Effects of supplementary biomass firing on the performance of combined cycle power generation: A comparison between NGCC and IGCC plants

In the present work, effects of biomass supplementary firing on the performance of fossil fuel fired combined cycles have been analyzed. Both natural gas fired combined cycle (NGCC) and integrated coal gasification combined cycle (IGCC) have been considered in the study. The efficiency of the NGCC plant monotonically reduces with the increase in supplementary firing, while for the IGCC plant the maximum plant efficiency occurs at an optimum degree of supplementary firing. This difference in the nature of variation of the efficiency of two plants under the influence of supplementary firing has been critically analyzed in the paper. The ratings of different plant equipments, fuel flow rates and the emission indices of CO₂ from the plants at varying degree of supplementary firing have been evaluated for a net power output of 200 MW. The fraction of total power generated by the bottoming cycle increases with the increase in supplementary firing. However, the decrease in the ratings of gas turbines is much more than the increase in that of the steam turbines due to the low work ratio of the topping cycle. The NGCC plants require less biomass compared to the IGCC under identical condition. A critical degree of supplementary firing has been identified for the slag free operation of the biomass combustor. The performance parameters, equipment ratings and fuel flow rates for no supplementary firing and for the critical degree of supplementary biomass firing have been compared for the NGCC and IGCC plants.     

An advanced integrated biomass gasification and molten fuel cell power system

Biomass has recently received considerable attention as a potential substitute for fossil fuels in electric power production. Renewable biomass crops, industrial wood residues, and municipal wastes as fuels for production of electricity allow substantial reduction of environmental impact. High reactivity of biomass makes it relatively easy to convert solid feedstocks into gaseous fuel for subsequent use in a power cycle.So far most of the studies were focused on investigating performance and economics of biomass gasifiction–gas turbine systems. A general conclusion resulting from these studies is that the combination of biomass gasifiers, hot gas cleanup systems, and advanced gas turbines is promising for cost competitive electric power generation[1, 2]. In this paper another concept of biomass fueled power systems is considered, namely biomass gasification with a molten carbonate fuel cell (MCFC). Comparison between two concepts is made in terms of efficiency, feasibility, and process requirements. As an example of such a system, a highly efficient novel power cycle consisting of the Battelle gasification process, a molten carbonate fuel cell, and a steam turbine is introduced. The calculated efficiency is around 53%, which exceeds efficiencies of traditional designs[1, 3] considerably. Finally, an economic analysis and electricity cost projection are performed for a power plant consuming 2000 tons of biomass per day. Results are compared with those for more traditional integrated biomass gasification/gas turbine systems and for coal fueled cycles.     

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.     

Cogeneration of power and substitute of natural gas using biomass and electrolytic hydrogen

Storing renewable energy sources is becoming a very important issue to allow a further reduction of greenhouse gas emissions. Most of such energy sources generate electric power which not always can be conveniently transferred to the grid and also its conversion to hydrogen presents some critical aspects connected mainly to hydrogen distribution and storage.Electrolysis generates not only hydrogen, but also oxygen which could be used to burn biomass or waste products (oxycombustion) in power plants with the result to obtain an exhaust gas containing mainly water and CO₂. This last can be converted into a mixture of methane and hydrogen by reacting with electrolytic hydrogen, so that the power used for electrolysis is stored into a fuel which can be distributed and stored just like natural gas.In this paper, an innovative biomass fuelled plant has been designed and simulated for different layouts with an internal combustion engine as a main power system. Utilizing hydrogen and oxygen produced through electrolysis and applying a hydrogasification process, the plant produces electricity and a substitute of natural gas. The result of such simulations is that the electricity can be stored in a useful and versatile fuel with a marginal efficiency up to 60%.     

