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.     

Development and Pilot Plant Evaluation of Silica- Enhanced Lime Sorbents for Dry Flue Gas Desulfurization

EPA’s efforts to develop low cost, retrofitable flue gas cleaning technology include the development of highly reactive sorbents. Recent work addressing lime enhancement and testing at the bench-scale followed by evaluation of the more promising sorbents in a pilot plant are discussed here.

The conversion of Ca(OH)₂ with SO₂ increased several-fold compared with Ca(OH)₂ alone when Ca(OH)₂ was slurrled with fly ash first and later exposed to SO₂ in a laboratory packed bed reactor. Ca(OH)₂ enhancement increased with the increased fly ash amount. Dlatomaceous earths were very effective reactivity promoters of lime-based sorbents. Differential scanning calorimetry of the promoted sorbents revealed the formation of a new phase (calcium silicate hydrates) after hydration, which may be the basis for the observed Improved SO₂ capture.

Fly ash/lime and diatomaceous earth/lime sorbents were tested in a 100 m³/h pilot facility incorporating a gas humidifier, a sorbent duct injection system, and a baghouse. The inlet SO₂ concentration range was 1000-2500 ppm. With once-through dry sorbent injection into the humidified flue gas [approach to saturation 10–20°C (18–36°F) in the baghouse], the total SO₂ removal ranged from 50 to 90 percent for a stoichiometric ratio of 1 to 2. Recycling the collected solids resulted in a total lime utilization exceeding 80–90 percent. Increased lime utilization was also investigated by the use of additives.     

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.     

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.     

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.     

Development of Federal Air Standards to Reduce Sulfur Dioxide Emissions from New Industrial Boilers

Federal new source performance standards to control air emissions of sulfur dioxide from new industrial boilers were proposed by EPA on June 19, 1986. These standards would require boiler owners to reduce SO₂ emissions by 90 percent and meet an emission limit of 1.2 lb/MM Btu of heat input for coal-fired boilers and 0.8 lb/MM Btu for oil-fired boilers. In developing these standards, several regulatory options were considered, from standards that could be met by firing low sulfur fuels to standards that would necessitate flue gas treatment. The environmental, economic, and cost impacts of each option were analyzed. National impacts were estimated by a computer model that projects the population of new boilers over the 5-year period following proposal, predicts the compliance strategy that will be used to comply with the particular option (always assuming that the lowest cost method of compliance will be selected), and estimates the resulting emission reductions and costs. Impacts on specific industries and on model boilers were also analyzed. This paper focuses on these analyses and their results. The Agency's conclusions from these analyses, which led to the decision to establish percent reduction standards, are provided, and the proposed SO₂ standards are summarized. The proposed standards also include an emission limit for particulate matter from oil-fired boilers (0.1 lb/MM Btu). However, this article focuses only on the SO₂ standards.     

Analysis of Industrial Boiler Solid Waste Impacts

This paper presents an examination of industrial coal-fired boiler waste products. Presently the atmospheric emissions from all new boilers larger than 250 × 10⁶ Btu/hr are controlled by existing New Source Performance Standards, and boilers smaller than 250 × 10⁶ Btu/hr are controlled to levels required by the regulations of the particular state in which the facility is located. The 1977 Clean Air Act Amendments, however, specify categories of sources for which EPA must develop revised New Source Performance Standards. Industrial coal-fired boilers are included as one of these categories, and a relevant issue concerns the potential amount of solid waste generated as a result of tightened emission standards that require flue gas desulfurization. This paper examines the air quality and solid waste impacts of moderate and stringent emission controls for particulate and SO₂ emissions from industrial coal-fired boilers.

Comparisons are presented of physical and chemical characterizations of the emissions and solid wastes produced when boilers are equipped with particulate and SO₂ control equipment. The SO₂ systems examined are lime spray drying, lime/limestone, double alkali, sodium throwaway, physically cleaned coal, and fluidized-bed combustion. The solid waste disposal alternatives and the disposal costs are discussed. The most common disposal methods used are landfill for dry wastes and impoundment for sludges, with special wastewater treatment requirements for the sodium throwaway aqueous wastes.     

