A Coal-Fired Power Plant With Zero Atmospheric Emissions

This paper presents the thermodynamic and cost analysis of a coal-based zero-atmospheric emissions electric power plant. The approach involves an oxygen-blown coal gasification unit. The resulting synthetic gas (syngas) is combusted with oxygen in a gas generator to produce the working fluid for the turbines. The combustion produces a gas mixture composed almost entirely of steam and carbon dioxide. These gases drive multiple turbines to produce electricity. The turbine discharge gases pass to a condenser where water is captured. A stream of carbon dioxide then results that can be used for enhanced oil recovery or for sequestration. The term zero emission steam technology is used to describe this technology. We present the analysis of a 400MW electric power plant. The power plant has a net thermal efficiency of 39%. This efficiency is based on the lower heating value of the coal, and includes the energy necessary for coal gasification, air separation, and for carbon dioxide separation and sequestration. This paper also presents an analysis of the cost of electricity and the cost of conditioning carbon dioxide for sequestration. Electricity cost is compared for three different gasification processes (Texaco, Shell, and Koppers-Totzek) and two types of coals (Illinois 6 and Wyodak). COE ranges from 5.95¢∕kWhto6.15¢∕kWh, indicating a 3.4% sensitivity to the gasification processes considered and the coal types used.

Life cycle energy-economy-environmental evaluation of coal-based CLC power plant vs. IGCC, USC and oxy-combustion power plants with/without CO2 capture

This paper presents a theoretical thermodynamic analysis of a zero-atmospheric emissions power plant. In this power plant, methane is combusted with oxygen in a gas generator to produce the working fluid for the turbines. The combustion produces a gas mixture composed of steam and carbon dioxide. These gases drive multiple turbines to produce electricity. The turbine discharge gases pass to a condenser where water is captured. A stream of pure carbon dioxide then results that can be used for enhanced oil recovery or for sequestration. The analysis considers a complete power plant layout, including an air separation unit, compressors and intercoolers for oxygen and methane compression, a gas generator, three steam turbines, a reheater, two preheaters, a condenser, and a pumping system to pump the carbon dioxide to the pressure required for sequestration. This analysis is based on a 400 MW electric power generating plant that uses turbines that are currently under development by a U.S. turbine manufacturer. The high-pressure turbine operates at a temperature of 1089 K (1500°F) with uncooled blades, the intermediate-pressure turbine operates at 1478 K (2200°F) with cooled blades and the low-pressure turbine operates at 998 K (1336°F). The power plant has a net thermal efficiency of 46.5%. This efficiency is based on the lower heating value of methane, and includes the energy necessary for air separation and for carbon dioxide separation and sequestration.

This paper presents a thermodynamic analysis of a natural gas zero-atmospheric emissions power plant with a net electrical output of 400 MW. In this power plant, methane is combusted with oxygen in a gas generator to produce the working fluid for the turbines. The combustion produces a gas mixture composed of steam and carbon dioxide. These gases drive multiple turbines to produce electricity. The turbine discharge gases pass to a condenser where water is captured as liquid and gaseous carbon dioxide is pumped from the system. The carbon dioxide can be economically conditioned for enhanced recovery of oil, or coal-bed methane, or for sequestration in a subterranean formation. The analysis considers a complete power plant layout, including an air separation unit, compressors and intercoolers for oxygen and methane compression, a gas generator, three steam turbines, a reheater, a preheater, a condenser, and a carbon dioxide pumping system to pump the carbon dioxide to the pressure required for sequestration. The computer code is a powerful tool for estimating the efficiency of the plant, given different configurations and technologies. The efficiency of the power plant has been calculated over a wide range of conditions as a function of the two important power plant parameters of turbine inlet temperature and turbine isentropic efficiency. This simulation is based on a 400 MW electric power generating plant that uses turbines that are currently under development by a U.S. turbine manufacturer. The high-pressure turbine would operate at a temperature of 1089 K (1500 °F) with uncooled blades, the intermediate-pressure turbine would operate at 1478 K (2200 °F) with cooled blades and the low-pressure turbine would operate at 998 K (1336 °F). The corresponding turbine isentropic efficiencies for these three turbines were taken as 90, 91 and 93 percent. With these operating conditions, the zero-atmospheric emissions electric power plant has a net thermal efficiency of 46.5%. This net thermal efficiency is based on the lower heating value of methane, and includes the energy necessary for air separation and for carbon dioxide separation and sequestration.

