performance was analyzed. The IG-SOFC/GT systems were found to produce much higher power and better efficiency than the IGCC. With regard to SOFC thermal management, the exit gas recirculation scheme showed better performance than the cathode heat exchange scheme. The impact of CO₂ capture was investigated in both the IGCC and IG-SOFC/GT systems, and the penalties in power output and efficiency due to pre-combustion CO₂ capture were found to be milder in the IG-SOFC/GT systems than in the IGCC. An IG-SOFC/GT system adopting oxy-combustion-based CO₂ capture was proposed, and its thermal efficiency was predicted to be sensibly higher than the system with pre-combustion CO₂ capture. Its net power output was predicted to be less than that of the system with pre-combustion technology, but was still much larger than that of the IGCC with pre-combustion CO₂ capture.