Uncertainty analysis of integrated gasification combined cycle systems based on Frame 7H versus 7F gas turbines

Integrated gasification combined cycle (IGCC) technology is a promising alternative for clean generation of power and coproduction of chemicals from coal and other feedstocks. Advanced concepts for IGCC systems that incorporate state-of-the-art gas turbine systems, however, are not commercially demonstrated. Therefore, there is uncertainty regarding the future commercial-scale performance, emissions, and cost of such technologies. The Frame 7F gas turbine represents current state-of-practice, whereas the Frame 7H is the most recently introduced advanced commercial gas turbine. The objective of this study was to evaluate the risks and potential payoffs of IGCC technology based on different gas turbine combined cycle designs. Models of entrained-flow gasifier-based IGCC systems with Frame 7F (IGCC-7F) and 7H gas turbine combined cycles (IGCC-7H) were developed in ASPEN Plus. An uncertainty analysis was conducted. Gasifier carbon conversion and project cost uncertainty are identified as the most important uncertain inputs with respect to system performance and cost. The uncertainties in the difference of the efficiencies and costs for the two systems are characterized. Despite uncertainty, the IGCC-7H system is robustly preferred to the IGCC-7F system. Advances in gas turbine design will improve the performance, emissions, and cost of IGCC systems. The implications of this study for decision-making regarding technology selection, research planning, and plant operation are discussed.     

Gas Cleaning Systems for the High Temperature,High Pressure Fluidized Bed Coal Combustor

The high temperature, high pressure fluidized bed coal combustor concept is intended to deliver a low dust content combustion gas at 1600°F and 11 atmospheres to a gas turbine for electricity generation. The perceived advantages of the system are 1) 15-20% increase in fuel efficiency and 2) flue gas desulfurization by adding crushed limestone to the fluidized bed combustor. A major R & D effort, supported by DOE, EPA, EPRI, and others, was undertaken to identify one or more gas cleaning systems of commercial size capable of 1) meeting EPA’s new source performance standards for coal burning power plants and 2) operating reliably under the severe environmental conditions specified. The principal gas cleaning systems that have been investigated for this service include: ceramic cleanable cloth filters, granular bed filters, rigid, porous ceramic structures, and electrostatic precipitators. Some of the fly ash collectors have been operated up to pilot scale size under realistic conditions. In spite of several years of intensive effort and many millions of dollars expended, production of a commercial unit has not been realized. A major content of this paper is a review of the accomplishments and failures of each of the fly ash collector concepts and a series of recommendations to guide future R & D efforts.     

Life cycle assessment of fuel selection for power generation in Taiwan

Life cycle assessment (LCA) was applied to performance data from 1997-2002 to evaluate the environmental impacts of the energy input, airborne emission, waterborne emission, and solid waste inventories for Taiwan's electric power plants. Eco-indicator 95 was used to compare the differences among the generation processes and fuel purification. To better understand the environmental trends related to Taiwan's electric power industry, three fuel scenarios were selected for LCA system analysis. Results indicate that there are differences in characteristic environmental impact among the 13 power plants. Scenario simulation provided a basis for minimizing environmental impacts from fuel selection targets. Fuel selection priority should be a gas-fired combined cycle substituted for a coal-fired steam turbine to be more environmentally friendly, particularly in the areas of the greenhouse effect, acidification, winter smog, and solid waste. Furthermore, based purely on economic and environmental criteria, it is recommended that the gas-fired combined cycle be substituted for the oil-fired steam turbine.     