Our way of life is on a collision course with geological limitations. Ever since petroleum geologist M. King Hubbard correctly predicted in l956 that U.S. oil production would reach a peak in l973 and then decline (1), scientists and engineers have known that worldwide oil production would follow a similar trend. Today, the only question is when the world peak will occur.The U.S. transportation system depends almost entirely (∼97%) on oil (2), and foreign imports have risen steadily since l973 as the demand increased and domestic supplies decreased. Today, more than 60% of U.S. oil consumption is imported and the dependence on foreign oil is bound to increase. There is no question that once the world peak is reached and oil production begins to drop, either alternative fuels will have to be supplied to make up the difference between demand and supply, or the cost of fuel will increase precipitously and create an unprecedented social and economic crisis for our entire transportation system.Among energy analysts the above scenario is not in dispute. There is, however, uncertainty about the timing. Bartlett (3) has developed a predictive model based on a Gaussian curve similar in shape to the data used by Hubbard as shown in Fig. 1. The predictive peak in world oil production depends only on the assumed total amount of recoverable reserves. According to a recent analysis by the Energy Information Agency (4), world ultimately recoverable oil reserves are between 2.2×1012 barrels (bbl) and 3.9×1012bbl with a mean estimate of the USGS at 3×1012bbl. But changing the total available reserve from 3×1012bbl to 4×1012bbl increases the predicted time of peak production by merely 11yr, from 2019 to 2030. The present trend of yearly increases in oil consumption, especially in China and India, shortens the window of opportunity for a managed transition to alternative fuels even further. Hence, irrespective of the actual amount of oil remaining in the ground, peak production will occur soon and the need for starting to supplement oil as the primary transportation fuel is urgent because an orderly transition to develop petroleum substitutes will take time and careful planning.Some analysts claim that hydrogen can take the place of petroleum in a future transportation system (56). But in previous publications, the authors have shown that hydrogen is inferior as an energy carrier to electricity (7) and that the energy efficiency of hydrogen vehicles, especially if the hydrogen were produced by the electrolysis of water, is considerably less than the efficiency of hybrid electric vehicles or fully electric battery vehicles (7). The results of these analyses have subsequently been confirmed by other studies, particularly those by Hammererschlag and Mazza (8) and Mazza and Hammerschlag (9).Before hydrogen could become a useful automotive fuel, an entirely new system of energy production and distribution on twice the scale of today’s electric power generating stations and distribution grid would have to be built. It has been estimated that a hydrogen transmission and storage system to fuel only 50% of the automotive fleet by the year 2020 would cost at least $600 billion (10) and that to make the hydrogen by electrolysis would require doubling the electric power generation rate (11). There is no question that a paradigm shift in fuel for worldwide transportation is imperative, and before embarking on such a huge investment, it is prudent to compare the hydrogen option with alternative ways to provide the energy and/or fuel needed by the transportation system.This paper presents and analyzes two generic approaches to meet the future demand of the U.S. ground transportation systems that do not require hydrogen, can use existing transmission infrastructure, and can eventually reduce CO2 emission drastically with a renewable energy system. Both these pathways are examined from an energetic and environmental perspective and are shown to be superior to the hydrogen economy on both these criteria. The first approach is a demand-side strategy based on the use of electric hybrid vehicles, an energy-efficient vehicle configuration, combined with a liquid fuel. This approach could use the existing liquid-fuel distribution system, but would need an expanded and robust electric-transmission system, albeit on a smaller and much more economical scale than a hydrogen fuel-cell infrastructure. The second approach is a supply-side strategy, based on synthetic fuel generation that can use initially coal or natural gas as the energy source, but can eventually transition to renewable biomass sources. The two pathways are not mutually exclusive, but can be combined into a secure and efficient future transportation system as will be shown in this paper.Cradle-to-grave energy efficiency is an important criterion for comparing energy-source utilization pathways because if a pathway is less efficient than another pathway that accomplishes the same final goal from the same amount of primary energy, then the less efficient pathway requires more primary energy to accomplish the same end. Hence, if the primary energy source is nonrenewable, then the less efficient pathway leaves less of the energy source for the future. It also means that more pollution is produced and the cost for the final end use is likely higher. However, if the primary energy source is renewable, then the efficiency does not change the amount of primary energy available in the future and energy efficiency does not have the same significance for renewable energy sources as for nonrenewable sources. Efficiency is, of course, important because the cost of delivering the energy is usually strongly influenced by the system efficiency. But a comparison between renewable and nonrenewable pathways should be based on economic and environmental criteria, such as cost and CO2 generation.In order to demonstrate the urgency for initiating a plan to supplement oil as soon as possible, we have made calculations to predict the potential gasoline savings based on the very optimistic scenario that, at an arbitrary starting time, all new light vehicles sold in the U.S. would be either hybrid or electric vehicles. The term “light vehicles” as used here includes all automobiles, family vans, sports utility vehicles, motorcycles, and pickup trucks. This scenario is an extreme case to show that because of the slow turnover of the light-vehicle fleet, it takes a long time for a significant impact on gasoline consumption to occur. The following cases are considered: (i) All new vehicles sold are gasoline-electric hybrid vehicles (HEV); (ii) all new vehicles sold are plug-in, gasoline-electric hybrids with a 20mil electric-only range (PHEV20); (iii) all new vehicles are diesel-electric hybrids (DHEV) with diesel fuel from coal or biomass; (iv) all new vehicles are plug-in, diesel hybrids with a 20mil all-electric range (PDHEV20); or (v) all new vehicles are all-electric vehicles (EV).The calculations use a rate of new vehicle sales of 7% of the fleet per year, a retirement rate of 5%/y, and a resulting net increase in total vehicles of 2%/y. These numbers represent an approximate fit to the light-vehicle sales and total number data for the years 1966 to 2003 reported by the U.S. government (12). All calculated results are presented in percentages and are therefore independent of the time at which all new vehicle sales switch to hybrids or EVs. When new car sales begin to be all hybrids or all EVs, it is assumed that the future rate of retirement of vehicles from the all-gasoline fleet is 5%/y of the remaining gasoline vehicles. The all-gasoline fleet is therefore completely retired 20 years later. The yearly rate of retirement of hybrid or EV vehicles is then 5% of the total number of vehicles at the beginning of that year, less 5% of the number of gasoline vehicles at the beginning of year zero. Thus, in year zero, no hybrid or EVs are retired.The following average vehicle mileage values were used: gasoline fleet, 21mpg (miles per gallon); gasoline HEV, 41mpg; gasoline PHEV 20, 56mpg of gasoline (13). A mileage is not needed for the EVs, or the diesels, since neither use gasoline, and we assume that the diesel fuel will be derived from nonpetroleum sources, as discussed in Secs. 34.The results of these calculations are presented in Figs. 234. Figure 2 shows the ratio of the total number of vehicles in the fleet, the number of all-gasoline vehicles in the fleet, and the number of hybrid or EV vehicles in the fleet to the total number in the fleet as a function of time. The total number of vehicles increases by over 60% in 25 years at the assumed 2%/y net increase while the number of all-gasoline vehicles decreases linearly from 100% initially to 0% after 20y. The number of hybrid or EV vehicles increases from 0% initially to 58% in 10y and 100% in 20y. This graph emphasizes how long it takes for the introduction of a new vehicle type to show a significant impact on the composition of the vehicle fleet, even when only the new vehicle types are sold after a starting point. This slow turnover of the fleet is the fundamental reason that the effects on gasoline consumption show up so slowly.Figure 3 shows the annual reduction in gasoline consumption as a function of time. Note that for HEVs the annual savings in gas consumption is 29% of the gasoline consumption for a conventional fleet in the tenth year and becomes constant at 49% in the twentieth year. Figure 3 also shows that the plug-in gasoline hybrid scenario saves 41% of the usage in the tenth year and increasing to 64% in the twentieth year and thereafter. Clearly, 10y after starting to sell only hybrid or EV vehicles, the impact of the HEV or PHEV20 scenarios on gasoline consumption is still rather small. After 20yr, the impact becomes significant, but gasoline consumption still remains high for gasoline hybrids. The total number of vehicles and the consumption (with the assumption of no efficiency improvement) by an all-gasoline fleet will have increased by more than 60%, but even the PHEV20 savings is only 40% of the zero-time annual-rate of gasoline consumption. The DHEV, DPHEV20, and EV scenarios show 59% annual savings in the tenth year and 100% in the twentieth year and thereafter. As would be expected, the nongasoline vehicles have a much greater impact on gasoline usage than gasoline-using HEVs, and the impact occurs more rapidly.Figure 4 gives the cumulative gasoline savings for the various scenarios compared to an all-gasoline fleet. HEVs save cumulatively 16% after 10yr and 20% after 20 years. Because of the cumulative savings, HEVs would use in 28yr the same amount of gasoline as an all-gasoline fleet would use in 20yr. PHEV20s save 21% after 10yr and 38% after 20yr. These results emphasize the relatively small effect on gasoline consumption that these highly optimistic scenarios have in the first decade after implementation. DHEVs, DPHEV20s, and EVs, the options without any gasoline use, save cumulatively as much as 32% after 10yr and 59% after 20yr.A 2004 report of the Committee on Alternatives and Strategies for Future Hydrogen Production and Use (14), prepared under the auspices of the National Research Council (NRC), concluded that the vision of a hydrogen economy is based on the expectation that hydrogen can be produced from domestic energy sources in a manner that is “both affordable and environmentally benign.” An analysis of currently available technologies for achieving this goal (7) showed that irrespective of whether fossil fuels, nuclear fuels or renewable technologies are used as the primary energy source, hydrogen is inefficient compared to using the electric power or heat from any of these sources directly. Given these facts, it is important to note that the NRC report also stated that “If battery technology improves dramatically, all-electric vehicles might become the preferred alternative (to fuel cell electric vehicles).” The report also noted that “Hybrid vehicle technology is commercially available today and can therefore be realized immediately.” If synthetic fuels made from coal, natural gas, or biomass were used in place of gasoline in hybrid vehicles, the consumption of oil could be reduced immediately and eventually eliminated. In the light of these observations, it is therefore important to examine what the current state of battery technology is, what can be expected in the near future, and how these developments affect the potential of hybrid vehicle performance and economics.To assess the performance of a battery for electric vehicles, the following characteristics have to be considered: Specific energy, a measure of the battery weight in units of watt hours per kilogramEnergy density, a measure of the space the battery occupies in watt hours per cubic meterCapacity, the total quantity of energy a battery can store and later deliver in watt hoursEfficiency, the