Efficiency enhancement of pressurized oxy‐coal power plant with heat integration

The oxy‐coal combustion with carbon dioxide capture and sequestration is among the promising clean coal technologies for reducing CO₂ emissions. Because most of oxy‐coal power plants need to cope with energy penalties from air separation and CO₂ compressor units, the pressurized combustion is added to reduce the electricity demand for the CCS system, and the waste heat of the pressurized flue gas is recovered by the heat integration technique to increase the power generation from steam turbines. Finally, the efficiency enhancement of a 100 MW_e‐scale power plant is successfully validated by Aspen Plus simulation. Copyright © 2014 John Wiley & Sons, Ltd.     

Experimental study on combustion of torrefied palm kernel shell (PKS) in oxy‐fuel environment

Oxy‐combustion of biomass can be a major candidate to achieve negative emission of CO₂ from a pulverized fuel (pf)‐firing power generation plants. Understanding combustion behavior of biomass fuels in oxy‐firing conditions is a key for design of oxy‐combustion retrofit of pulverized fuel power plant. This study aims to investigate a lab‐scale combustion behavior of torrefied palm kernel shell (PKS) in oxy‐combustion environments in comparison with the reference bituminous coal. A 20 kW_th‐scale, down‐firing furnace was used to conduct the experiments using both air (conventional) and O₂/CO₂ (30 vol% for O₂) as an oxidant. A bituminous coal (Sebuku coal) was also combusted in both air‐ and oxy‐firing condition with the same conditions of oxidizers and thermal heat inputs. Distributions of gas temperature, unburned carbon, and NO_x concentration were measured through sampling of gases and particles along axial directions. Moreover, the concentrations of SO_x and HCl were measured at the exit of the furnace. Experimental results showed that burnout rate was enhanced during oxy‐fuel combustion. The unburnt carbon in the flue gas was reduced considerably (~75%) during combustion of torrefied PKS in oxy‐fuel environment as compared with air‐firing condition. In addition, NO emission was reduced by 16.5% during combustion of PKS in oxy‐fuel environment as compared with air‐firing condition.     

New weighted‐sum‐of‐gray‐gases model for typical pressurized oxy‐fuel conditions

Pressurized oxy‐fuel combustion technology has received considerable attention due to its ability to improve the overall system efficiency and to control CO₂ emissions. The characteristics of radiation heat transfer are significant for pressurized oxy‐fuel gas mixture and different from those under atmospheric conditions. Therefore, to calculate the radiation characteristics of pressurized oxy‐fuel gas mixture quickly and accurately, new weighted‐sum‐of‐gray‐gases (WSGG) model for pressurized oxy‐fuel conditions was first presented in this paper, which was applied in 3 typical high pressure conditions: 5, 10, and 15 bar. The new WSGG model correlations were suitable for pressurized conditions with a molar ratio range of 0.125‐2, temperature range of 400‐2500 K, and path length range of 0.1‐20 m. Calculations for a variety of typical pressurized oxy‐fuel combustion cases showed that the new WSGG model can accurately predict the radiation characteristics and heat transfer characteristics of the gas mixtures compared with the SNB model benchmark. In addition, the application of the previous atmospheric WSGG models yielded non‐ideal results under pressurized conditions. Consequently, the new model can provide efficient and accurate radiation heat transfer results for pressurized oxy‐fuel conditions and can be used to design pressurized oxy‐fuel combustion furnaces or boilers.     