Life Cycle Assessment of Fuel Selection for Power Generation in Taiwan

Abstract

Life cycle assessment (LCA) was applied to performance data from 1997–2002 to evaluate the environmental impacts of the energy input, airborne emission, waterborne emission, and solid waste inventories for Taiwan’s electric power plants. Eco-indicator 95 was used to compare the differences among the generation processes and fuel purification. To better understand the environmental trends related to Taiwan’s electric power industry, three fuel scenarios were selected for LCA system analysis. Results indicate that there are differences in characteristic environmental impact among the 13 power plants. Scenario simulation provided a basis for minimizing environmental impacts from fuel selection targets. Fuel selection priority should be a gas-fired combined cycle substituted for a coal-fired steam turbine to be more environmentally friendly, particularly in the areas of the greenhouse effect, acidification, winter smog, and solid waste. Furthermore, based purely on economic and environmental criteria, it is recommended that the gas-fired combined cycle be substituted for the oil-fired steam turbine.     

How best management practices affect emissions in gas turbine power plants—An important factor to consider when strengthening emission standards

The Beijing Municipal Environmental Protection Bureau (EPB) is considering strengthening the Emission Standard of Air Pollutants for Stationary Gas Turbines, originally published in 2011 (DB11/847–2011), with a focus on reducing nitrogen oxides (NOx) emissions. A feasibility study was conducted to evaluate the current operation of 12 existing combined-cycle gas turbine power plants and the design of two new plants in Beijing and their emission reduction potential, in comparison with a state-of-the-art power plant in California. The study found that best management practices (BMPs) could potentially improve the emission level of the power plants, and should be implemented to minimize emissions under current design characteristics. These BMPs include (1) more frequent tuning of turbine combustors; (2) onsite testing of natural gas characteristics in comparison to turbine manufacturer’s specifics and tuning of turbine to natural gas quality; (3) onsite testing of aqueous ammonia to ensure adequate ammonia concentration in the mixed solution, and the purity of the solution; (4) more careful inspection of the heat recovery steam generator (HRSG), and the selective catalytic reduction (SCR) during operation and maintenance; (5) annual testing of the catalyst coupon on the SCR to ensure catalyst effectiveness; and (6) annual ammonia injection grid (AIG) tuning. The study found that without major modification to the plants, improving the management of the Beijing gas turbine power plants may potentially reduce the current hourly average NOx emission level of 5–10 parts per million (ppm; ranges reflects plant variation) by up to 20%. The exact improvement associated with each BMP for each facility requires more detailed analysis, and requires engagement of turbine, HRSG, and SCR manufacturers. This potential improvement is an important factor to consider when strengthening the emission standard. However, note that with the continuous needs of improving air quality within the area, more expensive control measures, such as retrofitting the turbines or the HRSGs, may be considered.

Implications: This study analyzed the potential emission reductions associated with implementing the best management practices (BMPs) on the combined cycle and cogeneration power plants in Beijing. It determined that implementing the BMPs could potentially achieve up to 580 metric tonnes, or 0.6%, reductions of all NOx emissions in Beijing. Many other cities in China and Asia battling air quality issues may find the information useful in order to evaluate the emission reduction potential of their own gas turbine power plants.     

Impact of NOx Emissions Released from a Gas Turbine-Based Power Plant on the Ambient Air Quality

The number of gas turbine- (GT-) based power plants is rapidly increasing to meet the world’s power demands. Until a few years ago, fossil fuel, and specifically fuel oil, was considered the major energy source for gas turbine operation. Due to the high amount of pollution that fuel oil generates, natural gas has become a popular source of energy due to its lower emissions compared to fuel oil. As a result, many GTs have switched to natural gas as an alternative to fuel oil. However, pollutants expelled from GT-based power plants operating on natural gas impact surrounding air quality. The objective of this study was to examine the dispersion of nitrogen oxides (NO_x) emitted from a GT-based power plant located in the Sultanate of Oman. Supported by CALPUFF dispersion modeling software, six scenarios were investigated in this study. The first four scenarios considered a case where the GT-based power plant was operating on natural gas during winter and summer and for open and combined cycle modes. The remaining two scenarios considered, for both open and combined cycle modes, the case where the GT-based power plant was operating on fuel oil. Whether run by natural gas or fuel oil, CALPUFF simulation results for both seasons showed that NO_x concentrations were higher when GTs were used in the combined cycle mode. The concentrations were still lower than the allowable concentrations set by the United States Environmental Protection Agency (U.S. EPA) standards. In contrast, for the case where the power plant operated on fuel oil, the NO_x one-hour average simulated results exceeded the allowable limits only when the combined cycle mode was activated.     