Highly efficient electricity generation from biomass by integration and hybridization with combined cycle gas turbine (CCGT) plants for natural gas

Integration/co-firing with existing fossil fuel plants could give near term highly efficient and low cost power production from biomass. This paper presents a techno-economical analysis on options for integrating biomass thermal conversion (optimized for local resources ∼50 MW_th) with existing CCGT (combined cycle gas turbine) power plants (800–1400 MW_th). Options include hybrid combined cycles (HCC), indirect gasification of biomass and simple cycle biomass steam plants which are simulated using the software Ebsilon Professional and Aspen Plus. Levelized cost of electricity (LCoE) is calculated with cost functions derived from power plant data. Results show that the integrated HCC configurations (fully-fired) show a significantly higher efficiency (40–41%, LHV (lower heating value)) than a stand-alone steam plant (35.5%); roughly half of the efficiency (2.4% points) is due to more efficient fuel drying. Because of higher investment costs, HCC options have cost advantages over stand-alone options at high biomass fuel prices (>25 EUR/MWh) or low discount rates (<5%). Gasification options show even higher efficiency (46–50%), and the lowest LCoE for the options studied for fuel costs exceeding 10 EUR/MWh. It can be concluded that clear efficiency improvements and possible cost reductions can be reached by integration of biomass with CCGT power plants compared to stand-alone plants.     

Design of an integrated process for simultaneous chemical looping hydrogen production and electricity generation with CO2 capture

This study was aimed at proposing a novel integrated process for co-production of hydrogen and electricity through integrating biomass gasification, chemical looping combustion, and electrical power generation cycle with CO₂ capture. Syngas obtained from biomass gasification was used as fuel for chemical looping combustion process. Calcium oxide metal oxide was used as oxygen carrier in the chemical looping system. The effluent stream of the chemical looping system was then transferred through a bottoming power generation cycle with carbon capture capability. The products achieved through the proposed process were highly-pure hydrogen and electricity generated by chemical looping and power generation cycle, respectively. Moreover, LNG cold energy was used as heat sink to improve the electrical power generation efficiency of the process. Sensitivity analysis was also carried out to scrutinize the effects of influential parameters, i.e., carbonator temperature, steam/biomass ratio, gasification temperature, gas turbine inlet stream temperature, and liquefied natural gas (LNG) flow rate on the plant performance. Overall, the optimum heat integration was achieved among the sub-systems of the plant while a high energy efficiency and zero CO₂ emission were also accomplished. The findings of the present study could assist future investigations in analyzing the performance of integrated processes and in investigating optimal operating conditions of such systems.     

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.     

Improving the technical, environmental and social performance of wind energy systems using biomass-based energy storage

A completely renewable baseload electricity generation system is proposed by combining wind energy, compressed air energy storage, and biomass gasification. This system can eliminate problems associated with wind intermittency and provide a source of electrical energy functionally equivalent to a large fossil or nuclear power plant. Compressed air energy storage (CAES) can be economically deployed in the Midwestern US, an area with significant low-cost wind resources. CAES systems require a combustible fuel, typically natural gas, which results in fuel price risk and greenhouse gas emissions. Replacing natural gas with synfuel derived from biomass gasification eliminates the use of fossil fuels, virtually eliminating net CO₂ emissions from the system. In addition, by deriving energy completely from farm sources, this type of system may reduce some opposition to long distance transmission lines in rural areas, which may be an obstacle to large-scale wind deployment.     

Cycle analysis of low and high H2 utilization SOFC/gas turbine combined cycle for CO2 recovery

A major factor in global warming is CO₂ emission from thermal power plants, which burn fossil fuels. One technology proposed to prevent global warming is CO₂ recovery from combustion flue gas and the sequestration of CO₂ underground or near the ocean bed. Solid oxide fuel cell (SOFC) can produce highly concentrated CO₂, because the reformed fuel gas reacts with oxygen electrochemically without being mixed with air in the SOFC. We therefore propose to operate multi-staged SOFCs with high utilization of reformed fuel to obtain highly concentrated CO₂. In this study, we estimated the performance of multi-staged SOFCs considering H₂ diffusion and the combined cycle efficiency of a multi-staged SOFC/gas turbine/CO₂ recovery power plant. The power generation efficiency of our CO₂ recovery combined cycle is 68.5%, whereas the efficiency of a conventional SOFC/GT cycle with the CO₂ recovery amine process is 57.8%.     

