Comparative studies of augmentation in combined cycle power plants

The attractive features of a combined cycle (CC) power plant are fuel flexibility, operational flexibility, higher efficiency and low emissions. The performance of five gas turbine‐steam turbine (GT‐ST) combined cycle power plants (four natural gas based plants and one biomass based plant) have been studied and the degree of augmentation has been compared. They are (i) combined cycle with natural gas (CC‐NG), (ii) combined cycle with water injection (CC‐WI), (iii) combined cycle with steam injection (CC‐SI), (iv) combined cycle with supplementary firing (CC‐SF) and (v) combined cycle with biomass gasification (CC‐BM). The plant performance and CO₂ emissions are compared with a change in compressor pressure ratio and gas turbine inlet temperature (GTIT). The optimum pressure ratio for compressor is selected from maximum efficiency condition. The specific power, thermal efficiency and CO₂ emissions of augmented power plants are compared with the CC‐NG power plant at the individual optimized pressure ratios in place of a common pressure ratio. The results show that the optimum pressure ratio is increased with water injection, steam injection, supplementary firing and biomass gasification. The specific power is increased in all the plants with a loss in thermal efficiency and rise in CO₂ emissions compared to CC‐NG plant. Copyright © 2013 John Wiley & Sons, Ltd.     

Perspectives for the direct firing of biomass as a supplementary fuel in combined cycle power plants

An analysis of the performance of a gas turbine–steam turbine combined cycle with supplementary firing has been carried out. Natural gas is fired in the main combustor of the cycle, whereas biomass fuel is considered as the supplementary fuel. Although, supplementary firing is found to reduce the overall cycle efficiency, the low cost of biomass and the CO₂‐neutral attribute of its combustion reduce the specific fuel cost and specific CO₂ emission. The effects of pressure and temperature ratios of the topping cycle and main steam conditions of the bottoming cycle on the performance parameters of the combined cycle have been studied at different degrees of supplementary firing. The topping cycle temperature ratio is found to be the most critical parameter and its low value gives substantial advantages in lowering the fuel cost and CO₂ emission. Marginal advantages are also achieved at higher pressure ratio and better bottoming cycle main steam conditions. Copyright © 2008 John Wiley & Sons, Ltd.     

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.     

Operation window and part-load performance study of a syngas fired gas turbine

Integrated coal gasification combined cycle (IGCC) provides a great opportunity for clean utilization of coal while maintaining the advantage of high energy efficiency brought by gas turbines. A challenging problem arising from the integration of an existing gas turbine to an IGCC system is the performance change of the gas turbine due to the shift of fuel from natural gas to synthesis gas, or syngas, mainly consisting of carbon monoxide and hydrogen. Besides the change of base-load performance, which has been extensively studied, the change of part-load performance is also of great significance for the operation of a gas turbine and an IGCC plant.In this paper, a detailed mathematical model of a syngas fired gas turbine is developed to study its part-load performance. A baseline is firstly established using the part-load performance of a natural gas fired gas turbine, then the part-load performance of the gas turbine running with different compositions of syngas is investigated and compared with the baseline. Particularly, the impacts of the variable inlet guide vane, the degree of fuel dilution, and the degree of air bleed are investigated. Results indicate that insufficient cooling of turbine blades and a reduced compressor surge margin are the major factors that constrain the part-load performance of a syngas fired gas turbine. Results also show that air bleed from the compressor can greatly improve the working condition of a syngas fired gas turbine, especially for those fired with low lower heating value syngas. The regulating strategy of a syngas fired gas turbine should also be adjusted in accordance to the changes of part-load performance, and a reduced scope of constant TAT (turbine exhaust temperature) control mode is required.     

