PB86-108263 I Primary Sulfate Balsaion Factors for the NAPAP (National Acid Precipitation Assessment Program) Emissions Inventory Radian Corp., Research Triangle Park? NC Prepared for Environmental Protection Agency Research Triangle Park, NC Sep 85 ------- EPA/600/7-85/037 September 1985 PRIMARY SULFATE EMISSION FACTORS FOR THE NAPAP EMISSIONS INVENTORY by James B. Homolya Radian Corporation 3200 East Chapel Hill Road/Progress Center Research Triangle Park, North Carolina 27709 Contract No. 68-02-3994 Work Assignment 5 Project Officer J. David Mobley A1r and Energy Engineering Research Laborato-y U. S. Environmental Protection Agency Research Triangle Park, North Carolina 27711 AIR AND ENERGY ENGINEERING RESEARCH LABORATORY OFFICE OF RESEARCH AND DEVELOPMENT U.S. ENVIRONMENTAL PROTECTION AGENCY RESEARCH TRIANGLE PARK, NC 27711 ------- TECHNICAL REPORT DATA (Htat ntd Inunctions on iht rtreru btfon compttMt) • REPORT NO EPA/600/7-85/037 2. 3 RECIPIENT'S ACCESSION1 WO. 4 TITLE AND SUBTITLE Primary Sulfate Emission Factors for the NAPAP Emissions Inventory I. REPORT DATS September 1985 I. PERFORMING ORGANIZATION COOi 7 AUTHORISI James B. Homolya I. PERFORMING OROANIIATION REPORT NO • PERFORMING ORGANIZATION NAME AND AOORE SB Radian Corporation P. O. Box 13000 Research Triangle Park. North Carolina 27709 10. PROGRAM ELEMENT NO. 11. CONTRACT/GRANT NO. 68-02-3994, Task 5 12 SPONSORING AOf NCV NAMI AND ADORES* EPA, Office of Research and Development Air and Energy Engineering Research Laboratory Research Triangle Park, NC 27711 13. TYPE Of REPORT AND PERIOD COVERED Task Final; 9/83 - 7/85 14. SPONSORING AGENCY COOS EPA/600/13 is SUPPLEMENTARY NOTIS AEERL project officer is J. David Mobley. Mail Drop 6TT9T9/ 541-2612. is. ABSTRACT jne report gives results of an estimation of primary sulfate emission fac- tors for use in the 1980 and 1985 National Acid Precipitation Assessment Program (NAPAP) emissions inventories. The estimates were developed from an assessment of existing measurements data for source categories including external combustion. chemical manufacturing, primary metals, wood products, mineral products, and petroleum refining. Initial elements of the assessment summarized primary sulfate formation mechanisms prevalent in combustion processes and reviewed the state- of-the-art methodology for primary sulfate sampling and analysis of source emis- sions, The Controlled Condensation System (CCS) was evaluated as the best primary sulfate emission measurement approach. CCS-derived measurement data were ab- stracted from an inventory of reports consisting of a variety of environmental asses- sment studies, field measurement evaluation experiments, and the U.S. /Canadian Work Group 3B inventory. The measurement data were then used to estimate primary sulfate emission factors for the corresponding source categories. Uncertainty esti- mates are given for each emission factor, and source catego* ies are identified where data are either lacking or incomplete to permit the assignment of an emission factor. KEY WORDS AND DOCUMENT ANALYSIS DESCRIPTORS b IDENTIPlSRS/OPEN ENDED TERMS C. COSATl f KM/Croup Pollution Sulfates Emission Precipitation Acidity Measurement Combustion Chemical Industry Metals Wood Products Minerals Petroleum Refining Pollution Control Stationary Sources AcH Rain NAPAP 13B D7B 14G 04B 07 D 21B 07A 11F 11L 08G 13H t DISTRIBUTION STATEMENT Release to Public IS SECURITY CLASS Unclassified 21 NO or PAOIS I 56 20 SECURITY Unclassified 13 PRICE EPA Perm 1110-1 IS-73) ------- NOTICE This document has been reviewed in accordance with U.S. Environmental Protection Agency policy and approved for publication. Mention of trade names or commercial products does not constitute endorse- ment or recommendation for use. ii ------- ABSTRACT Primary sulfate emission factors were estimated for Task Group B, Man-Mada Sources, of the National Add Precipitation Assessment Program (HAPAP), for use In the 1980 and 1985 NAPAP Emissions Inventories. The estimates were developed from an assessment of existing measurements data for source categories Including external combustion, chemical manufacturing, primary