The role of coal technologies to support responsible economic growth

The Asian Pacific region is home to the fastest-growing economies in the world. These economies are expected to double gross domestic product (GDP) in the next decade, and coal will play a major role as the primary energy source for electric power. The tremendous projected financial burden associated with the installation of new, coal-fired electric power facilities to fuel this unprecedented economic growth has focused efforts to identify existing and new sources of financing for major thermal power projects that are efficient and environmentally responsible. The economics are trying to accelerate economic development and promote the leveraging of in-country resources to meet their electric power objectives. With the growth in power production will come more greenhouse gas emissions and negative environmental impacts. The means to reducing these impacts is clean coal technology, which is becoming more and more accepted for debt financing. Competition for debt financing is becoming tighter worldwide, with increased use of project financing. Representatives of the coal technology and equipment industries believe that the availability of non-recourse financing is an impediment to greater penetration of clean coal technology into electric power markets in Asian Pacific economies. Better use of existing infrastructure project financing instruments and management of risk in Asian markets are critical to the development and acceptance of clean coal technology to meet greenhouse gas abatement and economic goals.     

Investigation of Nitrogen-Bearing Species in Catalytic Steam Gasification of Poultry Litter

Abstract

The production of broiler chickens has become one of the largest sectors in U.S. agriculture, and the growing demand for poultry has led to an annual production growth rate of 5%. With increased demand for poultry, litter management has become a major challenge in the agriculture industry. Although the catalytic steam gasification has been accepted as a possible and feasible method for litter management, concern has been expressed about the presence of nitrogen and phosphorus containing species in the fuel gas and/or in the final solid residue. The possible release of phosphorus as phosphine gas in the fuel gas can have an adverse impact on the environment. Similarly, possible release of ammonia from the nitrogen containing species is also not acceptable. Hence, under partial U.S. Department of Agriculture support, a study was conducted to examine the fate and the environmental impact of the nitrogen- and phosphorus-containing species released during catalytic steam gasification of poultry litter. From various preliminary tests, it was concluded that most (～100%) of the phosphorus would remain in the residue, and some (20–70%) of the nitrogen would end up as ammonia in the fuel gas. The effects of temperature, catalyst loading, and type of catalyst on ammonia liberation were studied in a muffled furnace setup at atmospheric pressure. The fraction of nitrogen released as ammonia was found to decrease with an increase in temperature during pyrolysis and steam gasification. It also decreased with an increase in catalyst loading.     

Investigation of nitrogen-bearing species in catalytic steam gasification of poultry litter

The production of broiler chickens has become one of the largest sectors in U.S. agriculture, and the growing demand for poultry has led to an annual production growth rate of 5%. With increased demand for poultry, litter management has become a major challenge in the agriculture industry. Although the catalytic steam gasification has been accepted as a possible and feasible method for litter management, concern has been expressed about the presence of nitrogen and phosphorus containing species in the fuel gas and/or in the final solid residue. The possible release of phosphorus as phosphine gas in the fuel gas can have an adverse impact on the environment. Similarly, possible release of ammonia from the nitrogen containing species is also not acceptable. Hence, under partial U.S. Department of Agriculture support, a study was conducted to examine the fate and the environmental impact of the nitrogen- and phosphorus-containing species released during catalytic steam gasification of poultry litter. From various preliminary tests, it was concluded that most (approximately 100%) of the phosphorus would remain in the residue, and some (20-70%) of the nitrogen would end up as ammonia in the fuel gas. The effects of temperature, catalyst loading, and type of catalyst on ammonia liberation were studied in a muffled furnace setup at atmospheric pressure. The fraction of nitrogen released as ammonia was found to decrease with an increase in temperature during pyrolysis and steam gasification. It also decreased with an increase in catalyst loading.     

