Eliminating Reheat from Existing FGD Systems

The Clean Air Act Amendments of the early 1970_s required coal burning utilities to reduce their emissions of sulfur dioxide. Lime or limestone based wet systems were employed for flue gas desulfurization (FGD). These systems reduced flue gas temperatures to below acid dew point conditions. Concerned about the prospect of ductwork exposed to a saturated, acid-rich environment, most utilities turned to stack gas reheat (SGR) to increase flue gas temperatures. By 1980, 82 percent of all FGD facilities employed SGR. Today there are about 130 FGD systems of which 101 employ some form of stack gas reheat.     

Flue Gas Desulfurization: The State of the Art

ABSTRACT

Coal-fired electricity-generating plants may use SO₂ scrubbers to meet the requirements of Phase II of the Acid Rain SO₂ Reduction Program. Additionally, the use of scrubbers can result in reduction of Hg and other emissions from combustion sources. It is timely, therefore, to examine the current status of SO₂ scrubbing technologies. This paper presents a comprehensive review of the state of the art in flue gas desulfurization (FGD) technologies for coal-fired boilers.

Data on worldwide FGD applications reveal that wet FGD technologies, and specifically wet limestone FGD, have been predominantly selected over other FGD technologies. However, lime spray drying (LSD) is being used at the majority of the plants employing dry FGD technologies. Additional review of the U.S. FGD technology applications that began operation in 1991 through 1995 reveals that FGD processes of choice recently in the United States have been wet limestone FGD, magnesium-enhanced lime (MEL), and LSD. Further, of the wet limestone processes, limestone forced oxidation (LSFO) has been used most often in recent applications.

The SO₂ removal performance of scrubbers has been reviewed. Data reflect that most wet limestone and LSD installations appear to be capable of ~90% SO₂ removal. Advanced, state-of-the-art wet scrubbers can provide SO₂ removal in excess of 95%.

Costs associated with state-of-the-art applications of LSFO, MEL, and LSD technologies have been analyzed with appropriate cost models. Analyses indicate that the capital cost of an LSD system is lower than those of same capacity LSFO and MEL systems, reflective of the relatively less complex hardware used in LSD. Analyses also reflect that, based on total annualized cost and SO₂ removal requirements: (1) plants up to ~250 MW_e in size and firing low- to medium-sulfur coals (i.e., coals with a sulfur content of 2% or lower) may use LSD; and (2) plants larger than 250 MW_e and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

Asbestos: Rationale Behind A Proposed Air Quality Standard

A computerized simulation model has been developed to compute energy requirements of a limestone slurry flue gas desulfurization (FGD) system as a function of FGD system design parameters, power plant characteristics, coal properties, and sulfur dioxide emission regulation. Results are illustrated for a "base case" plant of 500 MW, burning 3.5% sulfur coal, meeting the federal new source performance standard of 1.2 lb SO₂/10⁶ Btu. The flue gas is cleaned by an electrostatic precipitator followed by a limestone FGD system with a TCA scrubbing vessel and an optimized in-line steam reheater. The total FGD system energy requirement for this case was found to be 3.4% of the total energy input to the boiler. Sensitivity analyses were then performed in which the nominal values of ten system parameters were individually varied. This caused the total FGD system energy requirement to vary between 2.5 % and 6.1 % of the gross plant output for the range of parameters tested. The most sensitive parameters were found to be scrubbing slurry pH, which affects pumping requirements, and stack gas exit temperature, which affects reheat requirements. In all cases, FGD energy requirements were minimized when the SO₂ emission standard was met by partially bypassing the scrubber. In light of the recent Clean Air Act Amendments this option may not be feasible in the future.     

Resource Recovery from Flue Gas Desulfurization Systems

The cost effective benefits of yielding a flue gas desulfurization (FGD) sludge predominantly composed of CaSO₄·2H₂O, have been previously established. The recovery of this material as FGD by-product gypsum has been demonstrated abroad. Recently U.S. wallboard manufacturers have recognized the viability of this recovery practice. Such techno-economic decision making variables as a) by-product specification, b) transportation costs, and c) location of suitable FGD systems enable the recognition of FGD by-product recovery. Recent investigations of resultant solids content and chloride washing reflect the technical possibility of delivering a suitable product. Commercial and economic factors favor recovery based upon rising disposal and transportation costs. Existing and near term proposed systems surface the technical and commercial problems faced by utilities considering recovery.