metals, wood products, mineral products, and petroleum refining. Initial elements of the assessment summarized primary sulfate formation mechanisms prevalent In combustion processes and reviewed the state-of-the-art methodology for primary sulfate sampling and analyses of source emissions. The controlled condensation system (CCS) method was evaluated as the best primary sulfate emission measurement approach. CCS-deHved measurement data were abstracted from an Inventory of reports consisting of a variety of environmental assessment studies, field measurement evaluation experiments, and the U. S./Canadian Work Group 3B Inventory. The measurement data were then used to estimate primary sulfate emission factors for the corresponding source categories. Uncertainty estimates are given for each emission factor ard source categories are Identified where data Is either lacking or Incomplete to permit the assignment of an emission factor. ill ------- CONTENTS Abstract . . . . , ill Tables vi Abbreviations Vii 1. Project SuMMry 1 Introduction 1 Approach f . . 2 Recommended Primary Sulfate Emission! Factors for the NAPAP Inventories 4 2. Formation of Primary Sulfates In Combustion Sources 9 Fuel Characteristics 9 Combustion Processes 11 3. Review of Primary Sulfate Emission Measurement Methodology ... 16 Absorption Systems 17 Condensation Systems . . 17 4. Review of Available Primary Sulfate Emission Factor Data Bases . . 19 Primary Sulfate Emission Factors from the SURE Emissions Inventory 19 Primary Sulfate Emission Factors Utilized by working Group 38 21 Emission Characterization of Major Fossil Fuel Power Plants In the Ohio River Valley 21 Primary Sulfate Emissions from a Lignite and a Western Bituminous Coal-Fired Utility Source 25 Measurement of Sulfate Emissions at KCP&L Hawthorne Station, Kansas City, Missouri 27 CCEA — Sulfates Sampling and Analysis on a Utility FGO Unit 30 Primary Sulfate Emissions from Residual 011-Flred Boilers . . 30 Primary Sulfate Emissions from a Coal- and Oil-Fired Industrial Boiler with FGO Controls 32 Primary Sulfate Emissions from a Dry Bottom Industrial Boiler Firing Pulverized Bituminous Coal 34 Primary Sulfate Emissions from Low-Sulfur Residual 011-Flred Commercial and Institutional Boilers 37 Primary Sulfate Emissions from a Bark/Coal-Fired Boiler ... 39 Primary Sulfate Emissions from 011-Flred Residential Heating Sources 39 Primary Sulfate Emissions at a Scrubber-Equipped Coal-Fired Boiler 41 References 43 ------- TABLES Number Page 1 Primary Sulfate Emission Factors for NAPAP Emissions Inventory . . 5 2 CompjHson of Fuel Characteristics 10 3 Effects of Fuel Oil Characteristics on PSE 11 4 Primary Sulfate Emission Factors Utilized for Working Group 38 Emissions Estimate 22 5 Primary Sulfate Emission Factors for Bituminous Coal-Fired Utility Sources 26 6 Primary Sulfate Emission Factors for a Lignite and a Western Bituminous Coal-Fired Utility Source 28 7 Primary Sulfate Emission Factors for a Nixed Bituminous Coal-Fired Utility Bailer 29 8 Primary Sulfate Emission Factor for a 31luminous Coal-Fired Utility Source 31 9 Primary Sulfate Emission Factors for Residual Oil-Fired Utility Boilers 33 10 Primary Sulfate Emission Factors for a Bituminous Coal or Residual Oil-Fired Industrial Boiler with FGO 35 11 Primary Sulfate Emission Factor for a Coal-Fired Dry Bottom Industrial Boiler 36 12 Primary Sulfate Emissions from Residential/Institutional Boilers Burning Low-Sulfur Residual 011 38 13 Primary Sulfate Emission Factor for a Wood Bark- and Coal-Fired Boiler 40 14 Primary Sulfate Emission Factors for Distillate 011-Fired Residential Heating Sources 42 15 Primary Sulfate Emission Factors for a Scrubber-Equipped Coal-Fired Boiler 43 vi ------- LIST OF ABBREVIATIONS AND SYMBOLS ABBREVIATIONS Ib — pound (0.45359 Mlogran) ton — short ton (906.18 kilograms) gal — U. S. gallon (3.7853 liters) bbl . — barrel (42 U. S. gallons) MW — megawatt (1.02 x 10* kilograms-meters/second) vii ------- SECTION 1 PROJECT SUMMARY INTRODUCTION The National Add Precipitation Assessment Program (NAPAP) was established by the United States Congress In 1980 to coordinate and expand research relevant to the problems posed by acid deposition In and around the United States. NAPAP 1s organized and Managed through the Interagency Task Force on Add Precipitation (ITFAP) and ten subordinate task groups coordinating specific technical areas of research. Task Group B: Man-Hade Sources has the basic two-fold objectives of: 1. Providing an accurate and complete Inventory of emissions from man-made sources beloved to be Important 1n acid deposition processes. The Inventories are to be provided with adequate geographic, temporal, and sectoral resolution. 