Lignite‐fired air‐blown IGCC systems with pre‐combustion CO2 capture

Detailed analyses based on mass and energy balances of lignite‐fired air‐blown gasification‐based combined cycles with CO₂ pre‐combustion capture are presented and discussed in this work. The thermodynamic assessment is carried out with a proprietary code integrated with Aspen Plus^® to carefully simulate the selective removal of both H₂S and CO₂ in the acid gas removal station. The work focuses on power plants with two combustion turbines, with lower and higher turbine inlet temperatures, respectively, as topping cycle. A high‐moisture lignite, partially dried before feeding the air‐blown gasification system, is used as fuel input. Because the raw lignite presents a very low amount of sulfur, a particular technique consisting of an acid gas recycle to the absorber, is adopted to fulfill the requirements related to the presence of H₂S in the stream to the Claus plant and in the CO₂‐rich stream to storage. Despite the operation of the H₂S removal section representing a significant issue, the impact on the performance of the power plant is limited. The calculations show that a significant lignite pre‐drying is necessary to achieve higher efficiency in case of CO₂ capture. In particular, considering a wide range (10–30 wt.%) of residual moisture in the dried lignite, higher heating value (HHV) efficiency presents a decreasing trend, with maximum values of 35.15% and 37.12% depending on the type of the combustion turbine, even though the higher the residual moisture in the dried coal, the lower the extraction of steam from the heat recovery steam cycle. On the other hand, introducing the specific primary energy consumption for CO₂ avoided (SPECCA) as a measure of the energy cost related to CO₂ capture, lower values were predicted when gasifying dried lignite with higher residual moisture content. In particular, a SPECCA value as low as 2.69 MJ/kg_CO2 was calculated when gasifying lignite with the highest (30 wt.%) residual moisture content in a power plant with the advanced combustion turbine. Ultimately, focusing on the power plants with the advanced combustion turbine, air‐blown gasification of lignite brings about a reduction in HHV efficiency equal to almost 1.5 to 2.8 percentage points, depending on the residual moisture in the dried lignite, if compared with similar cases where bituminous coal is used as fuel input. Copyright © 2016 John Wiley & Sons, Ltd.     

Study on zero CO2 emission atmospheric pressure SOFC hybrid power system integrated with OTM

In order to further reduce the energy consumption of CO₂ capture from the traditional SOFC hybrid power system, based on the principle of energy cascade utilization and system integration, a zero CO₂ emission atmospheric pressure solid oxide fuel cell (SOFC) hybrid power system integrated with oxygen ion transport membrane (OTM) is proposed. The oxygen is produced by the OTM for the oxy‐fuel combustion afterburner of SOFC. With the Aspen‐plus software, the models of the overall SOFC hybrid power systems with or without CO₂ capture are developed. The thermal performance of new system is investigated and compared with other systems. The effects of the fuel utilization factor of SOFC and the pressure ratio between two sides of OTM membrane on the overall system performance are analyzed and optimized. The research results show that the efficiency of the zero CO₂ emission atmospheric pressure SOFC hybrid power system integrated with OTM is around 58.36%, only 2.48% lower than that of the system without CO₂ capture (60.84%) but 0.96% higher than that of the zero CO₂ emission atmospheric pressure SOFC hybrid system integrated with the cryogenic air separation unit. Copyright © 2014 John Wiley & Sons, Ltd.     

Study on different zero CO2 emission IGCC systems with CO2 capture by integrating OTM

In this paper, different zero CO₂ emission integrated gasification combined cycle (IGCC) systems based on the oxy‐fuel combustion method by integrating with oxygen ion transfer membrane (OTM) with and without sweep gas are proposed in order to reduce the energy consumption of CO₂ capture. By utilizing the Aspen Plus software, the overall system models are established. The performances of the proposed systems are compared with the traditional IGCC system without CO₂ capture and the zero CO₂ emission IGCC system based on the oxy‐fuel combustion method using the cryogenic air separation unit. In addition, the effects of OTM key parameters on the proposed system performance, such as the feed side pressure, permeate side pressure, and operating temperature, are investigated and analyzed. The results show that the efficiency of the zero CO₂ emission IGCC system based on the oxy‐fuel combustion method integrated with OTM without sweep gas is 6.67% lower than that of the traditional IGCC system without CO₂ capture, but 1.88% higher than that of the zero CO₂ emission IGCC system using the cryogenic air separation unit, and 0.64% lower than that of the proposed system with sweep gas. The research achievements will provide valuable references for further study on CO₂ capture based on IGCC with lower energy penalty. Copyright © 2016 John Wiley & Sons, Ltd.     