ratio of energy that can be extracted from the battery to the initial energy input to change the batterySpecific power, the rate at which the battery can deliver the stored energy per unit weight of battery in watts per kilogramBattery lifecycle, the number of charge and discharge cycles that a battery can sustain during its lifeA significant effort to replace oil as a transportation fuel was undertaken ten years ago in California, when the California Air Resources Board [CARB] mandated that a certain percentage of all vehicles sold in California had to have zero tailpipe emissions (15). At that time the only technology available to meet the mandate was the all battery electric vehicle [BEV], which required no gasoline for its operation. The experiment to mandate the use of BEVs in California failed because the technology was not ready for commercialization. The best battery available in 1995 (fluted-tubular lead acid) had an energy storage density of 35Wh∕kg, a specific power of 100W∕kg, and a life cycle of 600-1000cycles. With these battery characteristics, the maximum range of a BEV was only 50mil, and the battery pack required replacement every 25,000mil at a cost of between $7000 and $8000 for an average BEV (16). Since that time, new batteries have been developed by Panasonic, VARTA, and SAFT, that have twice the energy-storage density, three times the specific power, and two or three times the cycle life of the lead acid batteries sold in California, as shown in Table 1 (13).In addition to the advanced batteries, a new concept has been developed that combines the best qualities of hybrid and battery vehicle technologies. This “plug-in hybrid vehicle” can recharge vehicle batteries during off-peak hours, and since most cars are parked 90% of the time, there are plenty of charging opportunities at both home and the workplace. Furthermore, a large portion of the electric generation infrastructure is only needed for peak demands and lays idle much of the time. Hence, if charging automobile batteries occurred during off-peak hours, they would level out the load of the electric production system and reduce the average cost of electricity (17). Moreover, plug-in hybrid vehicles are not range limited because they have an engine that can refuel at existing gas stations to use when the batteries are low.The efficiency of a PHEV depends on the number of miles the vehicle travels on liquid fuel and electricity, respectively, as well as on the efficiency of the prime movers according to1η=energytowheelsenergyfromprimarysource=f1η1η2+f2η3η4where η1 is the efficiency of the primary source of electricity, η2 is the efficiency of transmitting electricity to the wheels, f1 is the fraction of energy supplied by electricity, f2 is the fraction of energy supplied by fuel =(1−f1), η3 is the efficiency of primary source to fuel, and η4 is the efficiency of fuel to wheels.PHEVs can be designed with different all-electric ranges. The distance, in miles, that a PHEV can travel on batteries alone is denoted by a number after PHEV. Thus, a PHEV20 can travel 20mil on fully charged batteries without using the gasoline engine. According to a study by EPRI (13), on average 1/3 of the annual mileage of a PHEV20 is supplied by electricity and 2/3 by gasoline. The percentage depends, of course, on the vehicle design and the capacity of the batteries on the vehicle. A PHEV60 can travel 60mil on batteries alone, and the percentage of electric miles will be greater as will the battery capacity.The tank-to-wheel (more appropriately, battery-to-wheel) efficiency for a battery all-electric vehicle according to EPRI (13) is 0.82. In a previous analysis by the authors (18), the efficiency in 1993 was only 0.49. Comparing these results shows the enormous improvements in the electric component efficiency (controller 87%, battery 90%, charger 90%, drivetrain 90%;). When these numbers are multiplied by a hybrid-weight-times-idle factor of 1.3 (19), the overall efficiency of an electric hybrid is 82%, the same as that used in the EPRI study (13). It is important to note that currently all-electric vehicles can be nearly twice as efficient as when (18) was published.Given the potentials for plug-in hybrid vehicles, the Electric Power Research Institute (13) conducted a large-scale analysis of the cost, the battery requirements, and the economic competitiveness of plug in vehicles today and within the near term future. Table 2 presents the net present value of life-cycle costs over ten years for a midsized combustion vehicle [CV], hybrid vehicle [HEV] and a plug in electric vehicle with a 20mil electric-only range [PHEV20]. The battery module cost in dollars per kilowatt is the cost at which the total life-cycle costs of all three vehicles would be the Figure presents cost for battery as a function of number of units produced per year. According to this a production of about units per year units would the cost reduction to make both hybrid electric vehicles and plug in electric vehicles 3 presents the electric and plug-in hybrid vehicle battery that would be to make electric vehicles cost for vehicles according to EPRI (13). As shown in Table the characteristics of batteries, and batteries are to meet the required cost and performance The battery characteristics shown in Table 1 and Fig. are years and it is likely that more from would show Furthermore, the EPRI study assumed a current gasoline cost of A of the analysis based on a gasoline cost of that the battery at which the net present values of conventional combustion vehicles and battery vehicles are would up from to for an HEV and from to for a PHEV Figure shows the cost for batteries production for Hence, it that the cost of HEVs and with available batteries is with that of engine The EPRI analysis is because it compared the performance of all battery electric and plug in hybrid vehicles only to currently available combustion as shown in the use of diesel in a hybrid would increase the efficiency of compared to a hybrid with engine and the amount of fuel Hence, it be concluded that the EPRI analysis is it includes advanced batteries, it does not the increased efficiency by using diesel of combustion Furthermore, diesel fuel, as will be shown in can be produced from coal or renewable sources as can the electric power required for charging the The introduction of to the energy is the of this it is and can be as renewable technologies become more cost and fossil fuels more natural gas and biomass can be into liquid the most fossil fuel in the is used almost to In order to make coal into a vehicle fuel, it first be to a gas by a of The of this then be to of that can be used as vehicle fuel. biomass and natural gas can be used of coal or combined with coal to make these and are discussed gas can be used as a vehicle fuel, or it can be with to make gas, which can be used to fuels in the same manner as for The technology is well developed as shown by the recent of of which will natural gas, which is currently to liquid fuel. These and a in of which is diesel in With a with an estimated billion and a diesel with the of with an estimated at The of natural gas to make vehicle fuels was discussed in an paper by the authors (18), and of those results are presented later for comparison with coal as the fuel It should also be noted that biomass can be either alone or in with coal and to liquid fuels by the same as coal, or it can also be and then into vehicle fuels as in is a that is a in the production of synthetic liquid fuels from coal for transportation The coal is shown in Fig. It a such as coal or with to and This gas can be to hydrogen or to make or can be used as a transportation fuel in but this study on diesel fuel because are more the first of the coal is with limited to and The in the coal is to hydrogen gas, and are as In the shift is with to and The and hydrogen are from the and to the or into The that is in this is from the in a for Thus, it can be from the and are the costs when liquid fuel is produced from The estimated time of for a is to years. The depends on the production capacity of the the cost of a with a capacity to barrels of liquid fuel per is estimated to be of the order billion of coal claim that there will be gas pollution from the However, in the future vehicle emissions of can be reduced those of vehicles, by the use of plug-in hybrid electric vehicles and by of the from the fuel production is a synthetic diesel fuel that can be made from coal by of The is first to make which can then be to The is to the and the gas is to electricity for the as shown in Fig. is a gas at but can be under and then can be to other liquid of make it an fuel for It is similar to but has a number The number to the of a fuel to With combustion of the fuel occurs after and emissions are as a of combustion The combustion also in by the need for to the shown in Fig. coal into liquid fuel. The was by scientists before and is used today in by to make diesel fuel gas to make a liquid fuel of synthetic diesel fuel, which is similar to and which is used to make synthetic gasoline (7). The is from the liquid diesel and to the The gas resulting from is to electricity for the can be made from coal by by gas After the hydrogen gas and are from the gas, and hydrogen are The hydrogen can be stored and the can be for electricity and/or to the shift as shown in Fig. store and the hydrogen, it is either to it to or to it at a The efficiency of the first option is while the second is efficient (7). Both and hydrogen have been for fuel storage in a of hydrogen fuel-cell vehicles is in the of coal or natural gas into a vehicle fuel. The energy efficiency of these is important in the overall well to efficiency of these alternative Table 4 presents or efficiency for various fuels from coal or natural and have reported the and energy for with of the and values are used (18) presented for natural gas without and estimated that of CO2 the efficiency of by about two percentage Since natural gas only about as much per unit of energy as coal, it has been assumed that will reduce the efficiency of to fuels by percentage point. Thus, percentage has been from values reported by (18) to the values shown in Table In the of data for the of natural gas to the authors assumed that the ratio of the for natural gas is the same as that for coal to estimate this efficiency as shown in Table 4 that the production of liquid fuels from natural gas is more efficient than from But is in and the technology is not a It is however, for the that is currently into the in gasoline The of of these has been But production is the more for the term and does not require hydrogen as a fuel or energy Today, the of fuel from coal, at the only in The of supplies of such fuels as gasoline, and The economic and of coal have been U.S. and for a fuel in using technology and are to the that will have a capacity to of diesel fuel. has in recent NRC study other technologies that could synthetic fuels from biomass and presents a comparison of the energy on energy for production from and These significant in synthetic But the for synthetic fuel production need to be multiplied before synthetic fuels can make up for the between demand and of gasoline after the peak in oil production is on the analysis presented in this we the following and oil production is expected to peak within the and as is liquid fuel are expected to increase This could lead to a crisis in the U.S. transportation system that on 60% of which is options for a transportation crisis by and/or liquid fuels derived from petroleum with synthetic fuels from natural gas, or coal and by demand by increasing the efficiency and mileage of options to have impact they be at least before hybrid vehicles are a option to reduce the liquid fuel consumption of future transportation hybrid vehicles can the existing infrastructure for electric power transmission by charging batteries during peak hours and use liquid fuels only for a fraction of overall power hybrid vehicles can diesel that can be by synthetic fuels derived from coal, natural gas, or use efficiency is increased efficiency alone will not be to the transportation without the production of large of synthetic liquid number of technologies for synthetic diesel that can be used in diesel and reduce emission of that lead to scale of effort required to provide synthetic fuels will require years to and should therefore be as soon as hybrid or all-electric vehicles with available battery technology in an are compared to gasoline of the of the transportation it is that be by government such as for the of synthetic fuels and CO2 high liquid fuel mileage for automobiles, and for efficient plug-in hybrid scenario in this paper for a secure transportation system can be immediately with available technologies and without hydrogen or authors to for as of an independent study for the of at the of