Simultaneous Control of Hg0, SO2, and NOx by Novel Oxidized Calcium-Based Sorbents

Abstract

Efforts to develop multipollutant control strategies have demonstrated that adding certain oxidants to different classes of Ca-based sorbents leads to a significant improvement in elemental Hg vapor (Hg⁰), SO₂, and NO_x removal from simulated flue gases. In the study presented here, two classes of Ca-based sorbents (hydrated limes and silicate compounds) were investigated. A number of oxidizing additives at different concentrations were used in the Ca-based sorbent production process. The Hg⁰, SO₂, and NO_x capture capacities of these oxidant-enriched sorbents were evaluated and compared to those of a commercially available activated carbon in bench-scale, fixed-bed, and fluid-bed systems. Calcium-based sorbents prepared with two oxidants, designated C and M, exhibited Hg⁰ sorp-tion capacities (~100 μg/g) comparable to that of the activated carbon; they showed far superior SO₂ and NO_x sorption capacities. Preliminary cost estimates for the process utilizing these novel sorbents indicate potential for substantial lowering of control costs, as compared with other processes currently used or considered for control of Hg⁰, SO₂, and NO_x emissions from coal-fired boilers. The implications of these findings toward development of multipollutant control technologies and planned pilot and field evaluations of more promising multipollutant sorbents are summarily discussed.     

Opacity Reduction Using Dry Hydrated Lime Injection

Abstract

This investigation studied the effects of injecting dry hydrated lime into flue gas to reduce sulfur trioxide, (SO₃) concentrations and consequently stack opacity at the University of Missouri-Columbia power plant. The opacity was due to sulf uric acid mist forming at the stack from high SO₃ concentrations. As a result of light scattering by the mist, a visible plume leaves the stack. Therefore, reducing high concentrations of SO₃ reduces the sulfuric acid mist and consequently the opacity. To reduce SO₃ concentrations, dry hydrated lime is periodically injected into the flue gas upstream of a baghouse and downstream of an induced draft fan. The hydrated lime is transported downstream by the flue gas and deposited on the filter bags in the baghouse forming a filter cake. The reaction between the SO₃ and the hydrated lime takes place on the filter bags. The hydrated lime injection system has resulted in at least 95% reduction in the SO₃ concentration and has reduced the opacity to acceptable limits. Low capital equipment requirements, low operating cost, and increased bag life make the system very attractive to industries with similar problems.     

Economics of an integrated approach to control SO2, NOX,HCl, and particulate emissions from power plants

An integrated approach for the simultaneous reduction of major combustion-generated pollutants from power plants is presented along with a simplified economic analysis. With this technology, the synergistic effects of high-temperature sorbent/coal or sorbent/natural gas injection and high-temperature flue gas filtration are exploited. Calcium-based (or Na-based, etc.) sorbents are sprayed in the post-flame zone of a furnace, where they react with S- and Cl-containing gases to form stable salts of Ca (or Na, etc.). The partially reacted sorbent is then collected in a high-temperature ceramic filter, which is placed downstream of the sorbent injection point, where it further reacts for a prolonged period of time. With this technique, both the likelihood of contact and the length of time of contact between the solid sorbent particles and the gaseous pollutants increase, because reaction takes place both in the furnace upstream of the filter and inside the filter itself. Hence, the sorbent utilization increases significantly. Several pollutants, such as SO2, H2S, HCl, and particulate (soot, ash, and tar), may be partially removed from the effluent. The organic content of the sorbents (or blends) also pyrolyzes and reduces NOx. Unburned carbon in the ash may be completely oxidized in the filter. The filter is cleaned periodically with aerodynamic regeneration (back pulsing) without interrupting furnace operation. The effectiveness of this technique has been shown in laboratory-scale experiments using either rather costly carboxylic salts of Ca or low- to moderate-cost blends of limestone, lime, or sodium bicarbonate with coal fines. Injection occurred in the furnace at 1150 degrees C, while the filter was maintained at 600 degrees C. Results showed that 65 or 40% SO2 removal was obtained with calcium formate or a limestone/coal blend, respectively, at an entering calcium-to-sulfur molar ratio of 2. A sodium bicarbonate/coal blend resulted in 78% SO2 removal at a sodium-to-sulfur molar ratio of 2. HCl removal efficiencies have been shown to be higher than those for SO2. NOx reductions of 40% have been observed with a fuel (coal)-to-air equivalence ratio, phi, around 2. The filter has been shown to be 97-99% efficient in removing PM2.5 particulates. Calculations herein show that this integrated sorbent/filter method is cost-effective, in comparison with current technologies, on both capital cost ($/kW) and levelized cost ($/ton pollutant removed) bases, if a limestone/coal mixture is used as the sorbent for fossil fuel plants. Capital costs for the filter/sorbent combination are estimated to be in the range of $61-$105/kW for a new plant. Because current technologies are designed for removing one pollutant at a time, both their cost and space requirements are higher than those of this integrated technique. At the minimum projected removal efficiencies for HCl/SO2/NOx of about 40%, the levelized costs are projected to be $203-$261/ton of combined pollutant SO2/HCl/NOx and particulates removed from coal-fired power plants.     