A cryogen‐based peak‐shaving technology: systematic approach and techno‐economic analysis

A peak‐shaving technology is recently proposed, which integrates peak‐electricity generation, cryogenic energy storage and CO₂ capture. In such a technology, off‐peak electricity is used to produce liquid nitrogen and oxygen in an air separation and liquefaction unit. At peak hours, natural gas (or alternative gases, e.g. from gasification of coal) is burned by oxygen from the air separation unit (oxy‐fuel combustion) to generate electricity. CO₂ produced is captured in the form of dry ice. Liquid nitrogen produced in the air separation plant not only serves as an energy storage medium but also supplies the low‐grade cold energy for CO₂ separation. In addition, waste heat from the tail gas can be used to superheat nitrogen in the expansion process to further increase the system efficiency. This article reports a systematic approach, with an aim to provide technical information for the system design. Three potential blending gases (helium, oxygen and CO₂) are considered not only for assessing thermodynamic performance but also for techno‐economic analysis. The peak‐shaving systems are also compared with natural gas combined cycle and an oxy–natural gas combined cycle in terms of capital cost and peak electricity production cost. Copyright © 2011 John Wiley & Sons, Ltd.     

Pressurized chemical-looping combustion of coal with an iron ore-based oxygen carrier

Chemical-looping combustion (CLC) is a new combustion technology with inherent separation of CO₂. Most of the previous investigations on CLC of solid fuels were conducted under atmospheric pressure. A pressurized CLC combined cycle (PCLC-CC) system is proposed as a promising coal combustion technology with potential higher system efficiency, higher fuel conversion, and lower cost for CO₂ sequestration. In this study pressurized CLC of coal with Companhia Valedo Rio Doce (CVRD) iron ore was investigated in a laboratory fixed bed reactor. CVRD iron ore particles were exposed alternately to reduction by 0.4 g of Chinese Xuzhou bituminous coal gasified with 87.2% steam/N₂ mixture and oxidation with 5% O₂ in N₂ at 970 °C. The operating pressure was varied between 0.1 MPa and 0.6 MPa. First, control experiments of steam coal gasification over quartz sand were performed. H₂ and CO₂ are the major components of the gasification products, and the operating pressure influences the gas composition. Higher concentrations of CO₂ and lower fractions of CO, CH₄, and H₂ during the reduction process with CVRD iron ore was achieved under higher pressures. The effects of pressure on the coal gasification rate in the presence of the oxygen carrier were different for pyrolysis and char gasification. The pressurized condition suppresses the initial coal pyrolysis process while it also enhances coal char gasification and reduction with iron ore in steam, and thus improves the overall reaction rate of CLC. The oxidation rates and variation of oxygen carrier conversion are higher at elevated pressures reflecting higher reduction level in the previous reduction period. Scanning electron microscope and energy-dispersive X-ray spectroscopy (SEM-EDX) analyses show that particles become porous after experiments but maintain structure and size after several cycles. Agglomeration was not observed in this study. An EDX analysis demonstrates that there is very little coal ash deposited on the oxygen carrier particles but no appreciable crystalline phases change as verified by X-ray diffraction (XRD) analysis. Overall, the limited pressurized CLC experiments carried out in the present work suggest that PCLC of coal is promising and further investigations are necessary.     

Experimental and numerical analysis of oxy‐fuel combustion in a porous plate reactor

