Reducing life‐cycle environmental impacts of coal‐power by using coal‐mine methane

The exploitation of coal‐mine methane is analysed to reduce the environmental impact from coal power systems. The analyses are based on a life cycle assessment, and the results were compared with carbon‐capture and storage technologies. The results suggest that by increasing the use of coalmine methane, the environmental impacts of coal power plants could be clearly reduced. Although the CO₂ reduction is much less than through sequestration of CO₂, increased use of coal‐mine methane in Poland could potentially reduce greenhouse gas emissions up to 9 million tonnes of CO₂ per year, which corresponds to about 2.5% of the emissions of Poland. Copyright © 2012 John Wiley & Sons, Ltd.     

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.     

Performance enhancement in coal‐fired thermal power plants. Part III: auxiliary power

Auxiliary power in coal‐fired power stations accounts for 7% (500 MW units) to 12% (30 MW units) of the gross generated power at the full plant load. The minimum AP varies between 4·5 and 9·0% for the same capacity range. The excessive power due to factors such as coal quality, excessive steam flow, internal leakage/ingress in equipment, inefficient drives, distribution network losses, reduced power quality, ageing, etc., is quantified. An experimental study has shown that 85·7% of the AP in excess of the design value can be traced to coal quality and its indirect effects. The AP can be minimized even below the design value by operational optimization, overhaul of equipment and revamping. The paper discusses in detail the techniques for restoration of the AP to the designed value and further improvements. Copyright © 1999 John Wiley & Sons, Ltd.     

Thermodynamic performance analysis of the coal‐fired power plant with solar thermal utilizations

A new way of energy saving for existing coal‐fired power plant that uses low‐or medium‐temperature solar energy as assistant heat source was proposed to generate ‘green’ electricity. This paper has built the mathematical models of the solar‐aided power generation system focusing on the NZK600‐16.7/538/538 units. Based on the combination of the first and second law of thermodynamics, the thermodynamic performance of different components of the integrated system was evaluated under the changing operating condition aiming at different substitution options for turbine bleed streams. It has been found that the efficiency of the solar heat to electricity enhances with the increase of the load and the replaced extraction level. Additionally, when the second extraction is replaced, the effect is the best, which makes the power output increase around 6.13% or the coal consumption rate decrease 13.14 g/(kW · h) under 100%THA load and CO₂ emission reduce about 32.76 g/(kW · h), while the energy and exergy efficiencies of the integrated system are 39.35% and 39.12%, respectively. The results provide not only theory basis and scientific support for the design of solar‐aided coal‐fired power plants, but also a new way of energy saving and optimization for the units. Copyright © 2014 John Wiley & Sons, Ltd.     

Profitability and off‐site CO2‐emission reduction from energy savings in the pulp and paper industry in different future energy markets

Previous studies by the authors have shown that energy savings in pulp and paper mills offer opportunities for increased electricity production on‐site or wood fuel export. The energy export implies reductions in CO₂ emissions off‐site, where fossil fuel or fossil‐fuel‐based electricity is replaced. To assess this potential and the related profitability for a future situation, four energy market scenarios were used. For a typical Scandinavian mill, the potential for CO₂‐emission reductions was 15–140 kton year^?1 depending on the scenario and the form of energy export. Extrapolated to all relevant mills in Sweden, the potential was 0.4–3.1 Mton year^?1, which is in the order of percent of the Swedish CO₂ emissions. Wood fuel export implies larger reduction in CO₂ emissions in most scenarios. In contrast, electricity export showed better economy in most of the cases studied; with annual earnings of 5–6 M€, this is an economically robust option. In the market pulp mill investigated, the wood fuel export was in the form of lignin. Lignin could possibly be valued as oil, regarding both price and potential for CO₂‐emission reduction, making lignin separation an option with good profitability and large reductions of CO₂ emissions. Copyright © 2011 John Wiley & Sons, Ltd.     