Generation of an oxidized FGD sludge consisting of 90⁺% CaSO₄·2H₂O and dewatered to 80⁺% solids is technically achievable by air sparging within the FGD system. Although the product is suitable for land disposal, electric power utilities should consider and evaluate by-product recovery. U.S. wallboard manufacturers have established technical criteria for FGD by-product gypsum. Percent CaSO₄·2H₂O, final solids content, particle size, and chloride content are primarily technical parameters. Technology exists within the FGD industry to satisfy these criteria and results are discussed.

Economic factors comparing mining costs, transportation costs, and disposal costs are developed for specific utility projects. Such comparison established generalized financial criteria for a given utility to develop the economic reasonableness of considering FGD byproduct recovery.

End product user perspectives are presented providing electric utilities with a realistic appreciation for by-product recovery potential. Location of existing wallboard plants highlight potential recovery regions. Quality control problems are discussed in terms of generating a by-product rather than a disposable material.     

Measurements of Rural Sulfur Dioxide and Particle Sulfate: Analysis of CASTNet Data, 1987 through 1996

ABSTRACT

The Clean Air Status and Trends Network (CASTNet) was implemented by the U.S. Environmental Protection Agency (EPA) in 1991 in response to Title IX of the Clean Air Amendments of 1990, which mandated the deployment of a national ambient air monitoring network to track progress of the implementation of emission reduction programs in terms of deposition, air quality, and changes to affected ecosystems. CASTNet evolved from the National Dry Deposition Network (NDDN). CASTNet currently consists of 45 sites in the eastern United States and 28 sites in the West. Each site measures sulfur dioxide (SO₂), nitric acid (HNO₃), particle sulfate (SO₄ ⁼), particle nitrate (NO₃ ^- ), and ozone. Nineteen sites collect precipitation samples. NDDN/CASTNet uses a uniform set of site-selection criteria which provides the data user with consistent measures to compare each site. These criteria also ensure that, to the extent possible, CASTNet sites are located away from local emission sources.

This paper presents an analysis of SO₂ and SO₄ ⁼ concentration data collected from 1987 through 1996 at rural NDDN/CASTNet sites. Annual and seasonal variability is examined. Gradients of SO₂ and SO₄ ⁼ are discussed. The variability of the atmospheric mix of SO₂ and SO₄ ⁼ is explored spatially and seasonally. Data from CASTNet are also compared to SO₂ and SO₄ ⁼ data from concurrent monitoring studies in rural areas.     

Status and Problems of Regenerable Flue Gas Desulfurization Processes

Fourteen sulfur and/or sulfuric acid producing regenerate FGD processes were discussed at the 1974 FGD Symposium in Atlanta. During the period elapsed since then, considerable status change has occurred on many of these regenerable processes. Other regenerable processes which were not as well known during 1974 have surfaced in 1975. The problems of obtaining reducing gases (hydrogen sulfide, carbon monoxide, and hydrogen) for the reduction of sulfur dioxide product streams to elemental sulfur have become severe due to shortages of natural gas or other petroleum based feedstock. A new sulfur producing process which employs CO and H₂ directly (rather than the H₂S required for liquid and vapor base Claus reactions) is gaining attention. This paper discusses briefly: (1) the announced status of the many regenerable FGD processes, (2) the problem of reductant gas supply, and (3) the effect on FGD processes of using coal based reducing gas instead of reformed natural gas.     