2. Providing models which predict how acidic and acld-presursor emissions may be altered by factors such as economic growth, fuel supply, emissions regulation, and control techniques. The models are to have the capability to permit the calculation of alternative control strategies. Task Group B has prepared a NAPAP Emissions Inventory Implementation Plan which 1s designed to address the needs of the NAPAP research programs being conducted by the other nine task groups within ITFAP. In general, the emissions Inventory needs of these various task groups can be summarized 1n two categories: 1. Detailed, multlcomponent point and area source disaggregated Inventory for defined annual base years to support the development and testing of atmospheric transport and transformation models to predict add deposition. 2. Retrospective Inventory summaries of addle and acld-presursor emissions over the past eighty years to support historical analyses of materials damage and to aid In developing policy assessments. ------- Tht modeling activities presently envisioned by NAPAP Include the utilization of both Eulerian and Lagranglan Acid Deposition Models. Eulerlan nodel development Is being directed by the EPA/ORO Environmental Sciences Research Laboratory which 1s supporting the development of a modeling approach similar to the Northeast Regional 0x1dent Study (NEROS) Model. Lagranglan •odeling Involves the use of existing models developed by EPA and others. Given the general emissions Inventory requirements of each modeling approach and the needs of those task groups dealing with assessments and historical analyses, the NAPAP Emissions Inventory Implementation Plan Identified that the level of temporal, spatial, and sectoral resolution to be contained 1n the NAPAP Emissions Inventory. The highest level of detail 1n the NAPAP Inventory must be directed to the requirements of the Eulerlan Model. Emissions Inventory development 1s geared to provide data for both the 1980 and 1985 base years which have been targeted for modeling studies. The 1980 Inventory contains emissions for S02, NO , VOC, primary sulfate, NH3, CO, and partlculate matter. APPROACH This report summarizes an analysis of existing data on primary sulfate emissions from a variety of source categories and presents a tabulation of primary sulfate emission factors appropriate for use with the NAPAP Emissions Inventory. This analysis also Identified areas where data are either lacking or Incomplete to permit the assignment of an emission factor. The study does not address the relative Importance or abundance of primary sulfates 1n the atmosphere compared to "secondary" sulfate derived from the atmospheric transformation of sulfur dioxide. These types of assessments require extensive emissions and air quality measurements which must be evaluated through the use of complex transport and transformation models. Prior to the current need for NAPAP Task Group B to Inventory primary sulfate emissions, two different environmental program activities have Included assessments of primary sulfate emission factors for use In emission Inventory development. The EPRI-sponsored sulfate regional experiment (SURE) program summarized existing experimental measurements data on primary sulfates and recommended generalized emission factors for a large number of source ------- categories. For the most part, many of the factors were based upon an extrapolation of a United data set for uncontrolled fossil fuel combustion sources along with data contained In the EPA Emission Factor Guidelines (AP-42) for sulfurlc acid manufacturing to Inventory