Cost and performance of fossil fuel power plants with CO2 capture and storage

CO₂ capture and storage (CCS) is receiving considerable attention as a potential greenhouse gas (GHG) mitigation option for fossil fuel power plants. Cost and performance estimates for CCS are critical factors in energy and policy analysis. CCS cost studies necessarily employ a host of technical and economic assumptions that can dramatically affect results. Thus, particular studies often are of limited value to analysts, researchers, and industry personnel seeking results for alternative cases. In this paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and current costs of fossil fuel power plants with CCS on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed for three major plant types: pulverized coal (PC) plants, natural gas combined cycle (NGCC) plants, and integrated gasification combined cycle (IGCC) systems using coal. In particular, we examine the effects of recent increases in capital costs and natural gas prices, as well as effects of differential plant utilization rates, IGCC financing and operating assumptions, variations in plant size, and differences in fuel quality, including bituminous, sub-bituminous and lignite coals. Our results show higher power plant and CCS costs than prior studies as a consequence of recent escalations in capital and operating costs. The broader range of cases also reveals differences not previously reported in the relative costs of PC, NGCC and IGCC plants with and without CCS. While CCS can significantly reduce power plant emissions of CO₂ (typically by 85–90%), the impacts of CCS energy requirements on plant-level resource requirements and multi-media environmental emissions also are found to be significant, with increases of approximately 15–30% for current CCS systems. To characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.     

Conversion of fossil and biomass fuels to electric power and transportation fuels by high efficiency integrated plasma fuel cell (IPFC) energy cycle

The IPFC is a high efficiency energy cycle, which converts fossil and biomass fuel to electricity and co-product hydrogen and liquid transportation fuels (gasoline and diesel). The cycle consists of two basic units, a hydrogen plasma black reactor (HPBR) which converts the carbonaceous fuel feedstock to elemental carbon and hydrogen and CO gas. The carbon is used as fuel in a direct carbon fuel cell (DCFC), which generates electricity, a small part of which is used to power the plasma reactor. The gases are cleaned and water gas shifted for either hydrogen or syngas formation. The hydrogen is separated for production or the syngas is catalytically converted in a Fischer–Tropsch (F–T) reactor to gasoline and/or diesel fuel. Based on the demonstrated efficiencies of each of the component reactors, the overall IPFC thermal efficiency for electricity and hydrogen or transportation fuel is estimated to vary from 70 to 90% depending on the feedstock and the co-product gas or liquid fuel produced. The CO₂ emissions are proportionately reduced and are in concentrated streams directly ready for sequestration. Preliminary cost estimates indicate that IPFC is highly competitive with respect to conventional integrated combined cycle plants (NGCC and IGCC) for production of electricity and hydrogen and transportation fuels.     

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.     

Biomass integrated gasification combined cycle power generation with supplementary biomass firing: Energy and exergy based performance analysis

A thermodynamic analysis of a Biomass Integrated Gasification Combined Cycle (BIGCC) plant has been performed based on energy and exergy balances in a proposed configuration. Combustion of supplementary biomass fuel is considered using the oxygen available in the gas turbine (GT) exhaust. The effects of pressure and temperature ratios of the GT system and the amount of fuel burned in the supplementary firing chamber on the thermal and exergetic efficiencies of the plant have been investigated. The plant efficiencies increase with the increase in both pressure and temperature ratios; however, the latter has a stronger influence than the former. Supplementary firing of biomass increases the plant efficiencies of a BIGCC plant till an optimum level of degree of firing. The other technical issues related to supplementary firing, like ash fusion in the furnace and exhaust heat loss maintaining a minimum pinch point temperature difference are accounted and finally a set of optimum plant operating parameters have been identified. The performance of a 50 MWe plant has been analyzed with the optimum operating parameters to find out equipment rating and biomass feed rates. Exergetic efficiencies of different plant equipments are evaluated to localize the major thermodynamic irreversibilities in the plant.     

The development of advanced energy technologies in Japan: IGCC: A key technology for the 21st century

Integrated coal gasification combined cycle (IGCC) power plants have been looked to as a key technology for the 21st century in order to realize high efficiency and good environmental performance for electricity generation, replacing existing coal fired power plants.Following successful completion of a 200 ton/d pilot project in Nakoso, IGCC technology development in Japan is moving from the stage of a feasibility study to a detailed study to allow final decisions for demonstration plant construction. The feasibility study, jointly conducted by the domestic electric power companies, found MHI's IGCC technology to have several advantages in efficiency and reliability. In parallel with the study, a number of R&D tests have been executed as a national project to facilitate scaling up from the pilot plant to the demonstration plant. This paper introduces the current status of the MHI's IGCC technological development.     