Sulfur Dioxide Emissions and Market Effects under the Clean Air Act Acid Rain Program

ABSTRACT

The Clean Air Act Amendments of 1990 (CAAA90) established a national program to control sulfur dioxide (SO₂) emissions from electricity generation. CAAA90's market-based approach includes trading and banking of Soumissions allowances. We analyzed data describing electric utility SO₂ emissions in 1995, the first year of the program's Phase I, and market effects over the 1990-1995 period. Fuel switching and flue-gas desulfurization were the dominant means used in 1995 by targeted generators to reduce emissions to 51% of 1990 levels. Flue-gas desulfur-ization costs, emissions allowance prices, low-sulfur coal prices, and average sulfur contents of coals shipped to electric utilities declined over the 1990-1995 period. Projections indicate that 13-15 million allowances will have been banked during the program's Phase I, which ends in 1999, a quantity expected to last through the first decade of the program's stricter Phase II controls. In 1995, both allowance prices and SO₂ emissions were below pre-CAAA90 expectations. The reduction of SO₂ emissions beyond pre-CAAA90 expectations, combined with lower-than-expected allowance prices and declining compliance costs, can be viewed as a success for market-based environmental controls.     

Simplified Models of U.S. Acid Rain Control Costs

Simplified algorithms are presented for estimating the cost of controlling sulfur dioxide (SO₂) emissions from existing coal-fired power plants on a state-by-state basis. Results are obtained using the detailed Utility Control Strategy Model (UCSM) to calculate the Impacts of emission reductions ranging from approximately 30 percent to 90 percent of projected 1995 emissions for 18 different scenarios and 36 states. Scenarios include the use of two dry SO₂ removal technologies (lime spray dryers and LIMB) as potential options for power plant retrofit, in addition to currently available emission control options including coal switching, coal cleaning and wet flue gas desulfurization (FGD). Technical assumptions relating to FGD system performance and the upgrading of existing cold-side electrostatic precipitators (ESP) for reduced sulfur levels are also analyzed, along with the effects of interest rates, coal prices, coal choice restrictions, plant lifetime, and plant operating levels. Results are summarized in the form of a 3-term polynomial equation for each state, giving total annualized SO₂ control cost as a function of the total SO₂ emissions reduction for each scenario. Excellent statistical fits to UCSM results are obtained for these generalized equations.     

Shock Wave Cleaning of Air Filters

The trends in and relationships between ambient air concentrations of sulfur dioxide and sulfate aerosols at 48 urban sites and 27 nonurban sites throughout the U.S. between 1963 and 1972 have been analyzed. The substantial decreases in ambient SO₂ concentrations measured at urban sites in the eastern and midwestern U.S. are consistent with the corresponding reductions in local SO₂ emissions, but these decreases have been accompanied by only modest decreases in ambient sulfate concentrations. Large differences in the amounts of SO₂ emitted within individual air quality control regions are associated with much smaller differences in the corresponding ambient sulfate concentrations. Substantial changes in the patterns of SO₂ emissions between air quality regions result in essentially no differences between ambient sulfate concentrations in those air quality regions. Comparisons of several air quality regions in the eastern and western U.S. with similar SO₂ emission levels and patterns of emissions clearly demonstrates the higher ambient sulfate concentration levels in eastern air quality control regions. Relationships between SO₂, sulfates, and vanadium concentrations at eastern nonurban U.S. sites cannot be explained by local emission sources. These various observed results can be best explained by long distance sulfur oxide transport with chemical conversion of SO₂ to sulfates occurring over ranges of hundreds of kilometers. This conclusion has been suggested earlier and the present analysis strongly supports previous discussions. An impact of long range transport of sulfates is to emphasize the need for Consistent strategies for reduction of sulfur oxides throughout large geographical regions. Additions of large capacities involving elevated sources in mid-continental or western regions could result in significant increases in sulfate concentrations well downwind of such sources. Some of the types of research activities required to quantitate crucial experimental parameters are discussed.     

Assessment of Dry Sorbent Emission Control Technologies Part I. Fundamental Processes

The utility and industrial sectors continue to come under pressure from both national and local regulatory groups to reduce sulfur dioxide emissions. With a trend in the utility industry for life extension, retrofit technologies are likely to play an important role in any SO₂ emission reduction strategy. Potential retrofit technologies include, singly and in combination: coal switching or cleaning, wet or dry FGD, conversion to fluidized bed, and dry sorbent injection. The diversity within the utility industry in terms of unit size, unit age, fuel use, financial base, and geographic location dictates the need for a variety of technologies to address SO₂ emission control. Dry injection processes involving the injection of dry powders into either the furnace or post-furnace region offer the potential for low capital cost retrofitable technologies. However, compared to wet FGD processes, the dry calcium based processes will likely have lower SO₂ removal efficiencies and may pose more plant-wide integration issues that need to be addressed from both an applications and R&D perspective.