The fate and behavior of mercury in coal-fired power plants

For the past 22 years in the Netherlands, the behavior of Hg in coal-fired power plants has been studied extensively. Coal from all over the world is fired in Dutch power stations. First, the Hg concentrations in these coals were measured. Second, the fate of the Hg during combustion was established by performing mass balance studies. On average, 43 +/- 30% of the Hg was present in the flue gases downstream of the electrostatic precipitator (ESP; dust collector). In individual cases, this figure can vary between 1 and 100%. Important parameters are the Cl content of the fuel and the flue gas temperature in the ESP. On average, 54 +/- 24% of the gaseous Hg was removed in the wet flue-gas desulfurization (FGD) systems, which are present at all Dutch coal-power stations. In individual cases, this removal can vary between 8% (outlier) and 72%. On average, the fate of Hg entering the power station in the coal was as follows: <1% in the bottom ash, 49% in the pulverized fuel ash (ash collected in the ESP), 16.6% in the FGD gypsum, 9% in the sludge of the wastewater treatment plant, 0.04% in the effluent of the wastewater treatment plant, 0.07% in fly dust (leaving the stack), and 25% as gaseous Hg in the flue gases and emitted into the air. The distribution of Hg over the streams leaving the FGD depends strongly on the installation. On average, 75% of the Hg was removed, and the final concentration of Hg in the emitted flue gases of the Dutch power stations was only -3 microg/m3(STP) at 6% O2. During co-combustion with biomass, the removal of Hg was similar to that during 100% coal firing. Speciation of Hg is a very important factor. An oxidized form (HgCl2) favors a high degree of removal. The conversion from Hg0 to HgCl2 is positively correlated with the Cl content of the fuel. A catalytic DENOX (SCR) favors the formation of oxidized Hg, and, in combination with a wet FGD, the total removal can be as high as 90%.     

An assessment of air emissions from liquefied natural gas ships using different power systems and different fuels

The shipping industry has been an unrecognized source of criteria pollutants: nitrogen oxides (NOx), volatile organic compounds, coarse particulate matter (PM10), fine particulate matter (PM2.5), sulfur dioxide (SO2), and carbon monoxide (CO). Liquefied natural gas (LNG) has traditionally been transported via steam turbine (ST) ships. Recently, LNG shippers have begun using dual-fuel diesel engines (DFDEs) to propel and offload their cargoes. Both the conventional ST boilers and DFDE are capable of burning a range of fuels, from heavy fuel oil to boil-off-gas (BOG) from the LNG load. In this paper a method for estimating the emissions from ST boilers and DFDEs during LNG offloading operations at berth is presented, along with typical emissions from LNG ships during offloading operations under different scenarios ranging from worst-case fuel oil combustion to the use of shore power. The impact on air quality in nonattainment areas where LNG ships call is discussed. Current and future air pollution control regulations for ocean-going vessels (OGVs) such as LNG ships are also discussed. The objective of this study was to estimate and compare emissions of criteria pollutants from conventional ST and DFDE ships using different fuels. The results of this study suggest that newer DFDE ships have lower SO2 and PM2.5/PM10 emissions, conventional ST ships have lower NOx, volatile organic compound, and CO emissions; and DFDE ships utilizing shore power at berth produce no localized emissions because they draw their required power from the local electric grid.     

Determining Impaction Efficiencies of Mist Collection Equipment

High temperature sulfur removal can be achieved with calcium-based sor-bents (e.g. dolomite) in fluidized-bed çoal gasification systems now being developed for power generation. The use of dolomite offers the opportunity to meet environmental emission standards, to minimize energy losses, and to reduce electrical energy costs.