Hydrogen production from fossil fuels with carbon capture and storage based on chemical looping systems

This paper analyzes innovative processes for producing hydrogen from fossil fuels conversion (natural gas, coal, lignite) based on chemical looping techniques, allowing intrinsic CO₂ capture. This paper evaluates in details the iron-based chemical looping system used for hydrogen production in conjunction with natural gas and syngas produced from coal and lignite gasification. The paper assesses the potential applications of natural gas and syngas chemical looping combustion systems to generate hydrogen. Investigated plant concepts with natural gas and syngas-based chemical looping method produce 500 MW hydrogen (based on lower heating value) covering ancillary power consumption with an almost total decarbonisation rate of the fossil fuels used.The paper presents in details the plant concepts and the methodology used to evaluate the performances using critical design factors like: gasifier feeding system (various fuel transport gases), heat and power integration analysis, potential ways to increase the overall energy efficiency (e.g. steam integration of chemical looping unit into the combined cycle), hydrogen and carbon dioxide quality specifications considering the use of hydrogen in transport (fuel cells) and carbon dioxide storage in geological formation or used for EOR.     

Biomass from agriculture in small-scale combined heat and power plants - A comparative life cycle assessment

Biomass produced on farm land is a renewable fuel that can prove suitable for small-scale combined heat and power (CHP) plants in rural areas. However, it can still be questioned if biomass-based energy generation is a good environmental choice with regards to the impact on greenhouse gas emissions, and if there are negative consequences of using of agricultural land for other purposes than food production.In this study, a simplified life cycle assessment (LCA) was conducted over four scenarios for supply of the entire demand of power and heat of a rural village. Three of the scenarios are based on utilization of biomass in 100 kW (e) combined heat and power (CHP) systems and the fourth is based on fossil fuel in a large-scale plant. The biomass systems analyzed were based on 1) biogas production with ley as substrate and the biogas combusted in a microturbine, 2) gasification of willow chips and the product gas combusted in an IC-engine and 3) combustion of willow chips for a Stirling engine. The two first scenarios also require a straw boiler.The results show that the biomass-based scenarios reduce greenhouse gas emissions considerably compared to the scenario based on fossil fuel, but have higher acidifying emissions. Scenario 1 has by far the best performance with respect to global warming potential and the advantage of utilizing a byproduct and thus not occupying extra land. Scenario 2 and 3 require less primary energy and less fossil energy input than 1, but set-aside land for willow production must be available. The low electric efficiency of scenario 3 makes it an unsuitable option.     

Reducing life cycle greenhouse gas emissions of corn ethanol by integrating biomass to produce heat and power at ethanol plants

A life-cycle assessment (LCA) of corn ethanol was conducted to determine the reduction in the life-cycle greenhouse gas (GHG) emissions for corn ethanol compared to gasoline by integrating biomass fuels to replace fossil fuels (natural gas and grid electricity) in a U.S. Midwest dry-grind corn ethanol plant producing 0.19 hm³ y⁻¹ of denatured ethanol. The biomass fuels studied are corn stover and ethanol co-products [dried distillers grains with solubles (DDGS), and syrup (solubles portion of DDGS)]. The biomass conversion technologies/systems considered are process heat (PH) only systems, combined heat and power (CHP) systems, and biomass integrated gasification combined cycle (BIGCC) systems. The life-cycle GHG emission reduction for corn ethanol compared to gasoline is 38.9% for PH with natural gas, 57.7% for PH with corn stover, 79.1% for CHP with corn stover, 78.2% for IGCC with natural gas, 119.0% for BIGCC with corn stover, and 111.4% for BIGCC with syrup and stover. These GHG emission estimates do not include indirect land use change effects. GHG emission reductions for CHP, IGCC, and BIGCC include power sent to the grid which replaces electricity from coal. BIGCC results in greater reductions in GHG emissions than IGCC with natural gas because biomass is substituted for fossil fuels. In addition, underground sequestration of CO₂ gas from the ethanol plant’s fermentation tank could further reduce the life-cycle GHG emission for corn ethanol by 32% compared to gasoline.     

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.     

Thermodynamic analysis of an integrated gasification solid oxide fuel cell plant combined with an organic Rankine cycle

A 100 kW_e hybrid plant consisting of gasification system, solid oxide fuel cells and organic Rankine cycle is presented. The nominal power is selected based on cultivation area requirement. For the considered output a land of around 0.5 km² needs to be utilized. Woodchips are introduced into a fixed bed gasification plant to produce syngas which fuels the combined solid oxide fuel cells – organic Rankine cycle system to produce electricity. More than a hundred fluids are considered as possible alternative for the organic cycle using non-ideal equations of state (or state-of-the-art equations of state). A genetic algorithm is employed to select the optimal working fluid and the maximum pressure for the bottoming cycle. Thermodynamic and physical properties, environmental impacts and hazard specifications are also considered in the screening process. The results suggest that efficiencies in the region of 54–56% can be achieved. The highest thermal efficiency (56.4%) is achieved with propylcyclohexane at 15.9 bar. A comparison with the available and future technologies for biomass to electricity conversion is carried out. It is shown that the proposed system presents twice the thermal efficiency achieved by simple and double stage organic Rankine cycle plants and around the same efficiency of a combined gasification, solid oxide fuel cells and micro gas turbine plant.     