This paper provides a critical assessment of dry injection technologies, in two parts. Part 1 focuses on sorbent processes and science. An assessment of the different dry sorbent processes and the effect of process parameters is provided. Emphasis is placed on process limitations and potential avenues to enhance SO₂ removal. Part 2 will deal with applications of the technology, addressing cost, scale-up, and integration issues.

Much of the data included in this paper was presented at the 1986 Joint Symposium on Dry SO₂ and Simultaneous SO₂/NO_x Control Technologies, sponsored by the Electric Power Research Institute and the Environmental Protection Agency and held in June 1986. This paper provides both an overview and an evaluation of the technology, based largely on our analysis of the data and interpretations discussed at this symposium.     

Performance/Cost Estimates for Retrofitting Control Technologies

The U.S. EPA’s Air and Energy Engineering Research Laboratory is responsible for assessing control technology performance and costs under the National Acid Precipitation Assessment Program. A major part of this assessment involves developing site-specific estimates of the performance and costs of retrofitting SO₂ and NO_x control technologies for the top 200 SO₂- emitting (1980) coal-fired power plants in the 31-state eastern region. This effort includes detailed evaluation of a small number of plants (30 or less) representing a cross-section of the top 200 population. In cooperation with the states of Ohio and Kentucky (in conjunction with the U.S. EPA’s State Acid Rain Grant Program), efforts were undertaken to visit and conduct detailed evaluation of 12 coal-fired plants—five in Ohio, seven in Kentucky and the Tennessee Valley Authority System. A variety of commercial and advanced SO₂ and NO_x control technologies—including precombustion, combustion (in-furnace), and postcombustion (flue gas cleanup) technologies—were applied to each plant through conceptual designs. Retrofit factors (applied to the capital cost of a new pollution control system), cost “adders” (e.g., movement of existing equipment), and costs were developed for applying the control technologies to the boilers of each plant. Results of these and subsequent efforts will be valuable in evaluations of acid deposition control strategies by federal and state agencies and by electric utilities.     

Environmental Irradiation Test Facility

Results from a detailed analysis of sulfur dioxide (SO₂) reductions achievable through “deep” physical coal cleaning (PCC) at 20 coal-fired power plants in the Ohio-Indiana-Illinois region are presented here. These plants all have capacities larger than 500 MWe, are currently without any flue gas desulfurization (FGD) systems, and burn coal of greater than l%sulfur content (in 1980). Their aggregate emissions of 2.4 million tons of SO₂ per year represents 55% of the SO₂ inventory for these states. The principal coal supplies for each power plant were identified and characterized as to coal seam and county of origin, so that published coal-washability data could be matched to each supplier. The SO₂ reductions that would result from deep cleaning each coal (Level 4) were calculated using an Argonne computer model that assumes a weight recovery of 80%. Percentage reductions in sulfur content ranged from zero to 52%, with a mean value of 29%, and costs ranged from a low of $364/ton SO₂ removed to over $2000/ton SO₂ removed. Because coal suppliers to these power plants employ some voluntary coal cleaning, the anticipated emissions reduction from current levels should be near 20%. Costs then were estimated for FGD systems designed to remove the same amount of SO₂ as was achieved by PCC through the use of partial scrubbing with bypass of the remaining flue gas. On this basis, PCC was more cost-effective than FGD for about 50% of the plants studied and had comparable costs for another 25% of the plants. Possible governmental actions to either encourage or mandate coal cleaning were identified and evaluated     

Technical Description of Parameters Influencing the pH Value of Suspension Absorbent Used in Flue Gas Desulfurization Systems