In addition to removing sulfur from the low-Btu gas, the complete sulfur removal system must be integrated with the total power plant and environment to assure compatibility. Critical requirements for achieving commercial system include establishing criteria for ‘acceptable’ sorbents, establishing integrated sulfur removal/gasification process design parameters, predicting trace element release, predicting sorbent attrition, developing an economic regeneration and/or once through process option, developing a spent sorbent processing system, and establishing safe and reliable disposition options for spent sorbent. Design and operating parameters are being developed and potential process limitations are identified.     

Recording the Response of Plants to Various Air Pollutants

A discussion of the methods used to determine the most economic design of chimney for a new thermal power station or large industrial plant is presented, with the objective that ground level concentration of pollutants will be kept at a minimum. Attention is paid to the geography and climatology of the site, with special reference to the frequency and height of inversions and the prevailing wind direction and speed.

A method is illustrated in using a large thermal power station as an example. The maximum sulfur dioxide concentrations at ground level are computed for several chimney heights and gas exit velocities. The values of these sulfur dioxide concentrations, the capital cost of the chimney, the pumping costs, and the gas pressures within the chimney are considered in selecting a suitable chimney height and a gas exit velocity which will meet most economically the stated objective.

The paper deals primarily with chimneys for industrial or power boiler plant of maximum continuous rating greater than 450 million Btu/hr (about 450,000 lbs of steam/hr), or to chimneys serving furnaces burning fuel at a maximum rate greater than 50,000 lbs/hr of coal, or 80,000 lbs/hr of oil. For chimneys serving plant with smaller heat inputs, chimney selection by reference to Clean Air Act 1956, Memorandum on Chimney Heights is suggested.     

The Fate and Behavior of Mercury in Coal-Fired Power Plants

Abstract

For the past 22 years in the Netherlands, the behavior of Hg in coal-fired power plants has been studied extensively. Coal from all over the world is fired in Dutch power stations. First, the Hg concentrations in these coals were measured. Second, the fate of the Hg during combustion was established by performing mass balance studies. On average, 43 ± 30% of the Hg was present in the flue gases downstream of the electrostatic precipitator (ESP; dust collector). In individual cases, this figure can vary between 1 and 100%. Important parameters are the Cl content of the fuel and the flue gas temperature in the ESP. On average, 54 ± 24% of the gaseous Hg was removed in the wet flue-gas desulfurization (FGD) systems, which are present at all Dutch coal-power stations. In individual cases, this removal can vary between 8% (outlier) and 72%.

On average, the fate of Hg entering the power station in the coal was as follows: <1% in the bottom ash, 49% in the pulverized fuel ash (ash collected in the ESP), 16.6% in the FGD gypsum, 9% in the sludge of the wastewater treatment plant, 0.04% in the effluent of the wastewater treatment plant, 0.07% in fly dust (leaving the stack), and 25% as gaseous Hg in the flue gases and emitted into the air. The distribution of Hg over the streams leaving the FGD depends strongly on the installation. On average, 75% of the Hg was removed, and the final concentration of Hg in the emitted flue gases of the Dutch power stations was only ~3 μg/m_STP ³ at 6% O₂. During co-combustion with biomass, the removal of Hg was similar to that during 100% coal firing.

Speciation of Hg is a very important factor. An oxidized form (HgCl₂) favors a high degree of removal. The conversion from Hg⁰ to HgCl₂ is positively correlated with the Cl content of the fuel. A catalytic DENOX (SCR) favors the formation of oxidized Hg, and, in combination with a wet FGD, the total removal can be as high as 90%.     

Assessing Sorbents for Mercury Control in Coal-Combustion Flue Gas

Abstract

Sorbent injection for Hg control is one of the most promising technologies for reducing Hg emissions from power-generation facilities, particularly units that do not require wet scrubbers for SO₂ control. Since 1992, EPRI has been assessing the performance of Hg sorbents in pilot-scale systems installed at full-scale facilities. The initial tests were conducted on a 5000-acfm (142-m³/min) pilot baghouse. Screening potential sorbents at this scale required substantial resources for installation and operation and did not provide an opportunity to characterize sor-bents over a wide temperature range.

