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.     

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.     

Summary of the 1991 EPRI/EPA/DOE SO2 Control Symposium

The 1991 SO₂ Control Symposium was held December 3-6, 1991, in Washington, D.C. The symposium, jointly sponsored by the Electric Power Research Institute (EPRI), the U.S. Environmental Protection Agency (EPA), and the U.S. Department of Energy (DOE), focused attention on recent improvements in conventional sulfur dioxide (SO₂) control technologies, emerging processes, and strategies for complying with the Clean Air Act Amendments of 1990. Its purpose was to provide a forum for the exchange of technical and regulatory information on SO₂ control technology. Over 800 representatives of 20 countries from government, academia, flue gas desulfurization (FGD) process suppliers, equipment manufacturers, engineering firms, and utilities attended. In all, 50 U.S. utilities and 10 utilities in other countries were represented. In 11 technical sessions, a diverse group of speakers presented 111 technical papers on development, operation, and commercialization of wet and dry FGD, Clean Coal Technologies, and combined sulfur dioxide/nitrogen oxides (SO₂/NO_x processes.     

Sulfur Toxicity and Media Capacity for H2S Removal in Biofilters Packed with a Natural or a Commercial Granular Medium

Abstract

Two types of media, a natural medium (wood chips) and a commercially engineered medium, were evaluated for sulfur inhibition and capacity for removal of hydrogen sulfide (H₂S). Sulfate was added artificially (40, 65, and 100 mg of S/g of medium) to test its effect on removal efficiency and the media. A humidified gas stream of 50 ppm by volume H₂S was passed through the media-packed columns, and effluent readings for H₂S at the outlet were measured continuously. The overall H₂S baseline removal efficiencies of the column packed with natural medium remained >95% over a 2-day period even with the accumulated sulfur species. Added sulfate at a concentration high enough to saturate the biofilter moisture phase did not appear to affect the H₂S removal process efficiency. The results of additional experiments with a commercial granular medium also demonstrated that the accumulation of amounts of sulfate sufficient enough to saturate the moisture phase of the medium did not have a significant effect on H₂S removal.

When the pH of the biofilter medium was lowered to 4, H₂S removal efficiency did drop to 36%. This work suggests that sulfate mass transfer through the moisture phase to the biofilm phase does not appear to inhibit H₂S removal rates in biofilters. Thus, performance degradation for odor-removing biofilters or H₂S breakthrough in field applications is probably caused by other consequences of high H₂S loading, such as sulfur precipitation.     

Hydrogen Sulfide Removal From Hot Producer Gas With Sintered Absorbents

The Bureau of Mines prepared three sintered materials capable of removing H₂S from producer gas at 1000° to 1500°F. They are mixtures of ferric oxide and fly ash, ferric oxide and pumice stone, and red mud (a ferric oxide-containing residue from processing bauxite). All three absorbents were virtually completely regenerable with air. A sintered Fe₂O₃; (25%)-fly ash [75%) mixture was tested through nine H₂S absorption-air regeneration cycles without loss of absorplion capacity or attrition of the pellets. The absorbent with the greatest capacity was a red mud, absorbing 16.0% by weight of sulfur at 1000° F, 24.0% at 1250° F, and 45.1 % at 1 500° F.     

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.     

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.     

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.     

Gaseous Sulfur Pollutants from Urban and Natural Sources

Major aspects of the circulation through the atmospheric environment of sulfur pollutants have been estimated, including source magnitudes, residual atmospheric concentrations, and scavenging processes. The compounds considered include SO₂ and H₂S, as well as sulfates. One-third of the sulfur reaching the atmosphere comes from pollutant sources, mainly as SO₂. Within the atmosphere there is a net transfer of sulfur from land to ocean areas. Pollutant sources annually amount to 73 × 10⁶ tons as sulfur while natural sources amount to 142 × 10⁶ tons, mainly as H₂S and sulfate sea spray. More than two thirds of the natural and pollutant sulfur emissions occur in the northern hemisphere. When only pollutant emissions are considered, 93 per cent occur in the northern hemisphere.     