Predicting the Performance of Particulate Control Equipment

A new probabilistic modeling environment is described which allows the explicit and quantitative representation of the uncertainties inherent in new environmental control processes for SO₂ and NO_x removal. Stochastic analyses provide additional insights into the uncertainties in process performance and cost not possible with conventional deterministic or sensitivity analysis. Applications of the probabilistic modeling framework are illustrated via an analysis of the performance and cost of the fluidized bed copper oxide process, an advanced technology for the control of SO₂ and NO_x emissions from coal-fired power plants. An engineering model of a conceptual commercial-scale system provides the basis for the analysis. The model also captures interactions between the power plant, the SO₂/NO_x removal process, and other components of the emission control system. Results of the analysis address payoffs from process design improvements; the dependence of system cost on process design conditions and the availability of byproduct markets; and the likelihood that the advanced process will yield cost savings relative to conventional technology. The implications of case study results for research planning and comparisons with alternative systems also are briefly discussed.     

ESP Performance with Atmospheric Fluidized-Bed Combustion

Electric utilities considering atmospheric fluidized-bed combustion (AFBC) as an economic way to reduce SO₂ and NO_x emissions at coal-fired power plants must evaluate the impact AFBC will have on existing or planned plant systems and components. Because fly ash in AFBC units can have characteristics significantly different from that generated in pulverized-coal-fired boilers, a particular concern in this regard is the performance of the plant's particulate control equipment.     

Effects of Sorbent Injection on Participate Properties: Part I. Low-Temperature Sorbent Injection

Abstract

This article is the first of a two-part series dealing with the effects of sorbent injection processes on particulate properties. Part I reviews the effects on particulate properties of low-temperature sorbent injection processes (those processes that treat flue gas at temperatures near 300 °F). Part II reviews the effects on particulate properties of high-temperature sorbent injection processes (those processes that involve sorbent injection into the combustion or economizer sections of a boiler). In this article, we review what is currently known about the effects of the low-temperature sorbent injection processes on electrical resistivity, particulate mass loading, particulate size distribution, particulate morphology and cohesivity.

Mixtures of ash and sorbent produced by low-temperature sorbent injection processes are typically less cohesive than most types of fly ash. At temperatures within 30 °F of the water dew point, the combination of low cohesivity and low electrical resistivity of the ash and sorbent mixtures can cause electrical reentrainment in electrostatic precipitators. Deliquescent additives such as calcium chloride cause the water to be retained on the particle surface, thereby increasing cohesivity.

Sorbent injection has been reported to increase the particulate mass loading by a factor of 1.8 to 10, depending upon the reagent ratio and the coal sulfur content. Conventional and in-duct spray drying processes tend to shift the particle size distribution toward larger particles, while dry injection processes tend to shift the particle size distribution toward smaller particles.     

Emissions of Sulfur Trioxide from Coal-Fired Power Plants

Abstract

Emissions of sulfur trioxide (SO₃) are a key component of plume opacity and acid deposition. Consequently, these emissions need to be low enough to not cause opacity violations and acid deposition. Generally, a small fraction of sulfur (S) in coal is converted to SO₃ in coal-fired combustion devices such as electric utility boilers. The emissions of SO₃ from such a boiler depend on coal S content, combustion conditions, flue gas characteristics, and air pollution devices being used. It is well known that the catalyst used in the selective catalytic reduction (SCR) technology for nitrogen oxides control oxidizes a small fraction of sulfur dioxide in the flue gas to SO₃. The extent of this oxidation depends on the catalyst formulation and SCR operating conditions. Gas-phase SO₃ and sulfuric acid, on being quenched in plant equipment (e.g., air preheater and wet scrubber), result in fine acidic mist, which can cause increased plume opacity and undesirable emissions. Recently, such effects have been observed at plants firing high-S coal and equipped with SCR systems and wet scrubbers. This paper investigates the factors that affect acidic mist production in coal-fired electric utility boilers and discusses approaches for mitigating emission of this mist.     