Analysis of a feasible polygeneration system for power and methanol production taking natural gas and biomass as materials

Co-utilization of natural gas and biomass is a successful way to make efficient use of them for chemical production and power generation, for biomass is rich in carbon while natural gas is rich in hydrogen. The present paper therefore proposes a new polygeneration system taking biomass and natural gas as materials for methanol production and power generation. The new polygeneration system can achieve the optimal ratio of H₂ to CO for methanol production by adjusting input ratio of natural gas to biomass without any energy penalty. Thus, the suggested system can eliminate CO to H₂ shift process and CO₂ remove process, which can avoid material and energy destruction; however, those processes are otherwise necessary in individual biomass to methanol plant. Moreover, the new system eliminates the CO₂ addition process; however, the addition of CO₂ is necessary in individual natural gas to methanol plant, which causes extra energy penalty. This system combined chemical production and power generation together, in order to achieve the cascaded utilization of chemical and physical energy of natural gas and biomass. In a further way, we investigated the key processes, to maximize the utilization of energy and improve system performance.     

Assessment of integration of different biomass gasification alternatives in a district-heating system

With increasingly stringent CO₂ emission reduction targets, incentives for efficient use of limited biomass resources increase. Technologies for gasification of biomass may then play a key role given their potential for high electrical efficiency and multiple outputs; not only electricity but also bio transport fuels and district heat. The aim of this study is to assess the economic consequences and the potential for CO₂ reduction of integration of a biomass gasification plant into a district-heating (DH) system. The study focuses on co-location with an existing natural gas combined cycle heat and power plant in the municipal DH system of Göteborg, Sweden. The analysis is carried out using a systems modelling approach. The so-called MARTES model is used. MARTES is a simulating, DH systems supply model with a detailed time slice division. The economic robustness of different solutions is investigated by using different sets of parameters for electricity price, fuel prices and policy tools. In this study, it is assumed that not only tradable green certificates for electricity but also tradable green certificates for transport fuels exist. The economic results show strong dependence on the technical solutions and scenario assumptions but in most cases a stand-alone SNG-polygeneration plant with district-heat delivery is the cost-optimal solution. Its profitability is strongly dependent on policy tools and the price relation between biomass and fossil fuels. Finally, the results show that operation of the biomass gasification plants reduces the (DH) system's net emissions of CO₂.     

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.     

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.     

Life cycle assessment of electricity generation using fast pyrolysis bio-oil

Biomass is expected to become an important energy source in U.S. electricity generation under state-lead renewable portfolio standards. This paper investigated the greenhouse gas (GHG) emissions for energy generated from forest resources through pyrolysis-based processing. The GHG emissions of producing pyrolysis bio-oil (pyrolysis oil) from different forest resources were first investigated; logging residues collected from natural regeneration mixed hardwood stands, hybrid poplar cultivated and harvested from abandoned agricultural lands, short rotation forestry (SRF) willow plantations and waste wood available at the site of the pyrolysis plant. Effects of biomass transportation were investigated through a range of distances to a central pyrolysis facility through road transport by semi-truck. Pyrolysis oil is assumed to be converted to electrical power through co-combustion in conventional fossil fuels power plants, gas turbine combined cycle (GTCC) and diesel generators. Life cycle GHG emissions were compared with power generated using fossil fuels and power generated using biomass direct combustion in a conventional Rankine power plant. Life cycle GHG savings of 77%–99% were estimated for power generation from pyrolysis oil combustion relative to fossil fuels combustion, depending on the biomass feedstock and combustion technologies used. Several scenario analyses were conducted to determine effects of pyrolysis oil transportation distance, N-fertilizer inputs to energy crop plantations, and assumed electricity mixes for pyrolysis oil production.