空速和二氧化碳对沼气脱硫剂硫容确定的影响

为了弄清空速与二氧化碳含量对氧化铁脱硫剂硫容确定的影响,分别在实验气源为纯硫化氢,空速为40、80、120和160 h-1以及实验气源为二氧化碳含量分别在0%、20%、40%和80%,其余为硫化氢,空速为80 h-1条件下,对T502(粗脱硫剂)和HXT-2(精脱硫剂)2种氧化铁脱硫剂进行了不同测试条件对氧化铁硫容确定影响的研究。研究结果表明,T502和HXT-2氧化铁脱硫剂硫容测试结果随着空速和二氧化碳含量增加而减少,结果显示了在空速较低条件下(120h-1),二氧化碳含量在40%以下时对氧化铁脱硫剂硫容测试结果影响不大,但二氧化碳含量在40%以上时,对氧化铁脱硫剂硫容测试结果影响显著。     

Laboratory and Field Evaluation of the Controlled Condensation System for S03 Measurements in Flue Gas Streams

The study reported by this paper involves the use of the Controlled Condensation System (Goksoyr/Ross Coil) for flue gas S0₃ measurements in both the laboratory and the field, under low and high mass loadings. The Controlled Condensation System cools the flue gas to below the dewpoint of H₂S0₄ but above the H₂0 dewpoint. The resulting aerosol is collected either on the coil walls or on the back-up glass frit. The laboratory recovery of the H₂S0₄ in streams of varying S0₂, H₂0, and H₂S0₄ content was found to be 95 ± 6%. A new quartz filter holder was designed to meet the filtration problems encountered in collecting S0₃ from particle laden flue gas streams. This quartz system, when heated to above 250°C, quantitatively passed the H₂S0₄ into the condensation coil. Later studies with this filter system preloaded with fly ash equivalent to a mass loading of 1.3 g/m³ yielded a 80-85% recovery of H₂S0₄. The laboratory system was simultaneously tested at a 150 megawatt, pulverized coal-fired power plant prior to and after a wet limestone FGD. The inlet grain loading to the FGD ranged from 0.06 g/m³ to 11.4 g/m³ with S0₂ concentrations as high as 4000 ppm. The average inlet H₂S0₄ value was 8.3 ppm and the outlet from the FGD was 3.1 ppm. The source fluctuation value was determined to be ±65%.     

Sulfur Gas Emissions From Stored Flue Gas Desulfurization Sludges

The emissions of volatile sulfur-containing compounds from 13 flue gas desulfurization (FGD) sludge field storage sites have been characterized. Sulfur gas emissions from the sludge surfaces were determined by measuring the sulfur gas enhancement of sulfur-free sweep air passing through a dynamic emission flux chamber placed over selected sampling sites. Samples of the enclosure sweep air were cryogenically concentrated in surface-deactivated Pyrex “U” traps. Analyses were conducted by wall-coated, open-tubular, capillary column, cyrogenic gas chromatography using a sulfur-selective, flame photometric detector. Several major variables associated with FGD sludge production processes were examined in relation to the measured range and variations in sulfur fluxes including: (a) the sulfur dioxide scrubbing reagent used, (b) sludge sulfite oxidation, (c) “unfixed” or “fixed” FGD sludge, and (d) ponding or landfill storage. The composition and concentration of the measured sulfur gas emissions were found to vary with the type of sludge, the effectiveness of rainwater drainage from the landfill surface, the method of impoundment, and the sulfate/sulfite ratio of the sludge. Hydrogen sulfide, carbonyl sulfide, dimethyl sulfide, carbon disulfide, and dimethyl disulfide were identified in varying concentrations and ratios in the FGD sludge emissions. In addition, up to four unidentified organo- sulfur compounds were found in the emissions from four FGD sludges. The sulfur flux from one FGD storage pond was analyzed by gas chromatography-single ion monitoring mass spectrometry. In addition to the four identified sulfur compounds, this flux contained large concentrations of benzene, toluene, and α-pinene. The measured, total sulfur emissions ranged from less than 0.01 to nearly 0.3 kg of sulfur per day for an equivalent 100 acre (40.5 hectare) sludge impoundment surface.     