Abstract

As a result of the large limestone deposits available in Poland, the low cost of reagent acquisition for the large-scale technological use and relatively well-documented processes of flue gas desulfurization (FGD) technologies based on limestone sorbent slurry, wet scrubbing desulfurization is a method of choice in Poland for flue gas treatment in energy production facilities, including power plants and industrial systems. The efficiency of FGD using the above method depends on several technological and kinetic parameters, particularly on the pH value of the sorbent (i.e., ground limestone suspended in water). Consequently, many studies in Poland and abroad address the impact of various parameters on the pH value of the sorbent suspension, such as the average diameter of sorbent particles (related to the limestone pulverization degree), sorbent quality (in terms of pure calcium carbonate [CaCO₃] content of the sorbent material), stoichiometric surfeit of CaCO₃ in relation to sulfur dioxide (SO₂) absorbed from flue gas circulating in the absorption node, time of absorption slurry retention in the absorber tank, chlorine ion concentration in sorbent slurry, and concentration of dissolved metal salts (Na, K, Mg, Fe, Al, and others). This study discusses the results of laboratory-scale tests conducted to establish the effect of the above parameters on the pH value of limestone slurry circulating in the SO₂ absorption node. On the basis of the test results, a correlation equation was postulated to help maintain the desirable pH value at the design phase of the wet FGD process. The postulated equation displays good coincidence between calculated pH values and those obtained using laboratory measurements.     

Sulfur Dioxide and Nitrogen Oxides Emissions from U.S. Pulp and Paper Mills, 1980–2005

Abstract

Comprehensive surveys conducted at 5-yr intervals were used to estimate sulfur dioxide (SO₂) and nitrogen oxides (NO_x) emissions from U.S. pulp and paper mills for 1980, 1985, 1990, 1995, 2000, and 2005. Over the 25-yr period, paper production increased by 50%, whereas total SO₂ emissions declined by 60% to 340,000 short tons (t) and total NO_x emissions decreased approximately 15% to 230,000 t. The downward emission trends resulted from a combination of factors, including reductions in oil and coal use, steadily declining fuel sulfur content, lower pulp and paper production in recent years, increased use of flue gas desulfurization systems on boilers, growing use of combustion modifications and add-on control systems to reduce boiler and gas turbine NO_x emissions, and improvements in kraft recovery furnace operations.     

Assessment of air quality benefits from national air pollution control policies in China. Part I: Background,emission scenarios and evaluation of meteorological predictions

Under the 11th Five Year Plan (FYP, 2006–2010) for national environmental protection by the Chinese government, the overarching goal for sulfur dioxide (SO₂) controls is to achieve a total national emissions level of SO₂ in 2010 10% lower than the level in 2005. A similar nitrogen oxides (NO_x) emissions control plan is currently under development and could be enforced during the 12th FYP (2011–2015). In this study, the U.S. Environmental Protection Agency (U.S.EPA)’s Community Multi-Scale Air Quality (Models-3/CMAQ) modeling system was applied to assess the air quality improvement that would result from the targeted SO₂ and NO_x emission controls in China. Four emission scenarios — the base year 2005, the 2010 Business-As-Usual (BAU) scenario, the 2010 SO₂ control scenario, and the 2010 NO_x control scenario—were constructed and simulated to assess the air quality change from the national control plan. The Fifth-Generation NCAR/Penn State Mesoscale Model (MM5) was applied to generate the meteorological fields for the CMAQ simulations. In this Part I paper, the model performance for the simulated meteorology was evaluated against observations for the base case in terms of temperature, wind speed, wind direction, and precipitation. It is shown that MM5 model gives an overall good performance for these meteorological variables. The generated meteorological fields are acceptable for using in the CMAQ modeling.     

Control of Claus Plant Sulfur Compound Emissions

The body of information of this paper is directed to those individuals charged with selecting a process to control atmospheric sulfur emissions from Claus plants serving refineries, gas processing installations, and chemical plants. The TGT process developed by the French Petroleum Institute (IFP) is an extension of the Claus reaction itself in the liquid phase. Mixed H₂S and SO₂ in tail gas from Claus units is fed to a packed tower in which a solution of proprietary catalyst in a high BP polyglycol circulates countercurrent to the gas flow. The mixed gases react with the catalyst to form a complex, which in turn reacts with more gases to produce elemental sulfur. Reaction temperature keeps the sulfur above its melting point. Product accumulates in the boot of the tower and is drawn off continuously through a seal leg.