The present work focuses on studying experimentally and numerically the oxy‐fuel combustion characteristics inside a porous plate reactor towards the application of oxy‐combustion carbon capture technology. Initially, non‐reactive flow experiments are performed to analyze the permeation rate of oxygen in order to obtain the desired stoichiometric ratios. A numerical model is developed for non‐reactive and reactive flow cases. The model is validated against the presently recorded experimental data for the non‐reacting flow cases, and it is validated against the available literature data for oxy‐fuel combustion for the reacting flow cases. A modified two‐step oxy‐combustion reaction kinetics model for methane is implemented in the present model. Simulations are performed over wide range of operating oxidizer ratios (O₂/CO₂ ratio), from OR = 0.2 to OR = 0.4, and over wide range of equivalence ratios, from φ = 0.7 to φ = 1.0. The flame length was decreased as a result of the increase of the oxidizer ratio. Effects of CO₂ recirculation amount on the oxy‐combustion flame stability are examined. A reduction in combustion temperature and increase in flame fluctuations are encountered while increasing CO₂ concentration inside the reactor. At high equivalence ratio, the combustion temperature and flame stability are improved. At low equivalence ratio, the flame length is increased, and the flame was moved towards the reactor center line. Copyright © 2015 John Wiley & Sons, Ltd.     

Investigation of flame characteristics using various design parameters in a pulverized coal burner for oxy‐fuel retrofitting

In oxy‐coal combustion for carbon capture and storage, oxygen and recirculated CO₂ are used as oxidizers instead of air to produce CO₂‐rich flue gas. Owing to differences between the physical and chemical properties of CO₂ and N₂, the development of a burner and boiler system based on fundamental understanding of the flame type, heat transfer, and NOx emission is required. In this study, computational fluid dynamic analysis incorporating comprehensive coal conversion models was performed to investigate the combustion characteristics of a 30 MWth tangential vane swirl pulverized coal burner. Various burner design parameters were evaluated, including the influence of the burner geometry on the swirl strength, direct O₂ injection, and O₂ concentrations in the primary and secondary oxidizers. The flame characteristics were sensitive to the oxygen concentration in the primary oxidizer. The performance of direct O₂ injection around the primary oxidizer with low O₂ concentration was dependent on the mixing of the fuel and oxidizer. The predictions showed that swirl number adjustment and careful direct oxygen injection design are essential for retrofitting air‐firing pulverized coal burners as oxy‐firing burners.     

Single particle ignition and combustion of anthracite,semi-anthracite and bituminous coals in air and simulated oxy-fuel conditions

A fundamental investigation has been conducted on the combustion behavior of single particles (75–150 μm) of four coals of different ranks: anthracite, semi-anthracite, medium-volatile bituminous and high-volatile bituminous. A laboratory-scale transparent laminar-flow drop-tube furnace, electrically-heated to 1400 K, was used to burn the coals. The experiments were performed in different combustion atmospheres: air (21%O₂/79%N₂) and four simulated dry oxy-fuel conditions: 21%O₂/79%CO₂, 30%O₂/70%CO₂, 35%O₂/65%CO₂ and 50%O₂/50%CO₂. The ignition and combustion of single particles was observed by means of three-color pyrometry and high-speed high-resolution cinematography to obtain temperature–time histories and record combustion behaviors. On the basis of the observations made with these techniques, a comprehensive examination of the ignition and combustion behaviors of these fuels was achieved. Higher rank coals (anthracite and semi-anthracite) ignited heterogeneously on the particle surface, whereas the bituminous coal particles ignited homogeneously in the gas phase. Moreover, deduced ignition temperatures increased with increasing coal rank and decreased with increasing oxygen concentrations. Strikingly disparate combustion behaviors were observed depending on the coal rank. The combustion of bituminous coal particles took place in two phases. First, volatiles evolved, ignited and burned in luminous enveloping flames. Upon extinction of these flames, the char residues ignited and burned. In contrast, the higher rank coal particles ignited and burned heterogeneously. The replacement of the background N₂ gas of air with CO₂ (i.e., changing from air to an oxy-fuel atmosphere) at the same oxygen mole fraction impaired the intensity of combustion. It reduced the combustion temperatures and lengthened the burnout times of the particles. Increasing the oxygen mole fraction in CO₂ to 30–35% restored the intensity of combustion to that of air for all the coals studied. Volatile flame burnout times increased linearly with the volatile matter content in the coal in both air and all oxygen mole fractions in CO₂. On the other hand, char burnout times increased linearly or quadratically versus carbon content in the coal, depending on the oxygen mole fraction in the background gas.     