Microbial electrolysis cells for production of methane from CO2: long‐term performance and perspectives

A methane‐producing microbial electrolysis cell (MEC) is a technology to convert CO₂ into methane, using electricity as an energy source and microorganisms as the catalyst. A methane‐producing MEC provides the possibility to increase the fuel yield per hectare of land area, when the CO₂ produced in biofuel production processes is converted to additional fuel methane. Besides increasing fuel yield per hectare of land area, this also results in more efficient use of land area, water, and nutrients. In this research, the performance of a methane‐producing MEC was studied for 188 days in a flat‐plate MEC design. Methane production rate and energy efficiency of the methane‐producing MEC were investigated with time to elucidate the main bottlenecks limiting system performance. When using water as the electron donor at the anode during continuous operation, methane production rate was 0.006 m³/m³ per day at a cathode potential of ?0.55 V vs. normal hydrogen electrode with a coulombic efficiency of 23.1%. External electrical energy input was 73.5 kWh/m³ methane, resulting in a voltage efficiency of 13.4%. Consequently, overall energy efficiency was 3.1%. The maximum achieved energy efficiency was obtained in a yield test and was 51.3%. Analysis of internal resistance showed that in the short term, cathode and anode losses were dominant, but with time, also pH gradient and transport losses became more important. The results obtained in this study are used to discuss the possible contribution of methane‐producing MECs to increase the fuel yield per hectare of land area. Copyright © 2011 John Wiley & Sons, Ltd.     

Utilization of combustible waste gas as a supplementary fuel in coal‐fired boilers

A system is proposed to use the combustible waste gas as a supplementary fuel in coal‐fired boilers. The combustion air can be partially or fully substituted by ventilation air methane or diluted combustible waste gases. The recommended volume fraction of combustible waste gas in combustion air is no more than 1.0%. The effect of waste gas introduction on thermodynamic parameters of boiler is evaluated through thermal calculation based on material balance, heat balance, and heat transfer principles. A case study is conducted by referring to a 600 MW supercritical pressure boiler. The results show that no retrofit of boiler is required. The operation of boiler is scarcely influenced, and the original forced and induced draft fans can meet the requirement. With increasing volume fraction of combustible waste gas, the flue gas temperature at the furnace exit decreases monotonically, resulting in an increment of heat absorption in furnace and a decrement of heat transferred in convective heating surfaces. When 1.0% volume fraction of hydrocarbon gas is introduced, the thermal efficiency of boiler is increased by 0.5%, and the coal consumption rate is reduced by 25.4%. The cost analysis of the proposed system is conducted, and break‐even curves are given as references for the utilization of waste gas as a supplementary fuel. The economic velocity of the combustion air is suggested to be 18.2 m s^?1.     

Flexibly using results of CFD and simplified heat transfer model for pulverized coal‐fired boilers

The efficient use of pulverized coal is crucial to the utility industries. The use of computational fluid dynamics (CFD)‐based numerical models has an important role in the design of new boiler furnaces or in retrofitting situations. The results of CFD simulations can be used to better understand the complex processes occurring within the boiler furnace. The use of these results to support boiler operation and training of operators requires that the CFD models can be easily accessed and the results are easily analysed. This paper discusses two ways to simulate the heat transfer process in boiler furnaces. The method directly applying CFD results is employed, in which the grid for solving the energy equation is the same as the flow grid in the CFD simulation while radiation heat transfer is solved in another relatively coarse grid. Comparison of the prediction results between CFD and Heat Transfer code (Simple model) is performed under boiler full load (100%) with one side wall fouling, as well as for different boiler loads (100, 98 and 95 per cent boiler full load, respectively). Finally, the flexible use of the results of CFD and the simple model for pulverized coal‐fired boilers is presented. To facilitate the use of the system, a user‐friendly interface was developed which enables the user to manipulate new calculations and to view results, namely performing ‘what–if’ analysis. Copyright © 2000 John Wiley & Sons, Ltd.     

Evaluation of solar aided thermal power generation with various power plants

Solar aided power generation (SAPG) is an efficient way to make use of low or medium temperature solar heat for power generation purposes. The so‐called SAPG is actually ‘piggy back’ solar energy on the conventional fuel fired power plant. Therefore, its solar‐to‐electricity efficiency depends on the power plant it is associated with. In the paper, the developed SAPG model has been used to study the energy and economic benefits of the SAPG with 200 and 300 MW typical, 600 MW subcritical, 600 MW supercritical, and 600 and 1000 MW ultra‐supercritical fuel power units separately. The solar heat in the temperature range from 260 to 90°C is integrated with above‐mentioned power units to replace the extraction steam (to preheat the feedwater) in power boosting and fuel‐saving operating modes. The results indicate that the benefits of SAPG are different for different steam extracted positions and different power plants. Generally, the larger the power plant, the higher the solar benefit if the same level solar is integrated. Copyright © 2010 John Wiley & Sons, Ltd.     