Performance analysis of a syngas-fed gas turbine considering the operating limitations of its components

As the need for clean coal technology grows, research and development efforts for integrated gasification combined cycle (IGCC) plants have increased worldwide. An IGCC plant couples a gas turbine with a gasification block. Various technical issues exist in designing the entire system. Among these issues, the matching between the gas turbine and the air separation unit is especially important. In particular, the operating condition of a gas turbine in an IGCC plant may be very different from that of its original design. In this study, we analyzed the impact of the use of syngas on operating conditions of the gas turbine in an IGCC plant. We evaluated the performance of a gas turbine under operating limitations in terms of compressor surge and turbine metal temperature. Although a lower degree of integration may theoretically allow higher gas turbine power output and efficiency, it causes a reduction in compressor surge margin and overheating of the turbine metal. The turbine overheating problem may be solved using several methods, such as a reduction in the firing temperature or an increase in the turbine cooling air. The latter yields a much smaller performance penalty. To achieve an acceptable margin for the compressor surge, either further reduction in the firing temperature or further increase in the coolant is required. Ventilation of some of the nitrogen generated by the air separation unit, i.e., a reduction of the nitrogen supply to the combustor, is another option. Coolant modulation yields the lowest performance penalty. Reduction of the nitrogen supply provides much greater system power output than control of the firing temperature. For nitrogen flow and firing temperature controls, there are optimal levels of integration degrees in terms of net system power output and efficiency.     

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.     

我国的燃气_蒸汽联合循环发电技术前景良好

针对我国能源结构和能源政策,指出燃气－蒸汽联合循环是提高发电效率和解决环境污染的重要途径,尤其是国际公认的最有发展前途的两种燃煤联合循环发电技术;ＩＧＣＣ和ＰＦＢＣ－ＣＣ。文中简要地介绍了这两种联合循环发电技术。     

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.     

IGCC多联产系统设备特点及其运行技术研究

IGCC发电技术是基于清洁煤气化的高效联合循环发电技术,本文通过对目前国内外燃烧天然气和IGCC发电技术的综合研究,分析了IGCC发电技术的设备特点,并结合类似IGCC燃用中低热值的联合循环机组试验研究结果,开展了IGCC发电设备的经济运行技术研究,对IGCC及其多联产机组参与电网调峰运行和掺烧备用天然气的运行技术提出了建议。     

Valuing flexibility: The case of an Integrated Gasification Combined Cycle power plant

In this paper we analyze the choice between two technologies for producing electricity. In particular, the firm has to decide whether and when to invest either in a Natural Gas Combined Cycle (NGCC) power plant or in an Integrated Gasification Combined Cycle (IGCC) power plant, which may burn either coal or natural gas. Instead of assuming that fuel prices follow standard geometric Brownian motions, here they are assumed to show mean reversion, specifically to follow an inhomogeneous geometric Brownian motion.First we consider the opportunity to invest in a NGCC power plant. We derive the optimal investment rule as a function of natural gas price and the remaining life of the right to invest. In addition, the analytical solution for a perpetual option to invest is obtained.Then we turn to the IGCC power plant. We analyse the valuation of an operating plant when there are switching costs between modes of operation, and the choice of the best operation mode. This serves as an input to evaluate the option to invest in this plant.Finally we derive the value of an opportunity to invest either in a NGCC or IGCC power plant, i.e. to choose between an inflexible and a flexible technology, respectively. Depending on the opportunity's time to maturity, we derive the pairs of coal and gas prices for which it is optimal to invest in NGCC, in IGCC, or simply not to invest.Numerical computations involve the use of one- and two-dimensional binomial lattices that support a mean-reverting process for coal and gas prices. Basic parameter values are taken from an actual IGCC power plant currently in operation. Sensitivity of some results with respect to the underlying stochastic process for fuel price is also checked.     

燃气轮机在热电联产工程中的应用状况分析

燃气轮机是21世纪乃至更长时间内能源高效转换与洁净利用系统的核心动力装备.介绍了燃气轮机的发展现状及其在热电联产工程中的应用,简述了联合循环和简单循环燃气轮机电厂的基本组合方式,并列举了目前应用在热电联产工程中的几种主要的燃气轮机.阐述了燃气轮机相对于常规火电机组的优点,分析了影响燃气轮机在热电联产工程中推广的因素,并对我国燃气轮机的发展前景进行了展望.     