Frontiers in combustion techniques and burner designs for emissions control and CO2 capture: A review

The use of fossil fuel is expected to increase significantly by midcentury because of the large rise in the world energy demand despite the effective integration of renewable energies in the energy production sector. This increase, alongside with the development of stricter emission regulations, forced the manufacturers of combustion systems, especially gas turbines, to develop novel combustion techniques for the control of NO_x and CO₂ emissions, the latter being a greenhouse gas responsible for more than 60% to the global warming problem. The present review addresses different burner designs and combustion techniques for clean power production in gas turbines. Combustion and emission characteristics, flame instabilities, and solution techniques are presented, such as lean premixed air‐fuel (LPM) and premixed oxy‐fuel combustion techniques, and the combustor performance is compared for both cases. The fuel flexibility approach is also reviewed, as one of the combustion techniques for controlling emissions and reducing flame instabilities, focusing on the hydrogen‐enrichment and the integrated fuel‐flexible premixed oxy‐combustion approaches. State‐of‐the‐art burner designs for gas turbine combustion applications are reviewed in this study, including stagnation point reverse flow (SPRF) burner, dry low NO_x (DLN) and dry low‐emission (DLE) burners, EnVironmental burners (including EV, AEV, and SEV burners), perforated plate (PP) burner, and micromixer (MM) burner. Special emphasis is made on the MM combustor technology, as one of the most recent advances in gas turbines for stable premixed flame operation with wide turndown and effective control of NO_x emissions. Since the generation of pure oxygen is prerequisite to oxy‐combustion, oxygen‐separation membranes became of immense importance either for air separation for clean oxy‐combustion applications or for conversion/splitting of the effluent CO₂ into useful chemical and energy products. The different carbon‐capture technologies, along with the most recent carbon‐utilization approaches towards CO₂ emissions control, are also reviewed.     

Techno‐economic analysis of biomass/coal Co‐gasification IGCC systems with supercritical steam bottom cycle and carbon capture

In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and In recent years, integrated gasification combined cycle technology has been gaining steady popularity for use in clean coal power operations with carbon capture and sequestration (CCS). This study focuses on investigating two approaches to improve efficiency and further reduce the greenhouse gas (GHG) emissions. First, replace the traditional subcritical Rankine steam cycle portion of the overall plant with a supercritical steam cycle. Second, add different amounts of biomass as feedstock to reduce emissions. Employing biomass as a feedstock has the advantage of being carbon neutral or even carbon negative if CCS is implemented. However, due to limited feedstock supply, such plants are usually small (2–50 MW), which results in lower efficiency and higher capital and production costs. Considering these challenges, it is more economically attractive and less technically challenging to co‐combust or co‐gasify biomass wastes with low‐rank coals. Using the commercial software, Thermoflow®, this study analyzes the baseline plants around 235 MW and 267 MW for the subcritical and supercritical designs, respectively. Both post‐combustion and pre‐combustion CCS conditions are considered. The results clearly show that utilizing a certain type of biomass with low‐rank coals up to 50% (wt.) can, in most cases, not only improve the efficiency and reduce overall emissions but may be economically advantageous, as well. Beyond a 10% Biomass Ratio, however, the efficiency begins to drop due to the rising pretreatment costs, but the system itself still remains more efficient than from using coal alone (between 0.2 and 0.3 points on average). The CO₂ emissions decrease by about 7000 tons/MW‐year compared to the baseline (no biomass), making the plant carbon negative with only 10% biomass in the feedstock. In addition, implementing a supercritical steam cycle raises the efficiency (1.6 percentage points) and lowers the capital costs ($300/kW), regardless of plant layout. Implementing post‐combustion CCS consistently causes a drop in efficiency (at least 7–8 points) from the baseline and increases the costs by $3000–$4000/kW and $0.06–$0.07/kW‐h. The SO_x emissions also decrease by about 190 tons/year (7.6 × 10^?6 tons/MW‐year). Finally, the CCS cost is around $65–$72 per ton of CO₂. For pre‐combustion CCS, sour shift appears to be superior both economically and thermally to sweet shift in the current study. Sour shift is always cheaper, (by a difference of about $600/kW and $0.02‐$0.03/kW‐h), easier to implement, and also 2–3 percentage points more efficient. The economic difference is fairly marginal, but the trend is inversely proportional to the efficiency, with cost of electricity decreasing by 0.5 cents/kW‐h from 0% to 10% biomass ratio (BMR) and rising 2.5 cents/kW‐h from 10% to 50% BMR. Pre‐combustion CCS plants are smaller than post‐combustion ones and usually require 25% less energy for CCS due to their compact size for processing fuel flow only under higher pressure (450 psi), versus processing the combusted gases at near‐atmospheric pressure. Finally, the CO₂ removal cost for sour shift is around $20/ton, whereas sweet shift's cost is around $30/ton, which is much cheaper than that of post‐combustion CCS: about $60–$70/ton. Copyright © 2014 John Wiley & Sons, Ltd.     