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     

Flue gas desulfurization: the state of the art

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 approximately 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 approximately 250 MWe 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 MWe and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

Abatement of Sulfur Hexafluoride Emissions from the Semiconductor Manufacturing Process by Atmospheric-Pressure Plasmas

Abstract

Sulfur hexafluoride (SF₆) is an important gas for plasma etching processes in the semiconductor industry. SF₆ intensely absorbs infrared radiation and, consequently, aggravates global warming. This study investigates SF₆ abatement by nonthermal plasma technologies under atmospheric pressure. Two kinds of nonthermal plasma processes—dielectric barrier discharge (DBD) and combined plasma catalysis (CPC)—were employed and evaluated. Experimental results indicated that as much as 91% of SF₆ was removed with DBDs at 20 kV of applied voltage and 150 Hz of discharge frequency for the gas stream containing 300 ppm SF₆, 12% oxygen (O₂), and 40% argon (Ar), with nitrogen (N₂) as the carrier gas. Four additives, including Ar, O₂, ethylene (C₂H₄), and H₂O_(g), are effective in enhancing SF₆ abatement in the range of conditions studied. DBD achieves a higher SF₆ removal efficiency than does CPC at the same operation condition. But CPC achieves a higher electrical energy utilization compared with DBD. However, poisoning of catalysts by sulfur (S)-containing species needs further investigation. SF₆ is mainly converted to SOF₂,SO₂F₄, sulfur dioxide (SO₂), oxygen difluoride (OF₂), and fluoride (F₂). They do not cause global warming and can be captured by either wet scrubbing or adsorption. This study indicates that DBD and CPC are feasible control technologies for reducing SF₆ emissions.     

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.     

Deodorization of Dimethyl Sulfide Using a Discharge Approach at Room Temperature

Abstract

The traditional technologies for odor removal of thiol usually create either secondary pollution for scrubbing, adsorption, and absorption processes, or sulfur (S) poisoning for catalytic incineration. This study applied a laboratory-scale radio-frequency plasma reactor to destructive percentage-grade concentrations of odorous dimethyl sulfide (CH₃SCH₃, or DMS). Odor was diminished effectively via reforming DMS into mainly carbon disulfide (CS₂) or sulfur dioxide (SO₂). The removal efficiencies of DMS elevated significantly with a lower feeding concentration of DMS or a higher applied rf power. A greater inlet oxygen (O₂)/DMS molar ratio slightly improved the removal efficiency. In an O₂-free environment, DMS was converted primarily to CS₂, methane (CH₄), acetylene (C₂H₂), ethylene (C₂H₄), and hydrogen (H₂), with traces of hydrogen sulfide (H₂S), methyl mercaptan (CH₃SH), and dimethyl disulfide. In an O₂-containing environment, the species detected were SO₂, CS₂, carbonyl sulfide, carbon dioxide (CO₂), CH₄, C₂H₄, C₂H₂, H₂, formal-dehyde, and methanol. Differences in yield of products were functions of the amounts of added O₂ and the applied power. This study provided useful information for gaining insight into the reaction pathways for the DMS dissociation and the formation of products in the plasmolysis and conversion processes.     

Seasonal Variations in Aerosol Composition and Acidity at Shenandoah and Great Smoky Mountains National Parks

The concentration of elements Na through Pb, select ions, and organic carbon from fine (<2.5 µm) particles has been monitored at Shenandoah and Great Smoky Mountains National Parks from 1988 through 1995. The data obtained from 1988 through 1994 show that significant changes in the concentrations of many aerosol constituents occur on a seasonal basis. Particulate sulfate and organic carbon are shown to exhibit substantially higher concentrations during the summer, while sulfur dioxide and nitrate concentrations are highest during the winter.

A method for estimating the degree of neutralization of particulate sulfate is given. This method uses routinely measured aerosol elemental compositions because ammonium ion, the primary neutralizing species for sulfate, is not measured on a routine basis. Application of this method to the selected data set shows that sulfate aerosol is most acidic during summer with an average molar H_s (moles of hydrogen associated with sulfur) to S (moles of sulfur) ratio of approximately 4. This suggests the average sulfate particle during the summer has a molar coon slightly more acidic than ammonium bisulfate (NH₄HSO₄) which has a molar hydrogen to sulfur ratio of 5. Winter H_s to S ratios, however, are approximately 8, suggesting the aerosol is on average fully neutralized ammonium sulfate [(NH₄)₂SO₄].     

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.