Three‐dimensional modeling method for heat exchange of rotary air preheater in coal‐fired power plant

A numerical modeling method based on a 3‐D heat transfer model and duct models for a dual‐sectional rotary air preheater have been developed in this paper. Owing to different boundary conditions for the heat transfer model obtained by modeling and calculation of the ducts, this method is capable of calculating the 3‐D metal and fluid temperature fields at different radial locations in the rotary air preheater along the rotor height as well as the rotating period, and furthermore, it can calculate temperature and flow field inside the flow passage as well. A case study with a dual‐sectional rotary air preheater of a typical 300 MW_e unit used as the research object is presented in this paper. The calculation results accord well with those obtained by verified numerical methods in published literature. The difference between the calculated and the measured outlet fluid temperature of the rotary air preheater is smaller than 3 °C. The numerical modeling method presented in this paper is proved to have high precision and is beneficial for the secure and economic operation of a rotary air preheater as well as the whole unit. © 2010 Wiley Periodicals, Inc. Heat Trans Asian Res; Published online in Wiley Online Library ( wileyonlinelibrary.com ). DOI 10.1002/htj.20325     

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

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

Constructal allocation of heat transfer area in Flue Gas Desulfurization equipment for coal‐firing power plants

In this paper, we report opportunities to maximize the overall heat transfer rate of a cooler and reheater by appropriately shaping the flue gas desulfurization equipment of a thermal power plant driven by coal‐firing combustion. The hottest combustion gas experiences a temperature drop through the cooler, which heats the water that circulates through the cooler and reheater. Constructal design is implemented in order to determine flow configurations that are superior. The overall heat transfer area is constrained (finite). We show that the most effective allocation of the heat transfer area can be pursued so that the maximum heat transfer density (or, compactness, as watts per volume) is achievable. The paper also documents two design candidates at the cooler outlet (with and without a maximum allowable gas stream temperature) and considers the balanced and unbalanced counter flows. The performance is superior when more degrees of freedom are allowed in the design. Copyright © 2015 John Wiley & Sons, Ltd.     

Highly integrated post‐combustion carbon capture process in a coal‐fired power plant with solar repowering

While post‐combustion carbon capture (PCC) technology has been considered as the ready‐to‐retrofit carbon capture solution, the implementation of the technology remains hampered by high costs associated with the large energy penalty incurred by solvent regeneration. This paper presents a highly integrated PCC process for a coal‐fired power plant with solar repowering that features significantly enhanced energy efficiency. Validated process models are developed for the power, capture, and solar thermal plants and simulated in a model superstructure to evaluate the possible improvements in power plant energy efficiency and power output penalty reductions. A 660‐MW power plant is taken as the case study. Three cases are used in this simulation analysis: (a) base case consisting of 660‐MW power plant integrated with a PCC plant, (b) the base case extended to incorporate solar repowering, and (c) a highly integrated case that extends on the previous case to include CO₂ gas compression unit heat integration. This study also highlights and discusses the role and interaction of various PCC and solar plant variables (e.g., solar field size, steam extraction flow rate, and twin LP turbine pressures) in the integration with power plant parameters. In particular, the power plant deaerator conditions play an important role in determining the total solar thermal energy required from the solar plant, thus dictating the solar field size. Copyright © 2015 John Wiley & Sons, Ltd.     

Performance analysis of a double calcium looping‐integrated biomass‐fired power plant: Exploring a carbon reduction opportunity

Integrating biomass energy generation with carbon capture will result in “carbon neutral” to “carbon negative” technology. Countries like India and China possess significant reserves of limestone. Calcium looping (CaL) technology can prove to be a promising option for carbon capture in these countries. The present work aims at improving the performance of CaL‐integrated biomass‐fired power plant (BFPP) by exploring different looping configurations. In this study, (i) standalone BFPP, (ii) conventional CaL (single stage), and (iii) double CaL‐integrated BFPP have been systematically evaluated. A comparative performance evaluation of these three plants in terms of energy, exergy and ecological assessment, has been carried out. A detailed parametric study and unit‐wise exergy analysis of the best configuration among the three are presented to identify the scope for further improvement in efficiency and energy savings.     