Carbon dioxide from oxy-fuel coal-fired power plant integrated green ammonia for urea synthesis: Process modeling, system analysis, and techno-economic evaluation

Power plants, which are major point source of air pollutants, contribute significantly to the overall ambient air particulate matter (PM) loading. Due to low grade of coal utilized in the power plants, emitted gases and PM affect the environment as well as public health. Gaseous as well as particulate emissions from power plants depend on types of coal and combustion conditions. Coal is subjected to various processes from arrival up to the combustion in a power plant. Particle size distribution and composition of PM emitted by coal combustion sources vary according to various formation and transformation processes to which they are subjected during their lifetime such as grade of coal, pulverization, and storage and combustion conditions including type of boiler, etc. Gaseous emissions in large amount from stack of power plants include gases such as sulfur dioxide, carbon monoxide, oxides of nitrogen, carbon dioxide, and volatile organic compounds. Respirable particulate matter is also emitted at a large scale in the form of fly ash, bottom ash, and flue gas. Toxicity associated with suspended PM can deteriorate human health by penetrating and affecting human respiratory system. Apart from this, these emissions can alter the atmospheric radiation balance by inducing climate forcing, and provide excess condensation nuclei for fog and cloud formation, thereby significantly altering the regional level weather conditions and patterns. Advanced techniques to track the precursors of PM such as stable isotope analysis and metal identification along with various modeling methods can be used quite effectively for understanding the sources and health hazards related to power plants. These mechanisms can be understood by making use of a tracer (such as stable isotope ratios, for example, δ13C or elemental ratios), which can track down the PM formation processes either in the stack exiting flue gases or further downstream from the source. Emissions from coal-fired power plants also contain certain toxic trace metals, which can severely affect the health of general public.