Experiments on chemical looping combustion of coal with a NiO based oxygen carrier

A chemical looping combustion process for coal using interconnected fluidized beds with inherent separation of CO₂ is proposed in this paper. The configuration comprises a high velocity fluidized bed as an air reactor, a cyclone, and a spout-fluid bed as a fuel reactor. The high velocity fluidized bed is directly connected to the spout-fluid bed through the cyclone. Gas composition of both fuel reactor and air reactor, carbon content of fly ash in the fuel reactor, carbon conversion efficiency and CO₂ capture efficiency were investigated experimentally. The results showed that coal gasification was the main factor which controlled the contents of CO and CH₄ concentrations in the flue gas of the fuel reactor, carbon conversion efficiency in the process of chemical looping combustion of coal with NiO-based oxygen carrier in the interconnected fluidized beds. Carbon conversion efficiency reached only 92.8% even when the fuel reactor temperature was high up to 970 °C. There was an inherent carbon loss in the process of chemical looping combustion of coal in the interconnected fluidized beds. The inherent carbon loss was due to an easy elutriation of fine char particles from the freeboard of the spout-fluid bed, which was inevitable in this kind of fluidized bed reactor. Further improvement of carbon conversion efficiency could be achieved by means of a circulation of fine particles elutriation into the spout-fluid bed or the high velocity fluidized bed. CO₂ capture efficiency reached to its equilibrium of 80% at the fuel reactor temperature of 960 °C. The inherent loss of CO₂ capture efficiency was due to bypassing of gases from the fuel reactor to the air reactor, and the product of residual char burnt with air in the air reactor. Further experiments should be performed for a relatively long-time period to investigate the effects of ash and sulfur in coal on the reactivity of nickel-based oxygen carrier in the continuous CLC reactor.     

Study on a zero CO2 emission SOFC hybrid power system integrated with OTM using CO2 as sweep gas

A new zero CO₂ emission solid oxide fuel cell (SOFC) hybrid power system integrated with the oxygen ion transport membrane using CO₂ as sweep gas is proposed in this paper. The pure oxygen is picked up from the cathode outlet gas by the oxygen ion transport membrane with CO₂ as sweep gas; the oxy‐fuel combustion mode in the afterburner of SOFC is employed. Because the combustion product gas only consists of CO₂ and steam, CO₂ is easily captured with lower energy consumption by the condensation of steam. With the aspen plus soft, this paper builds the simulation model of the overall SOFC hybrids system with CO₂ capture. The exergy loss distributions of the overall system are analyzed, and the effects of the key operation parameters on the overall system performance are also investigated. The research results show that the new system still has a high efficiency after CO₂ recovery. The efficiency of the new system is around 65.03%, only 1.25 percentage points lower than that of the traditional SOFC hybrid power system(66.28%)without CO₂ capture. The research achievements from this paper will provide the valuable reference for further study on zero CO₂ emission SOFC hybrid power system with higher efficiency. Copyright © 2013 John Wiley & Sons, Ltd.     