Carbon dioxide sequestration effects on coal's hydro‐mechanical properties: a review

Carbon dioxide (CO₂) sequestration in deep un‐minable coal seam causes the seam's permeability and strength to be significantly reduced because of CO₂ adsorption‐induced matrix swelling. This paper reviews this swelling process in coal and its influence on coal's flow and strength properties. The amount of swelling depends on the properties of both the gas and the coal mass. The swelling caused by CO₂ adsorption is higher compared with that caused by CH₄ and N₂ and greatly depends on the state of the CO₂ phase. The super‐critical state of CO₂ adsorption causes greater swelling compared with the sub‐critical state. It has been observed that the swelling rate increases with increasing CO₂ pressure; however, high saturation pressures may cause the coal matrix to shrink. The swelling rate reduces with increasing temperature, and the effect of coal rank on swelling still remains unclear. The CO₂ adsorption‐induced swelling effect causes the coal mass permeability to be significantly reduced, and the reduction is significant for super‐critical CO₂.The effect of swelling on coal permeability reduces with increasing temperature. The coal matrix swelling and associated polymer structure re‐arrangement occur in the coal mass during and after the CO₂ injection, resulting in the weakening of the coal mass strength. The strength reduction is much higher for high rank coal compared with low rank coal. It is also observed that the influence of super‐critical CO₂ on strength is more powerful than that of sub‐critical CO₂. Although CO₂ sequestration in deep coal seams has been carried out in several main coal seams in the USA, Australia and some other countries, none of these projects has achieved the original target of storing large amounts of CO₂, possibly because initial analysis did take into account the effects of coal seam property changes because of the adsorption of CO₂ during and after injection. Copyright © 2012 John Wiley & Sons, Ltd.     

Techno‐economic comparison of boiler cold‐end flue gas heat recovery processes for efficient hard‐coal‐fired power generation

An important method to increase the efficiency of thermal power plants is to recover the exhaust gas heat at the boiler cold‐end with the stepwise integration of a steam turbine heat regenerative system. To this end, there are currently three typical heat recovery processes, that is, a low‐temperature economizer (LTE), segmented air heating (SAH) and bypass flue (BPF). To provide useful guidance to thermal power plants for optimal and efficient processes, the thermal economy and techno‐economic performance of the three aforementioned processes were calculated and compared using an in‐service 600‐MW hard‐coal‐fired ultra‐supercritical power unit as a reference. The results demonstrate that with the use of the LTE, SAH and BPF, respectively, to recover the exhaust heat, reducing the exhaust temperature from 122 °C to 90 °C, the net standard coal consumption rate of the 600‐MW unit can be reduced by 1.51, 1.71 and 2.81 g/(kW h). The initial costs of the three heat recovery projects are 1.69, 2.91 and 2.53 million USD. If the 600‐MW unit runs 5500 h per year at the rated load, the three processes can increase the earnings of the unit by 0.49, 0.52 and 0.94 million USD from coal savings annually, meaning that their dynamic payback periods are 4.42, 8.66 and 3.29 years, respectively. The results indicate that for a hard‐coal‐fired power unit, the coal savings achieved by exhaust heat recovery are notable. Among the three processes, SAH shows the worst techno‐economic performance because it induces a significant increase in initial costs while obtaining a limited increase in thermal economy, while BPF exhibits the best techno‐economic performance owing to the significant increase in thermal economy. Copyright © 2016 John Wiley & Sons, Ltd.     

A novel approach for treatment of CO2 from fossil fired power plants. Part B: The energy suitability of integrated tri-reforming power plants (ITRPPs) for methanol production

In Part A of this two-paper work, a novel approach for treatment of CO₂ from fossil fired power plants was studied. This approach consists of flue gases utilization as co-reactants in a catalytic process, the tri-reforming process, to generate a synthesis gas suitable in chemical industries for production of chemicals (methanol, DME, ammonia and urea, etc.). In particular, the further conversion of syngas to a transportation fuel, such as methanol, is an attractive solution to introduce near zero-emission technologies (i.e. fuel cells) in vehicular applications. In fact, the methanol can be used in DMFC (Direct Methanol Fuel Cell) or as fuel for on-board reforming to produce hydrogen for PEMFC (Proton Exchange Membrane Fuel Cell).     