the range of source classification coded point and area sources 1n the mldwestern and northeastern United States and southeastern Canada. At that time, primary sulfate field measurement methodology was under development by EPA. Consequently, much of the existing data In the literature were qualified by the uncertainty of the sampling and analysis procedures. In fact many of the available field measurement data were obtained for the purpose of method development with the attendant problem that few critical supporting measurements were taken to permit the proper calculation of emission factors. More recently, the United States/Canada Work Group 3B (WG 3B) prepared an emissions measurement report 1n accordance with the Memorandum of Intent on Transboundary A1r Pollution of August 1980. The report Included an estimate of United States and Canadian primary sulfate emissions using emission factors obtained from a study of available data conducted by the Ontario Research Foundation. Those emission factors were abstracted fro* similar open literature sources used for preparation of the SURE Inventory along with unpublished emissions data from Canadian measurements. Emission factors were reported for uncontrolled fossil fuel combustion sources as well as for primary metal smelters. Measurements data for smelters were acquired from tests in Canada using a variety of sampling and analysis methods. Since the preparation of the SURE and WG 3B inventories, several developments have occurred regarding primary sulfate emission measurements. The first major development has been the acceptance of a standard sampling and analysis procedure for sulfate emission assessment. The source emission measurement technical community now agree that the controlled condensation sampling (CCS) procedure is the best approach for the determination of H2S04, and particulate sulfate emissions from stationary sources. Although this acceptance does not invalidate previous source measurements using methodology available at the time, the Integration of CCS into field measurement programs conducted by EPA and other has afforded the opportunity to assess the general consistency of sulfate emission measurements conducted at various point sources within given source categories. 3 ------- As a result of a series ot environmental assessment studies conducted by the EPA's Industrial and Environmental Research and Environmental Sciences Research Laboratories, several field programs Included detailed primary sulfate emission measurements taken at both uncontrolled and S02-controlled utility and Industrial sources utilizing a variety of fuels. The Importance of sulfate emission measurements for scrubber-equipped sources became apparent after researchers discovered that scrubbers removed proportionately less sulfate than S02 from flue gases. Therefore, the objective of this report 1s to summarize the current body of sulfate emissions data. This Investigation consisted of four major activities Including: 1. a summary discussion of primary sulfate formation mechanisms thought to be prevalent In combustion processes; 2. assessment of the state-'of-the-art met'iodology for primary sulfate sampling and analysis of source emissions; 3. review of the SURE and WG 3B primary sulfate emission Inventories; and 4. collection, review, and calculdtion of primary sulfate emission factors derived from additional field studies not Included 1n the SURE and WG 3B Inventories. RECOMMENDED PRIMARY SULFATE EMISSION FACTORS FOR THE NAPAP INVENTORIES Primary sulfate emission factors recommended for use In the NAPAP Emissions Inventories are given 1n Table 1. The factors are reported for a number of source classification codes (SCCs) based on an analysis of available data. Most of the current data set 1s for fossil fuel combustion 1n the Industrial and utility sectors. The emission factors have been calculated to a normalized Emissions Information System (EIS) format as: Sulfate emissions per SCC unit = (Emission factor x percent sulfur content of fuel) The emission factors given 1n Table 1 reflect sulfate emitted as SO}2 based upon chemical analyses of source test samples. The