PurposeLignite coal-fired power plants are the main electricity generators in the province of Saskatchewan, Canada. Although burning lignite coal to generate power is economical, it produces significant greenhouse gases making it a big challenge to Canada’s international commitment on emission reduction. However, abundant agricultural crops and sawdust produced in Saskatchewan put the province in a good position to produce and use agri-pellets as an alternative fuel to generate electricity. This study aims to conduct an economic and environmental analysis of the replacement of lignite coal by agri-pellets as the fuel for Saskatchewan’s coal-fired power plants.Design/methodology/approachThe study estimates the economic and environmental costs and benefits of two alternative fuels for power plants. The economic analysis is based on the pellet production and transportation costs from farms to production sites and from the production sites to power plants. In the production process, biomass precursors are densified with and without additives to produce fuel agri-pellets with appropriate mechanical durability and high heating value per volume unit. The environmental analysis involves estimation of greenhouse gas emissions and their social costs for lignite coal and different types of agri-pellets under different scenarios for pellet production and transportation.FindingsThe results show that although the total cost of electricity is lower for coal than agri-pellets, the gap shrinks when social costs and specifically a carbon price of $50/tonne are included in the model. The cost of electricity in lignite coal-fired power plants would also be on par with agri-pellets-fired power plants if the carbon price is between U$68 and $78 per tonne depending on the power plant locations. Therefore, a transition from coal to agri-pellet fuels is feasible if a high-enough price is assigned to carbon. The method and the results can be generalized to other places with similar conditions.Research limitations/implicationsThere are a few caveats in this study as follows. First, the fixed costs associated with the transformation of the existing coal-fired power plants to pellet-fired plants are not considered. Second, the technological progress in the transportation sector, which would favor the net benefits of using pellets versus coal, is not included in the analysis. Finally, the study does not address the possible political challenges facing the transition in the context of the Canadian federal system.Practical implicationsThe study results indicate that the current carbon price of $50 per tonne is not sufficient to make the agri-pellets a feasible source of alternative energy in Saskatchewan. However, if carbon pricing continues to rise by $15 annually starting in 2022, as announced, a transition from coal to agri-pellets will be economically feasible.Social implicationsCanada is committed to reduce its emission according to the Paris agreement, and therefore, needs to have a concrete policy to find alternative energy sources for its coal-fired power plants. This study examines the challenges and benefits of such transition using the existing agri-pellet resources in Saskatchewan, a province with abundant agricultural residues and coal-fired power plants. The findings indicate that a significant emission reduction can be achieved by using agri-pellets instead of coal to produce electricity. The study also implies that the transition to renewable energy is economical when social costs of carbon (carbon tax) is included in the analysis.Originality/valueAs far as the authors know, this is the first study providing a socio-economic analysis for a possible transition from the coal-fired power plants to a more clean and sustainable renewable energy source in one of the highest carbon dioxide (CO2) producer provinces in Canada: Saskatchewan. The study builds upon the technical production of three agri-pellets (oat hull, canola hull and sawdust) and estimates the economic and environmental costs of alternative fuels under different scenarios.