Sustainable energy systems: Role of optimization modeling techniques in power generation and supply—A review

Electricity is conceivably the most multipurpose energy carrier in modern global economy, and therefore primarily linked to human and economic development. Energy sector reform is critical to sustainable energy development and includes reviewing and reforming subsidies, establishing credible regulatory frameworks, developing policy environments through regulatory interventions, and creating market-based approaches. Energy security has recently become an important policy driver and privatization of the electricity sector has secured energy supply and provided cheaper energy services in some countries in the short term, but has led to contrary effects elsewhere due to increasing competition, resulting in deferred investments in plant and infrastructure due to longer-term uncertainties. On the other hand global dependence on fossil fuels has led to the release of over 1100 GtCO₂ into the atmosphere since the mid-19th century. Currently, energy-related GHG emissions, mainly from fossil fuel combustion for heat supply, electricity generation and transport, account for around 70% of total emissions including carbon dioxide, methane and some traces of nitrous oxide. This multitude of aspects play a role in societal debate in comparing electricity generating and supply options, such as cost, GHG emissions, radiological and toxicological exposure, occupational health and safety, employment, domestic energy security, and social impressions. Energy systems engineering provides a methodological scientific framework to arrive at realistic integrated solutions to complex energy problems, by adopting a holistic, systems-based approach, especially at decision making and planning stage. Modeling and optimization found widespread applications in the study of physical and chemical systems, production planning and scheduling systems, location and transportation problems, resource allocation in financial systems, and engineering design. This article reviews the literature on power and supply sector developments and analyzes the role of modeling and optimization in this sector as well as the future prospective of optimization modeling as a tool for sustainable energy systems.     

A generic methodology to evaluate economics of hydrogen production using energy from nuclear power plants

Hydrogen, the deemed future transportation fuel can be produced from nuclear assisted energy sources. Assessment of economics of hydrogen production using energy from nuclear power plants is vital for asserting its competitiveness with competing technologies. A generic method is presented in this paper to evaluate Levelised Hydrogen Generation Cost, based on the discounted cash flow analysis. The method is illustrated by consideration of a typical case of hydrogen production via conventional electrolysis using electrical energy supplied from a pressure tube type boiling light water cooled heavy water moderated reactor concept.     

A comprehensive techno‐economic analysis method for power generation systems with CO2 capture

A new comprehensive techno‐economic analysis method for power generation systems with CO₂ capture is proposed in this paper. The correlative relationship between the efficiency penalty, investment increment, and CO₂ avoidance cost is established. Through theoretical derivation, typical system analysis, and variation trends investigation, the mutual influence between technical and economic factors and their impacts on the CO₂ avoidance cost are studied. At the same time, the important role that system integration plays in CO₂ avoidance is investigated based on the analysis of a novel partial gasification CO₂ recovery system. The results reveal that for the power generation systems with CO₂ capture, the efficiency penalty not only affects the costs on fuel, but the incremental investment cost for CO₂ capture (U.S.$ kW⁻¹) as well. Consequently, it will have a decisive impact on the CO₂ avoidance cost. Therefore, the added attention should be paid to improve the technical performance in order to reduce the efficiency penalty in energy system with CO₂ capture and storage. Additionally, the system integration may not only decrease the efficiency penalty, but also simplify the system structure and keep the investment increment at a low level, and thereby it reduces the CO₂ avoidance cost significantly. For example, for the novel partial gasification CO₂ recovery system, owing to system integration, its efficiency can reach 42.2%, with 70% of CO₂ capture, and its investment cost is only 87$ kW⁻¹ higher than that of the reference IGCC system, thereby the CO₂ avoidance cost is only 6.23$ t⁻¹ CO₂. The obtained results provide a comprehensive technical–economical analysis method for energy systems with CO₂ capture useful for reducing the avoidance costs. Copyright © 2009 John Wiley & Sons, Ltd.