source descriptions and fuel sulfur contents for fossil fuel combustion are given in Section 4. Emission factors for fuel sulfur contents other than those given 1n Section 4 ------- TABLE 1. PRIMARY SULFATE EMISSION FACTORS FOR NAPAP EMISSIONS INVENTORY Source category ilectrlc Utmtle* - Uternal Conbmttor (astern bltuBtnow coal Western bltuBtnou* coal Lignite •ettduel ell (>tt sulfur contmt) Industrial - Uternal Coabustlon fastern bttuBlnous coal Residual otl CoMMrcUI/lnstltutlonaV - CaUriMl Co^uttlon •Mlducl oil < Industrial trocttt - PrlMry Httalt rrlatry copper taclurt NEDS Source cUstlflcetlon coot (SCC) Control d»«tc» 1-01-002 IS* iv tnt tea 1-01-002 1ST isr and rco 1-01-003 csr 1-01-004 ruol oil «ddltl«« 1-02-002 Nulttcloiw* Nulttclonot and FCO 1-02-004 Nultlclonn NulttclonM *nd FCO l-OJ-004 Fuel oil aditUiw 1-05-001-05 Horn 3-Q1-OJ3 OnliUr 3-03fOOS-l 3-03-005-2 J-OJ-OOS-3 3-QJ-OOS-4 •rUMry iulf«U * ••tttton lector 0.385 ID/ton 0 2SOt -1.290 0 Til . • l.»l 5 43* lb*/1.000 .. gellom 2.M6 Ibt/ton 0.4*2 S.2W lb*/1.000 gelloi* 2 »16 25 07 Ibt/l.OOOi 0*1 Ion* ».U lbs/1.000 gel Ion* 0.100 Ib/toa ectd produced 22 S lb*/ton concentrated ore 1 01 57* IS 6t Uncertainty Reference . range* ' ». » n. M .26. 37 M 29 M. 31 30 30 30 32 14 • 4 4 4 4 4 * C • C C • • . . C 0 0 C C t C C 0 0 (continued) ------- TABLE 1. (continued) Source category Industrial Process - Prlaery Metals (Cont'd) ' Prlaary tine saelters . - Priaary aluainua saolter Iron production Cote Industrial Process - Mood Produc tt Kraft pulp aill Sulfite pulp Bill - ' Mood/bark waste Industrial Process - Mineral Products Ceaent aanufacturing Cypsua aanufacturing Industi lal Process - Petreleua Industry fluid crackers Sulfur recovery Claws plants MfOS Source classification code (SCO . Control device 3-03-030 3-0«-001 3-03-008 3-03-003 3-07-001 3-07-002 1-02-009 Nultlc tenet - 3-05-006 and 3-05-007 3-OV01S 3-06-002 ESP 3-01-032 Prlaary sulfate eaission factor Reference 5$ 5 Ibs/ton processed 0 &X of SO, 2 OX of SO, 0 320 ID/ton coal charged -• •• 3.6 Ibs/ton ' bark tt M. - 15 0 lbs/1.000 barrels ell 2 • Ibs/ton produced 4 4 4 4 4 4 33 ' 4 4 4. 4 Uncertainty range* 0 0 0 0 C c 0 0 0 c . c * CstiMted ••Isiian factor uncertainty Attunes that 90S of the values for an Individual source II* within Uie e»an uncertainty ettleutes. Corresponding values are: A > *10»; • » t2SS; C • iSOB; 0 - S7SX, and [ > 100X. - » [Billion factor based en average sulfete scrubbing efficiency of 3SX. - . I t«l»»io« factor applicable only U low sulfur content (0.3* i, residual fuel oil • Total sulfate ea'issions fe" kraft pulp Blllt estiMted us 8SS of NCOS total earticulate enlsslens froB kraft recovery boilers (see Reference 3t). . - - •* Tout sulfate ealsslons froB MdluB-tase sulfite Bills estimated at 70» of NEOS SO, eaisslons; for ctlclua-base sulfite Bills estimated as 2Sk of MCOS SO, eaisslont (tee Reference 3s>). tt total sulfate Missions I ram ceeent kilns estlBtted as 5.6 Ibs/ton of ceaent on an uncontrolled basis Average partlcuVate control efficiency froa MfOS'data-assuBed to apply in order to ca'cvlate actual eBlssions (see Reference 3i). ii Total sulfate froa gypsue plants estlaated as MX as NEDS actual partlculate eaisstons (>ee Reference 36) ------- can only be estimated since the dependence of primary sulfate emissions on fuel sulfur content had not been studied 1n detail. In fact, the limited data available suggest that sulfate emissions can be markedly affected by other parameters such as furnace oxygen levels and trace element content of the fuel. For source categories oJter than fossil fuel combustion, sulfate emission factors are reported In standard SCC units or as percentages of mass part1cu1ate emissions. The calculation of specific primary sulfate emission factors were based on the following heirarchical Selection process. 1. Where available, all field measurements using the CCS procedure were considered as the prime data set. 2. Sulfate emission assessments were aggregated for different point sources within the same source category only If fuel composition and emission controls were similar. 