Data collected in the laboratory and in field tests indicate that sorbents are affected by flue gas composition and temperature. Tests carried out in actual flue gas at a number of power plants also have shown that sorbent performance can be site-specific. In addition, data collected at a field site often are different from data collected in the laboratory, with simulated flue gas mixed to match the major components in the site’s gas. To effectively estimate the costs of Hg sorbent systems at different plants, a measure of sorbent performance in the respective flue gases must be obtained. However, injection testing at multiple facilities with large pilot systems is not practical.

Over the past five years, fixed-bed characterization testing, modeling studies, and bench-scale injection testing have been undertaken to develop a low-cost technique to characterize sorbent performance in actual flue gas and subsequently to project normalized costs for Hg removal prior to full-scale demonstration. This article describes the techniques used and summarizes field-testing results from two plants burning Powder River Basin (PRB) coal for commercial activated carbon and several other sorbent types. Full-scale projections based on the results and data collected on larger-scale systems also are included.     

Gas turbine emissions and environmental impact of efficiency boosting techniques

In this paper, environmental impact of gas turbine power generation equipment is reviewed and emissions sources are discussed. The types of pollutants in simple cycle gas turbine power plants and the associated air quality problems are compiled. Then, airborne pollutants which are generated in the combustion turbines are described and factors affecting emission formation are discussed. Also, the environmental impact of a number of efficiency boosting techniques including inlet air cooling and cogeneration is presented. It is concluded that environmental impact should be taken into account when economics of different efficiency boosting technologies is evaluated. Also, the conflicting issues of emission dependence on temperature need to be addressed in a broader perspective.     

生物质气化过程催化剂应用研究进展

生物质气化技术已在国内外得到广泛的开发和运用,但由于燃气品位较差,焦油较多,限制了生物质气化气的进一步利用。在生物质气化过程中应用催化剂是一种有效的提升燃气质量和催化裂解焦油的方法,近年来已引起了国内外的广泛注意。本文对国内外生物质催化气化及相关研究进展进行了综合评述,分析了催化剂对减少生物质气化焦油的生成和改进燃料气品质的作用结果, 提出了进一步的研究方向。     

Separation and capture of CO2 from large stationary sources and sequestration in geological formations--coalbeds and deep saline aquifers

The topic of global warming as a result of increased atmospheric CO2 concentration is arguably the most important environmental issue that the world faces today. It is a global problem that will need to be solved on a global level. The link between anthropogenic emissions of CO2 with increased atmospheric CO2 levels and, in turn, with increased global temperatures has been well established and accepted by the world. International organizations such as the United Nations Framework Convention on Climate Change (UNFCCC) and the Intergovernmental Panel on Climate Change (IPCC) have been formed to address this issue. Three options are being explored to stabilize atmospheric levels of greenhouse gases (GHGs) and global temperatures without severely and negatively impacting standard of living: (1) increasing energy efficiency, (2) switching to less carbon-intensive sources of energy, and (3) carbon sequestration. To be successful, all three options must be used in concert. The third option is the subject of this review. Specifically, this review will cover the capture and geologic sequestration of CO2 generated from large point sources, namely fossil-fuel-fired power gasification plants. Sequestration of CO2 in geological formations is necessary to meet the President's Global Climate Change Initiative target of an 18% reduction in GHG intensity by 2012. Further, the best strategy to stabilize the atmospheric concentration of CO2 results from a multifaceted approach where sequestration of CO2 into geological formations is combined with increased efficiency in electric power generation and utilization, increased conservation, increased use of lower carbon-intensity fuels, and increased use of nuclear energy and renewables. This review covers the separation and capture of CO2 from both flue gas and fuel gas using wet scrubbing technologies, dry regenerable sorbents, membranes, cryogenics, pressure and temperature swing adsorption, and other advanced concepts. Existing commercial CO2 capture facilities at electric power-generating stations based on the use of monoethanolamine are described, as is the Rectisol process used by Dakota Gasification to separate and capture CO2 from a coal gasifier. Two technologies for storage of the captured CO2 are reviewed--sequestration in deep unmineable coalbeds with concomitant recovery of CH4 and sequestration in deep saline aquifers. Key issues for both of these techniques include estimating the potential storage capacity, the storage integrity, and the physical and chemical processes that are initiated by injecting CO2 underground. Recent studies using computer modeling as well as laboratory and field experimentation are presented here. In addition, several projects have been initiated in which CO2 is injected into a deep coal seam or saline aquifer. The current status of several such projects is discussed. Included is a commercial-scale project in which a million tons of CO2 are injected annually into an aquifer under the North Sea in Norway. The review makes the case that this can all be accomplished safely with off-the-shelf technologies. However, substantial research and development must be performed to reduce the cost, decrease the risks, and increase the safety of sequestration technologies. This review also includes discussion of possible problems related to deep injection of CO2. There are safety concerns that need to be addressed because of the possibilities of leakage to the surface and induced seismic activity. These issues are presented along with a case study of a similar incident in the past. It is clear that monitoring and verification of storage will be a crucial part of all geological sequestration practices so that such problems may be avoided. Available techniques include direct measurement of CO2 and CH4 surface soil fluxes, the use of chemical tracers, and underground 4-D seismic monitoring. Ten new hypotheses were formulated to describe what happens when CO2 is pumped into a coal seam. These hypotheses provide significant insight into the fundamental chemical, physical, and thermodynamic phenomena that occur during coal seam sequestration of CO2.     