The IFP TGT process is simple in design and units have simple construction, characterized by use of low carbon steel and the use of very few pieces of equipment. Of all processes used today to take effluent sulfur values down to 1000 ppm SO₂ after incineration, the IFP TGT process requires the least capital investment and the lowest operating costs. Twenty-six full scale plants are operating or under design or construction: nine each in the U.S. and Japan, five in the U.S.S.R. and Poland, two in western Europe and one in Canada. Capacities of the Claus plants served range from 45 to 800 Lt/d sulfur.     

The Survival of Airborne Serratia marcescens in Urban Concentrations of Sulfur Dioxide

Aerosols of Serratia marcescens ATCC 274 were suspended in a 709L rotating drum at 20 ± 1 °C and high to mid-range relative humidities. At specified times after bacterial aerosolization, sulfur dioxide was added to concentrations of 2.5, or 5 mg/m³. Viable cell decay rate constants, in control aerosols without added sulfur dioxide, increased rapidly from near 100% to 60% RH in the first hour (termed: young aerosol) of suspension, and from a minimum rate constant at 80% in the succeeding four hours (termed: old aerosol).Upon addition of sulfur dioxide to a cloud of S. marcescens, generally, viable cell decay rate constants increased further. One exception was at 80% relative humidity where maximum resistance to SO₂ accelerated death was observed for old aerosols. Cells in young aerosols were particularly sensitive to SO₂ addition at mid-range humidities, while in older aerosols the cells were insensitive to up to 5 mg SO₂/m³ introduced at high RH; but were up to 10 times more sensitive than cells in young aerosols to a given increase (from 2.5 to 5 mg/m³) in SO₂ concentration at mid-range humidities.     

Simultaneous removal of NOx,SO2, and Hg from flue gas in FGD absorber with oxidant injection (NaClO2)– full-scale investigation

ABSTRACT

This article presents the results of an industrial-scale study (on 400 MW_e lignite fired unit) of simultaneous NO_x, SO₂, and Hg^T removal in FGD absorber with oxidant injection (NaClO₂) into flue gas. It was confirmed that the injection of sodium chlorite upstream the FGD (Flue Gas Desulfurization) absorber oxidize NO to NO₂, Hg⁰ to Hg²⁺, and enhancing NO_x and Hg^T removal efficiency from exhaust gas in FGD absorber. Mercury removal efficiency grows with the rise of degree of oxidation NO to NO₂ and was limited by the phenomenon of re-emission. For NO_x removal the most critical parameters is slurry pH and temperature. There was no negative effect on sulfur dioxide removal efficiency caused by oxidant injection in tested FGD absorber. Based on the data provided, NO_x and Hg^T emissions can be reduced by adjusting the FGD absorber operating parameters combined with oxidant injection.     

Natural sulfur dioxide emissions from sulfuric soils

Soils have long been recognised as sulfur dioxide (SO₂) sinks, but we show that they can also be sources of atmospheric SO₂. Using static chambers and micrometeorological techniques, we have measured emissions of SO₂ from coastal lowland soils containing sulfides (mostly pyrite), commonly referred to as acid sulfate soils in Australia. SO₂ evolution seems coupled to evaporation of soil water containing sulfite. The global emissions of S from acid sulfate soils is estimated at about 3 Tg/year, which is of the same order as emissions from terrestrial biogenic sources and biomass burning and is about 3% of known anthropogenic emissions of S.     

Estimating Costs of Flue Gas Desulfurization Systems for Utility Boilers

In September 1973, PEDCo-Environmental Specialists was awarded a study by the U. S. Environmental Protection Agency to evaluate the cost of controlling sulfur dioxide and particulate emissions from selected utility boilers. Since that time, PEDCo has conducted additional studies for the U. S. EPA, state and local control agencies, and private industry on the costs of control technology and the reliability of sulfur dioxide control systems. Current work includes determining the feasibility and environmental impact of converting selected utility boilers to coal-firing to conserve the nation’s gas and oil supplies. This paper presents an overview of the status and costs of flue gas desulfurization (FGD) systems, and the factors relating to the variability in costs. It is based in part upon work performed in developing detailed FGD cost estimating manuals for EPA.