This report describes carbon dioxide (CO{sub 2}) capture options from large stationary emission sources in the Illinois Basin, primarily focusing on coal-fired utility power plants. The CO{sub 2} emissions data were collected for utility power plants and industrial facilities over most of Illinois, southwestern Indiana, and western Kentucky. Coal-fired power plants are by far the largest CO{sub 2} emission sources in the Illinois Basin. The data revealed that sources within the Illinois Basin emit about 276 million tonnes of CO2 annually from 122 utility power plants and industrial facilities. Industrial facilities include 48 emission sources and contribute about 10% of total emissions. A process analysis study was conducted to review the suitability of various CO{sub 2} capture technologies for large stationary sources. The advantages and disadvantages of each class of technology were investigated. Based on these analyses, a suitable CO{sub 2} capture technology was assigned to each type of emission source in the Illinois Basin. Techno-economic studies were then conducted to evaluate the energy and economic performances of three coal-based power generation plants with CO{sub 2} capture facilities. The three plants considered were (1) pulverized coal (PC) + post combustion chemical absorption (monoethanolamine, or MEA), (2) integrated gasification combined cycle (IGCC) + pre-combustion physical absorption (Selexol), and (3) oxygen-enriched coal combustion plants. A conventional PC power plant without CO2 capture was also investigated as a baseline plant for comparison. Gross capacities of 266, 533, and 1,054 MW were investigated at each power plant. The economic study considered the burning of both Illinois No. 6 coal and Powder River Basin (PRB) coal. The cost estimation included the cost for compressing the CO{sub 2} stream to pipeline pressure. A process simulation software, CHEMCAD, was employed to perform steady-state simulations of power generation systems and CO{sub 2} capture processes. Financial models were developed to estimate the capital cost, operations and maintenance cost, cost of electricity, and CO{sub 2} avoidance cost. Results showed that, depending on the plant size and the type of coal burned, CO{sub 2} avoidance cost is between $47/t to $67/t for a PC +MEA plant, between $22.03/t to $32.05/t for an oxygen combustion plant, and between $13.58/t to $26.78/t for an IGCC + Selexol plant. A sensitivity analysis was conducted to evaluate the impact on the CO2 avoidance cost of the heat of absorption of solvent in an MEA plant and energy consumption of the ASU in an oxy-coal combustion plant. An economic analysis of CO{sub 2} capture from an ethanol plant was also conducted. The cost of CO{sub 2} capture from an ethanol plant with a production capacity of 100 million gallons/year was estimated to be about $13.92/t.