Minnesota Power’s Operating Experience with Integrated Particulate and SO2 Scrubbing

Minnesota Power currently has in commercial operation a 500 MW gas cleaning system consisting of a venturi particulate scrubber, integrated with a spray tower SO₂ absorber. The system was designed to achieve 99.7% particulate removal and 90% SO₂ removal based upon burning a 2.8 % sulfur coal.

Initially the concept of using a venturi for wet particulate collection was selected based upon a significant cost saving of $25 million compared to dry particulate collection devices. Subsequently, the Interaction of particulate collection with SO₂ removal provided additional operating cost benefits. Prior to start-up of the commercial system, a pilot plant was used to evaluate various modes of operation. Results showed that alkali contained in the fly ash removed with the venturi was sufficient to meet the alkali requirement for SO₂ removal.

Clay Boswell Station Unit No. 4 was started up during March 1980. Since initial start-up the system has exhibited almost 100% availability. EPA compliance testing has confirmed that the system Is meeting its emission standards. The unit is operating with fly ash as the only source of alkali. Since commercial operation started, no external alkali has been purchased.

This paper will discuss the design details of the system and performance of the commercial system.     

Full-Scale Evaluation of Mercury Control with Sorbent Injection and COHPAC at Alabama Power E.C. Gaston

Abstract

The overall objective of this project was to determine the cost and impacts of Hg control using sorbent injection into a Compact Hybrid Particulate Collector (COHPAC) at Alabama Power’s Gaston Unit 3. This test is part of a program funded by the U.S. Department of Energy’s National Energy Technology Laboratory (NETL) to obtain the necessary information to assess the costs of controlling Hg from coal-fired utility plants that do not have scrubbers for SO₂ control. The economics will be developed based on various levels of Hg control.

Gaston Unit 3 was chosen for testing because COHPAC represents a cost-effective retrofit option for utilities with existing electrostatic precipitators (ESPs). COHPAC is an EPRI-patented concept that places a high air-to-cloth ratio baghouse downstream of an existing ESP to improve overall particulate collection efficiency. Activated carbons were injected upstream of COHPAC and downstream of the ESP to obtain performance and operational data.

Results were very encouraging, with up to 90% removal of Hg for short operating periods using powdered activated carbon (PAC). During the long-term tests, an average Hg removal efficiency of 78% was measured. The PAC injection rate for the long-term tests was chosen to maintain COHPAC cleaning frequency at less than 1.5 pulses/bag/hr.     

Improved Spray Dry Scrubbing through Grinding of FGD Recycle Material

A laboratory size spray dry scrubbing unit consisting of a spray dryer and a pulse Jet baghouse was used to study the effect of grinding recycle waste on SO₂ removal across the spray dryer and on sorbent utilization. The equipment treats simulated flue gas with a dry flow rate of 1.5 m³ h^?1 (stp) and utilizes an ultrasonic nozzle for atomization. The apparatus was initially tested over a broad range of operating conditions; a close agreement in SO₂ removal was found with data from much larger units. The effect of grinding the FGD recycle material on the SO₂ removal across the spray dryer was found to be great. Grinding the recycle material can enhance the SO₂ removal efficiency to a level comparable to operation with a large excess of fresh lime.     

Supply Curves for Using Powder River Basin Coal to Reduce Sulfur Emissions

Abstract

Supply curves were prepared for coal-fired power plants in the contiguous United States switching to Wyoming's Powder River Basin (PRB) low-sulfur coal. Up to 625 plants, representing ～44% of the nameplate capacity of all coal-fired plants, could switch. If all switched, more than $8.8 billion additional capital would be required and the cost of electricity would increase by up to $5.9 billion per year, depending on levels of plant derating. Coal switching would result in sulfur dioxide (SO₂) emissions reduction of 4.5 million t/yr. Increase in cost of electricity would be in the range of 0.31-0.73 cents per kilowatt-hour. Average cost of S emissions reduction could be as high as $1298 per t of SO₂. Up to 367 plants, or 59% of selected plants with 32% of 44% nameplate capacity, could have marginal cost in excess of $1000 per t of SO₂. Up to 73 plants would appear to benefit from both a lowering of the annual cost and a lowering of SO₂ emissions by switching to the PRB coal.