3. Emissions data acquired through the use of methods other thnn CCS were Included only If multiple measurements yielded data with minimal scatter. Therefore, the primary sulfate emission factors summarized In Table 1 are representative of the current emissions data base and reflect the WG 3B emission factors calculated for source categories other than fuel combustion. There are a number of source categories for which no experimental field data exist. At present,-the only alternative to an emission factor for the NAPAP Emission Inventory 1s the assignment of an "assumed11 factor already contained within the source allocation codes Tor the Regional Model Data Handling System (RMDHS). However, most of the regional mass emissions of primary sulfates should occur from those source categories for which emission factors have already been substantiated (utility and Industrial fossil fuel burning). The best approach to Improving the NAPAP Emissions Inventory sulfate component may be an expanded field measurement activity which focuses on those source categories which have not been sufficiently characterized but are potentially significant contributors to regional emissions. Improvements are needed In the data base for low sulfur residual oil-fired Industrial and commercial boilers. Field measurements using the CCS procedure are recommended for this source type which 1s a significant source of sulfur ------- Missions In Major Metropolitan areas In the eastern United States. In addition, sulfate emissions from the pulp and paper Industry need further characterization given the large preliminary emission factors reported by WG 3B. Pulp Mill operations a:e concentrated In the add deposition sensitive Northeast and represent a major S0a and particulate source contributor 1n the southeastern United States. ------- SECTION 2 FORMATION OF PRIMARY SULFATES IN COMBUSTION SOURCES Sulfur present In fossil fuels 1s emitted to the atmosphere mainly as sulfur dioxide (S0a). However, some of the sulfur Is oxidized further In the combustion process and Is emitted In a variety of forms, collectively known as "primary sulfates". These forms Include gaseous sulfur trloxlde (S03) and sulfurlc acid (H2S04), sulfurlc add mist, and metallic sulfates (MS04, where M may be metal or ammonium Ions). Secondary sulfates are formed In the atmosphere by the oxidation of some of the emitted S0a. Some S02 and sulfates, both primary and secondary, are returned to the earth by wet or dry deposition. Others remain 1n the atmosphere and may be transported far from the emission source. These atmospheric sulfates form ambient aerosols - stable mixtures of gases, liquid droplets, and particles. The largest source of primary sulfate emissions (PSE) appears to be from the combustion of coal and oil. The amount of primary sulfates emitted from a particular combustion source 1s dependent on a great number of factors. Among these are fuel type and composition, equipment type and design, operating parameters, and emission controls. FUEL CHARACTERISTICS A significantly higher conversion of fuel sulfur to primary sulfates occurs during oil firing as compared to coal firing. In general, the fraction of fuel sulfur emitted as primary sulfates has been found to be related to the metals content of the fuel as well as the amount of excess air used for combustion. It 1s believed that, among other factors, the relatively higher vanadium and nickel content of residual fuel oil contributes to the higher conversion of fuel sulfur to sulfate. ------- Several other fuel characteristics have an effect on PSE. Table 2 shows some of the properties of coal and oil which are Important In assessfng the potential of the fuel to form primary sulfates when burned. TABLE 2. COMPARISON OF FUEL CHARACTERISTICS Coal Fuel oil Burn rate Relatively slow Relatively fast Ash content 5 to 15** 0.01 to 0.20% Principal metals S1, Al, Fe, Ca Mg, Na, V, N1 Minor netals Mg, Na, K Ca, Fe, Al Sulfur content 0.2 to TV 0.1 to 4% * Weight percent, dry basis. Characteristics of Coal Coal Is a slow-burning fuel, which results In a lower flame temperature than Is achieved with oil firing. Relatively low flame temperatures lessen production of S03 