The unique chemistry of carbonate fuel cell offers an innovative approach for separation of carbon dioxide from greenhouse gases (GHG). The carbonate fuel cell system also produces electric power at high efficiency. The simultaneous generation of power and sequestration of greenhouse gases offer an attractive scenario for re-powering the existing coal-fueled power plants, in which the carbonate fuel cell would separate the carbon dioxide from the flue gas and would generate additional pollutant-free electric power. Development of this system is concurrent with emergence of Direct FuelCell{reg_sign} (DFC{reg_sign}) technology for generation of electric power from fossil fuels. DFC is based on carbonate fuel cell featuring internal reforming. This technology has been deployed in MW-scale power plants and is readily available as a manufactured product. This final report describes the results of the conceptualization study conducted to assess the DFC-based system concept for separation of CO2 from GHG. Design and development studies were focused on integration of the DFC systems with coal-based power plants, which emit large amounts of GHG. In parallel to the system design and simulation activities, operation of laboratory scale DFC verified the technical concept and provided input to the design activity. The system was studied to determine its effectiveness in capturing more than ninety percent of CO2 from the flue gases. Cost analysis was performed to estimate the change in cost of electricity for a 200 MW pulverized coal boiler steam cycle plant retrofitted with the DFC-based CO2 separation system producing an additional 127 MW of electric power. The cost increments as percentage of levelized cost of electricity were estimated for a range of separation plant installations per year and a range of natural gas cost. The parametric envelope meeting the goal (<20% increase in COE) was identified. Results of this feasibility study indicated that DFC-based separation systems have the potential for capturing at least 90% of the emissions from the greenhouse gases generated by power plants and other industrial exhaust streams, and yet entail in less than 20% increase in the cost of energy services for long-term deployment (beyond 2012). The anticipated cost of energy increase is in line with DOE's goal for post-combustion systems as outlined in the ''Carbon Capture and Sequestration Systems Analysis Guidelines'', published by NETL, April 2005. During the course of this study certain enabling technologies were identified and the needs for further research and development were discussed.

Towering 650 feet over the sea surface and spouting an impressive burning flare, it would be easy to mistake the Sleipner West gas platform for an environmental nightmare. Its eight-story upper deck houses 200 workers and supports drilling equipment weighing 40,000 tons. Located off the Norwegian coast, it ranks among Europe’s largest natural gas producers, delivering more than 12 billion cubic feet of the fuel annually to onshore terminals by pipeline. Roughly 9% of the natural gas extracted here is carbon dioxide (CO2), the main culprit behind global warming. But far from a nightmare, Sleipner West is actually a bellwether for environmental innovation. Since 1996, the plant’s operators have stripped CO2 out of the gas on-site and buried it 3,000 feet below the sea floor, where they anticipate it will remain for at least 10,000 years. We believe [CCS] is a viable way to cut global warming pollution. . . . We have the knowledge we need to start moving forward. –David Hawkins, Natural Resources Defense Council Operated by StatoilHydro, Norway’s largest company, Sleipner is among the few commercial-scale facilities in the world today that capture and bury CO2 underground. Many experts believe this practice, dubbed carbon capture and storage (sometimes known as carbon capture and sequestration, but in either case abbreviated CCS), could be crucial for keeping industrial CO2 emissions out of the atmosphere. Sleipner injects 1 million tons of CO2 annually into the Utsira Formation, a saline aquifer big enough to store 600 years’ worth of emissions from all European power plants, company representatives say. With mounting evidence of climate change—and predictions that fossil fuels could supply 80% of global energy needs indefinitely—the spotlight on CCS is shining as brightly as the Sleipner flare. A panel of experts from the Massachusetts Institute of Technology (MIT) recently concluded that CCS is “the critical enabling technology to reduce CO2 emissions significantly while allowing fossil fuels to meet growing energy needs.” The panel’s views were presented in The Future of Coal, a report issued by MIT on 14 March 2007. Environmental groups are split on the issue. Speaking for the Natural Resources Defense Council (NRDC), David Hawkins, director of the council’s Climate Center and a member of the MIT panel’s external advisory committee, says, “We believe [CCS] is a viable way to cut global warming pollution. . . . We have the knowledge we need to start moving forward.” Other environmental groups, including the World Resources Institute, Environmental Defense, and the Pew Center on Global Climate Change, have also come out in support of CCS. These groups view CCS as one among many alternatives (including renewable energy) for reducing CO2 emissions. Greenpeace is perhaps the most vocal critic of CCS. Truls Gulowsen, Greenpeace’s Nordic climate campaigner, stresses that CCS deflects attention from renewable energy and efficiency improvements, which, he says, offer the best solutions to the problem of global warming. “Companies are doing a lot of talking about CCS, but they’re doing little to actually put it into place,” he says. “So, they’re talking about a possible solution that they don’t really want to implement now, and at the same time, they’re trying to push for more coal, oil, and gas development instead of renewables, which we already know can deliver climate benefits.”