Optimum conditions for a natural gas combined cycle power generation system based on available oxygen when using biomass as supplementary fuel

Due to the higher oxygen content and lower heating value, the amount of biomass required in a combined cycle, where it is used as supplementary fuel, to meet a given energy demand is such that the biomass consumes almost all of the oxygen remaining from gas turbine combustion process under certain conditions. This situation requires additional air for biomass combustion thus reducing the cycle efficiency and the net work output rate while increasing CO₂ emissions. Three conditions at which the oxygen is completely consumed are identified based on alterations in net fuel utilization. The first condition is linked to fuel utilization, which is observed to be significantly affected by variations in temperatures at three locations in the combined cycle (air temperature entering the gas turbine combustion chamber, gas turbine inlet temperature and HRSG inlet temperatures). The second condition relates to the characteristics of the feedstock (oxygen content of the biomass and heating value of natural gas). The heat loss due to combustion of natural gas and biomass is the third condition that affects oxygen availability. The current work assesses these conditions in order to identify the proper condition at which no additional air is required for supplementary firing of biomass.     

Technologies for increasing CO2 concentration in exhaust gas from natural gas-fired power production with post-combustion, amine-based CO2 capture

Enhanced CO₂ concentration in exhaust gas is regarded as a potentially effective method to reduce the high electrical efficiency penalty caused by CO₂ chemical absorption in post-combustion capture systems. The present work evaluates the effect of increasing CO₂ concentration in the exhaust gas of gas turbine based power plant by four different methods: exhaust gas recirculation (EGR), humidification (EvGT), supplementary firing (SFC) and external firing (EFC). Efforts have been focused on the impacts on cycle efficiency, combustion, gas turbine components, and cost. The results show that the combined cycle with EGR has the capability to change the molar fraction of CO₂ with the largest range, from 3.8 mol% to at least 10 mol%, and with the highest electrical efficiency. The EvGT cycle has relatively low additional cost impact as it does not require any bottoming cycle. The externally fired method was found to have the minimum impacts on both combustion and turbomachinery.     

Aspen Plus simulation of biomass integrated gasification combined cycle systems at corn ethanol plants

Biomass integrated gasification combined cycle (BIGCC) systems and natural gas combined cycle (NGCC) systems are employed to provide heat and electricity to a 0.19 hm³ y⁻¹ (50 million gallon per year) corn ethanol plant using different fuels (syrup and corn stover, corn stover alone, and natural gas). Aspen Plus simulations of BIGCC/NGCC systems are performed to study effects of different fuels, gas turbine compression pressure, dryers (steam tube or superheated steam) for biomass fuels and ethanol co-products, and steam tube dryer exhaust treatment methods. The goal is to maximize electricity generation while meeting process heat needs of the plant. At fuel input rates of 110 MW, BIGCC systems with steam tube dryers provide 20–25 MW of power to the grid with system thermal efficiencies (net power generated plus process heat rate divided by fuel input rate) of 69–74%. NGCC systems with steam tube dryers provide 26–30 MW of power to the grid with system thermal efficiencies of 74–78%. BIGCC systems with superheated steam dryers provide 20–22 MW of power to the grid with system thermal efficiencies of 53–56%. The life-cycle greenhouse gas (GHG) emission reduction for conventional corn ethanol compared to gasoline is 39% for process heat with natural gas (grid electricity), 117% for BIGCC with syrup and corn stover fuel, 124% for BIGCC with corn stover fuel, and 93% for NGCC with natural gas fuel. These GHG emission estimates do not include indirect land use change effects.     

Gas fired combined cycle plant in Singapore: energy use,GWP and cost—a life cycle approach

A life cycle assessment was performed to quantify the non-renewable (fossil) energy use and global warming potential (GWP) in electricity generation from a typical gas fired combined cycle power plant in Singapore. The cost of electricity generation was estimated using a life cycle cost analysis (LCCA) tool. The life cycle assessment (LCA) of a 367.5 MW gas fired combined cycle power plant operating in Singapore revealed that hidden processes consume about 8% additional energy in addition to the fuel embedded energy, and the hidden GWP is about 18%. The natural gas consumed during the operational phase accounted for 82% of the life cycle cost of electricity generation. An empirical relation between plant efficiency and life cycle energy use and GWP in addition to a scenario for electricity cost with varying gas prices and plant efficiency have been established.