formed In the flame zone by the combination of S02 with atomic oxygen. The principal metals which typically constitute coal ash are silicon, aluminum, Iron, and calcium, which are usually present In the oxide form. Magnesium, sodium, and potassium are usually present, but 1n much smaller amounts. Certain coal ashes such as those formed from lignite combustion are basic, so some of the acid formed during coal combustion Is neutralized 1n the flue gases by the large quantity of ash produced. The high ash content and slow burning properties of the fuel tend to make coal-fired boilers emit less of the fuel sulfur as S03 and H2S04 than oil-fired boilers of comparable size. Although the sulfur content of coal 1s In many cases higher than fuel oil, some of the sulfur present In coal 1s trapped In bottom ash which 1s not emitted to the atmosphere. In any case, the sulfate content of bituminous coal ash emitted to the atmosphere 1s less than 1.5 percent as SOJ. 10 ------- Properties of Fuel Oil The low ash, fast burning properties of fuel oil favor formation of pr1 >ary sulfates during oil firing. In particular, the ability of some of the principal metals 1n oil ash to catalyze the formation of SOA 1n the combustion process contributes to Increased sulfate emissions. Table 3 summarizes the effects on PSE of different fuel oil characteristics. \ TABLE 3. EFFECTS OF FUEL OIL CHARACTERISTICS ON PSE Increasing. . . Causes. . . Percent V In oil Increased S03, H2S04 and MS04 emissions Other metals In oil Increased MS04 emissions Percent S In oil Increased S03, H2S04 and MS04 emissions COMBUSTION PROCESSES Specifics of the combustion process, such as equipment type and design, operating parameters, and emission controls, can affect the quantity of PSE. There are several possible mechanisms by which primary sulfates are believed to form 1n combustion processes. Primary Sulfate .Formation Mechanisms r~! Sulfates are formed In combustion processes 1n both the flame region and downstream In the heat transfer section. The proportions of total PSE formed In each region are not known, and probably vary from process to process. Primary sulfates are formed by oxidation of S02 to S03, hydratIon of S03 to H2S04, corrosion of boiler Internals by H2S04, and conversion of metallic oxides 1n ash to partlculate sulfates. 11 ------- In combustion flames, the predominant sulfate formation mechanism 1s reaction of S0a with molecular oxygen to form S03. In the adlabatlc flame region, peaks of SQ3 can occur which coincide with peaks of 0 atom concen- tration resulting from Co combustion. However, as combustion reactions reach equilibrium, SO* concentrations drop to less than 1 ppmv, thus only a small portion of emitted S0a 1s formed 1n the flame region. Ai combustion products are cooled by radiative and conductive heat transfer 1n the post-flame region, 0 atom concentrations exceed 0-02 equilibrium. This causes an Increase 1n S03 concentration above S02-S03 equilibrium levels at the flame temperature. With further cooling, production of 0 atoms ceases. Oxygen molecules form from 0 atoms, which are rapidly depleted by this reaction. This depletion prevents formation of more S03, the concentration of which remains at a superequlHbrlum level above that normally expected at the flame temperature. The final S03 concentration depends on 02 concentration, cooling rate, and the location and rate of mixing of excess air. Only fuel-rich combustion (zero percent excess 02) can prevent S03 formation by flame processes. For fuel-lean combustion, S03 concentration Increases nearly linearly with 02 concentration 1n the range zero to 3 percent excess 02. In excess of 3 percent Oa above stolchlometrlc, only slight Increases 1n S03 concentration are noted. Decreasing the level of excess 02 In the combustion process has been shown to decrease sulfate emissions, but this practice Is not feasible for all systems. The rate of cooling of combustion gases in the temperature range 1,650°C to 820°C 1s another parameter affecting Sti3 formation 1n the post-flame region. An Increase 1n S03 concentration occurs when combustion products are rapidly cooled In the heat