Promising components of waste-derived slurry fuels

The paper presents the results of experimental studies of energy (calorific value, ignition delay times and threshold ignition temperatures, duration and temperature of combustion) and environmental (CO₂, NO_x and SO_x emission) characteristics of fuel slurries based on pulverized wood (sawdust), agricultural (straw), and household (cardboard) waste. Wastewater from a sewage treatment plant served as a liquid medium for fuels. Petrochemical waste and heavy oil were additives to slurries. The focus is on obtaining the maximum efficiency ratio of slurry fuel, calculated taking into account environmental, cost, energy and fire safety parameters. All slurry fuels were compared with typical coal-water slurry for all the parameters studied. A comparison was also made between slurries and traditional boiler fuels (coal, fuel oil). The relative efficiency indicator for waste-based mixtures was varied in the range of 0.93–10.92. The lowest ignition costs can be expected when burning a mixture based on straw, cardboard and oil additive (ignition temperature is about 330 °C). The volumes of potential energy generated with the active involvement of industrial waste instead of traditional coal and oil combustion are forecasted. It is predicted that with the widespread use of waste-derived slurries, about 43% of coal and oil can be saved.     

An integrated power generation system combining solid oxide fuel cell and oxy-fuel combustion for high performance and CO2 capture

An integrated power generation system combining solid oxide fuel cell (SOFC) and oxy-fuel combustion technology is proposed. The system is revised from a pressurized SOFC-gas turbine hybrid system to capture CO₂ almost completely while maintaining high efficiency. The system consists of SOFC, gas turbine, oxy-combustion bottoming cycle, and CO₂ capture and compression process. An ion transport membrane (ITM) is used to separate oxygen from the cathode exit air. The fuel cell operates at an elevated pressure to facilitate the use of the ITM, which requires high pressure and temperature. The remaining fuel at the SOFC anode exit is completely burned with oxygen at the oxy-combustor. Almost all of the CO₂ generated during the reforming process of the SOFC and at the oxy-fuel combustor is extracted from the condenser of the oxy-combustion cycle. The oxygen-depleted high pressure air from the SOFC cathode expands at the gas turbine. Therefore, the expander of the oxy-combustion cycle and the gas turbine provides additional power output. The two major design variables (steam expander inlet temperature and condenser pressure) of the oxy-fuel combustion system are determined through parametric analysis. There exists an optimal condenser pressure (below atmospheric pressure) in terms of global energy efficiency considering both the system power output and CO₂ compression power consumption. It was shown that the integrated system can be designed to have almost equivalent system efficiency as the simple SOFC-gas turbine hybrid system. With the voltage of 0.752 V at the SOFC operating at 900 °C and 8 bar, system efficiency over 69.2% is predicted. Efficiency penalty due to the CO₂ capture and compression up to 150 bar is around 6.1%.     

Thermodynamic analysis of high‐ash coal‐fired power plant with carbon dioxide capture

A thermodynamic analysis of a 500‐MWe subcritical power plant using high‐ash Indian coal (base plant) is carried out to determine the effects of carbon dioxide (CO₂) capture on plant energy and exergy efficiencies. An imported (South African) low‐ash coal is also considered to compare the performance of the integrated plant (base plant with CO₂ capture plant). Chemical absorption technique using monoethanolamine as an absorbent is adopted in the CO₂ capture plant. The flow sheet computer program “Aspen Plus” is used for the parametric study of the CO₂ capture plant to determine the minimum energy requirement for absorbent regeneration at optimum absorber–stripper configuration. Energy and exergy analysis for the integrated plant is carried out using the power plant simulation software “Cycle‐Tempo”. The study also involves determining the effects of various steam extraction techniques from the turbine cycle (intermediate‐pressure–low‐pressure crossover pipe) for monoethanolamine regeneration. It is found that the minimum reboiler heat duty is 373 MW_th (equivalent to 3.77 MJ of heat energy per kg of CO₂ captured), resulting in a drop of plant energy efficiency by approximately 8.3% to 11.2% points. The study reveals that the maximum energy and exergy losses occur in the reboiler and the combustor, respectively, accounting for 29% and 33% of the fuel energy and exergy. Among the various options for preprocessing steam that is extracted from turbine cycle for reboiler use, “addition of new auxiliary turbine” is found to be the best option. Copyright © 2011 John Wiley & Sons, Ltd.     