Air Pollution Assessments Of New Fossil Energy Technologies

This paper presents an overview on air pollution assessments of new fossil energy technologies for baseload electric generating plants. The discussion is oriented towards those who must understand the broad issues affecting the design and performance of such power plants. It is motivated by the potential air pollution problems caused by the near doubling of coal use projected for the next 15 years.

The paper first reviews the applicable emissions performance standards for these plants, as well as predictions of likely future standards needed to protect the environment. The conclusion is reached that significantly tighter emissions standards will apply in the future.

Next, the cost, emissions performance, and development status of the three major technology groups for coal fired baseload plants are reviewed. It is observed that while all of the technologies can meet the current standards, only the Baseline plant with Advanced Control Technology can meet future standards, without unreasonable increases in electrical generation costs. Furthermore, since Advanced Direct Combustion Technologies and Fuel Conversion Technologies are in very early stages of development, only the Baseline plant with Advanced Control Technology will be available to the utilities in the near term. This is because it will be evolved from the current commercial Baseline Technology.

Hence, it is concluded that the utilities will use mainly the Baseline coal fired plant with Advanced Control Technology to protect the environment for the next 15-20 years.     

A new method to assess mercury emissions: a study of three coal-fired electric-generating power station configurations

U.S. Environmental Protection Agency (EPA) Method 7473 for the analysis of mercury (Hg) by thermal decomposition, amalgamation, and atomic absorption spectroscopy has proved successful for use in Hg assessment at coal-fired power stations. In an analysis time of approximately 5 min per sample, this instrumental methodology can directly analyze total Hg--with no discrete sample preparation--in the solid matrices associated with a coal-fired power plant, including coal, fly ash, bottom ash, and flue gas desulfurization (FGD) material. This analysis technique was used to investigate Hg capture by coal combustion byproducts (CCBs) in three different coal-fired power plant configurations. Hg capture and associated emissions were estimated by partial mass balance. The station equipped with an FGD system demonstrated 68% capture on FGD material and an emissions estimate of 18% (11 kg/yr) of total Hg input. The power plant equipped with low oxides of nitrogen burners and an electrostatic precipitator (ESP) retained 43% on the fly ash and emitted 57% (51 kg/yr). The station equipped with conventional burners and an ESP retained less than 1% on the fly ash, emitting an estimated 99% (88 kg/yr) of Hg. Estimated Hg emissions demonstrate good agreement with EPA data for the power stations investigated.