China's retrofitting measures in coal-fired power plants bring significant mercury-related health benefits

Coal could be called energy’s comeback kid: sometimes forgotten, perhaps underappreciated, but always available for one more shot at the big time. It is one of humankind’s original sources of energy, and is used worldwide for cooking, heating, forging steel, and making electricity. In the United States, coal’s role today is limited almost exclusively to electricity generation; for the last decade or so, even that use has stagnated. For years new power facilities that relied on coal were spurned in favor of natural gas, as American electric companies were wooed by the cleaner-burning fossil fuel and its easier-to-site and cheaper-to-build power plants. Still, because so many coal-fired plants were built before the natural gas craze, coal accounts for over 50% of our annual electric generation. And now many energy experts say coal is poised to once again play a prominent role in the United States. Coal does have an appeal. For one thing, there’s plenty of it. It’s located here in the United States, a comfort to those worried about the political and security hazards of overdependence on imported energy. It’s cheap. And its price is stable, at least compared to natural gas. But coal can be ugly, too. If left unchecked with inadequate emissions control, it can emit ash (which has been linked to human cancers and genotoxic effects in some animal studies), sulfur dioxide (which contributes to acid rain), carbon dioxide (CO2; the chief culprit behind global warming), nitrogen oxides (NOx; which can produce smog and low-lying ozone), and mercury (linked to disorders in the kidneys and the nervous, digestive, and respiratory systems). Mining coal can also be a messy business, carving scars into the Earth, releasing clouds of dust, leaving behind sources of acidic water that can persist decades after a mine closes, and requiring dams—“impoundments” in industry lingo—that sometimes break and ravage miles of waterways. In coming years, however, what’s right about coal will almost certainly overpower what’s wrong, says Richard Gendreau, a senior market consultant for R.W. Beck, a Framingham, Massachusetts, management consulting and engineering company. And what’s wrong, he says, will be made better by new technologies and more vigorous application of existing technologies. “The ultimate driver on all of this,” he says, “is that ninety-five percent of our fossil energy reserves—the amount of fossil energy that we have within our boundaries that we can rely on for energy and economic security, as well as national security—is coal.”

The major barriers for applying carbon dioxide (CO 2 ) capture technology to coal-fired power plants in China and worldwide are the consequent drop in power plant energy efficiency and significantly higher cost of electricity (COE). This paper proposes a new perspective for determining the most cost-efficient CO 2 capture ratio using a modeling and simulation approach that balances the per unit parasitic energy consumption for absorbent regeneration with the per unit capital cost of the CO 2 capture unit of a coal-fired power plant. Using a typical 550 MW supercritical pulverized coal-fired power plant in China as the reference plant, with monoethanolamine (MEA) absorption unit for CO 2 capture, a process model of the power generation unit together with the MEA CO 2 capture unit was developed and detailed process simulations were conducted with the model. Then, a sensitivity analysis was then conducted to study the impact on key plant behavior indicators, including per unit energy penalty for absorbent regeneration, net power output and power generation efficiency, total capital cost of the power plant together with the MEA CO 2 absorption unit, per unit capital cost of the MEA unit, COE, as well as the per unit CO 2 avoidance cost (indicated by cost per tonne (t) CO 2 avoided), across a CO 2 capture ratio range between 20% and 99%. The results show that when CO 2 capture ratio is low, while the unit energy consumption for absorbent regeneration per tCO 2 avoided increases steadily with the increase of CO 2 capture ratio, the cost per tCO 2 avoided decreases as the MEA absorption train is scaled up given the high capital cost of each MEA train. After CO 2 capture ratio reaches certain level (60% for this plant), the cost per tCO 2 avoided starts to increase with CO 2 capture ratio, since the unit energy consumption for absorbent regeneration per tCO 2 avoided has increased to so high that it supplants the scaling effect of the MEA train and becomes the dominant factor that determines the increase or decrease trend of the cost per tCO 2 avoided. Besides, due to the physical restraint on the upper bound of CO 2 capture capability of one single MEA train by the diameter of the absorber, an additional MEA train is needed when the CO 2 capture ratio increases to certain points (40% and 85% for this plant), resulting in jumps of several parameters including the total capital cost for the power plant and MEA CO 2 capture unit, per unit capital cost for the MEA CO 2 capture unit, and last the cost per tCO 2 avoided. Based on all these result, finally a cost-optimal CO 2 capture ratio of 40% (365 RMB/tCO 2 -_avoided) was obtained, which is easier for the power plant to bear while realizing a significant reduction in CO 2 emission of this plant. Therefore, applying this approach for determining CO 2 capture ratios could help minimize the barrier for the initiation of carbon dioxide capture and storage (CCS) in China's power industry. Besides, future replacement or improvement for the MEA CO 2 capture technology has the potential to further reduce the cost per tCO 2 avoided, which needs special attention.

A decision analysis model for reducing carbon emission from coal-fired power plants and its compensatory units