A review of recent developments in carbon capture utilizing oxy‐fuel combustion in conventional and ion transport membrane systems

Fossil fuels provide a significant fraction of the global energy resources, and this is likely to remain so for several decades. Carbon dioxide (CO₂) emissions have been correlated with climate change, and carbon capture is essential to enable the continuing use of fossil fuels while reducing the emissions of CO₂ into the atmosphere thereby mitigating global climate changes. Among the proposed methods of CO₂ capture, oxyfuel combustion technology provides a promising option, which is applicable to power generation systems. This technology is based on combustion with pure oxygen (O₂) instead of air, resulting in flue gas that consists mainly of CO₂ and water (H₂O), that latter can be separated easily via condensation, while removing other contaminants leaving pure CO₂ for storage. However, fuel combustion in pure O₂ results in intolerably high combustion temperatures. In order to provide the dilution effect of the absent nitrogen (N₂) and to moderate the furnace/combustor temperatures, part of the flue gas is recycled back into the combustion chamber. An efficient source of O₂ is required to make oxy‐combustion a competitive CO₂ capture technology. Conventional O₂ production utilizing the cryogenic distillation process is energetically expensive. Ceramic membranes made from mixed ion‐electronic conducting oxides have received increasing attention because of their potential to mitigate the cost of O₂ production, thus helping to promote these clean energy technologies. Some effort has also been expended in using these membranes to improve the performance of the O₂ separation processes by combining air separation and high‐temperature oxidation into a single chamber. This paper provides a review of the performance of combustors utilizing oxy‐fuel combustion process, materials utilized in ion‐transport membranes and the integration of such reactors in power cycles. The review is focused on carbon capture potential, developments of oxyfuel applications and O₂ separation and combustion in membrane reactors. The recent developments in oxyfuel power cycles are discussed focusing on the main concepts of manipulating exergy flows within each cycle and the reported thermal efficiencies. Copyright © 2010 John Wiley & Sons, Ltd.     

Integration of gas switching combustion in a humid air turbine cycle for flexible power production from solid fuels with near-zero emissions of CO2 and other pollutants

This work presents a novel plant configuration for power production from solid fuels with integrated CO₂ capture. Specifically, the Gas Switching Combustion (GSC) system is integrated with a Humid Air Turbine (HAT) power cycle and a slurry fed entrained flow (GE-Texaco) gasifier or a dry fed (Shell) gasifier with a partial water quench. The primary novelty of the proposed GSC-HAT plant is that the reduction and oxidation reactor stages of the GSC operation can be decoupled allowing for flexible operation, with the oxygen carrier serving as a chemical and thermal energy storage medium. This can allow the air separation unit, gasifier, gas clean-up, CO₂ compressors and downstream CO₂ transport and storage network to be downsized for operation under steady state conditions, while the reactors and the power cycle operate flexibly to follow load. Such cost-effective flexibility will be highly valued in future energy systems with high shares of variable renewable energy. The GSC-HAT plant achieves 42.5% electrical efficiency with 95.0% CO₂ capture rate with the Shell gasifier, and 41.6% efficiency and 99.2% CO₂ capture with the GE gasifier. An exergy analysis performed for the GE gasifier case revealed that this plant reached 38.9% exergy efficiency, only 1.6%-points below an inflexible GSC-IGCC benchmark configuration, while reaching around 5%-points higher CO₂ capture rate. Near-zero SO_x and NO_x emissions are achieved through pre-combustion gas clean-up and flameless fuel combustion. Overall, this flexible and efficient near-zero emission power plant appears to be a promising alternative in a future carbon constrained world with increasing shares of variable renewables and more stringent pollutant (NO_x, SO_x) regulations.