transfer section of the boiler. Rapid cooling rates result In superequlllbrlum 0 atom concentrations and the production of more S03, the concentration of which Increases with Increasing rates of cooling. Altering the cooling rate of combustion gases 1n existing equipment would Involve majo'- modifications. New sources designed for slower cooling rates would probably be less energy efficient overall than current designs. Proper staging of excess air addition after fuel-rich combust1on can minimize S03 formation. This technique has been used to reduce NO emissions n from combustion sources. However, staged-a1r mixing to high excess Oa levels 12 ------- In tht rang* 1,090°C to 1,650°C must bt avoided, since In this range excess 02 causes high 0 atom concentrations and results In higher S03 levels than occur with normal unstaged combustion. Further modeling and experimental work Is needed to determine whether staged air addition can be effectively used to Unit S03 formation. Tht importance of catalysis In the oxidation of S0a to S03 has been studied by many Investigators. Many different substances have been shown to have a catalytic effect on the reaction, and have thus been Implicated as contributing to Increased PSE. Hedley and Cull1s7 and Mulcahy8 have discussed the homogeneous catalysis of S0a oxidation by N02, and Levy and Merryman9 demonstrated an Increase 1n S03 when the oxldant In combustion was switched from Q2-Ar to 02-N2. Heterogeneous catalytic oxidation of S02 by metals, metal oxides, and soot suspended In the stream of combustion gases or deposited on boiler Internal surfaces can occur to substantially Increase PSE. One of the best catalysts for conversion of S02 to S03 Is V20S. Residual fuel oils from Venezuela and the Middle East contain significant amounts of vanadium, which Is liberated as V209 during combustion. Vanadium catalysis has been noted often 1n the literature.10'1*'1*'13 At high relative humidities, Fea0314*15'16 and Mn0215'17 are also strong catalysts. The major constituents of coal fly ash, S102 and A1203, are only weak catalysts. Soot (carbon) has 18 been reported to catalyze S02 oxidation but data are mainly qualitative, and little Is known of the Importance of particle characteristics or temperature on the catalytic action. Sulfurlc add Is formed by reaction of S03 with water vapor 1n combustion product gases. This H2S04 can adsorb on ash or soot particles, condense on cooler parts of the combustion equipment, or be emitted to the atmosphere as a mist. The S03-to-H2S04 conversion Is temperature- and moisture-dependent. For example, at a flue gas moisture level of eight volume percent, the following observations can be made: (1) above 370°C essentially all the S03 Is In the vapor ph:se; (2) from 370°C to 20S°C S03 reacts with water vapor to form H2S04 vapor; and (3) below 205°C, H2SQ4 condensation occurs and the gas stream consists of an equilibrium mixture of H2S04 liquid aerosol and H2S04 vapor. Because of this Integral relationship between S03 and H2S04, the two 13 ------- are often referred to collectively as S03/H2S04. As the temperature of the flue gas decreases, It approaches the add dewpolnt, which Is a function of S03/HaS04 concentration. When flue gas temperature reaches the acid dewpolnt (at a given S03/H2S04 concentration), concentrated H2S04 condenses on air heaters, ductwork, fly ash collectors, and stacks. The resulting corrosion cycle can pose a serious problem and can exacerbate primary sulfate emissions as described below. The formation mechanism for metallic sulfates (NS04) Is subject to some debate. Some HS04 1s probably formed by conversion of metal oxides In ash to sulfates by the action of adsorbed H2S04. Additionally, sulfurlc acid condensed on boiler Internals can react with the Iron (and possibly with other constituents of metallic alloys such as N1, Cr, Mo) In the system to form corrosion products. Ferrous sulfate (FeS04-7H20), a corrosion product, can further react with S02 and oxygen 1n the flue gas to yield highly corrosive ferric sulfate (Fe2(S04)3). Below pH 3, the latter will attack boiler metal, producing more ferrous sulfate, and beginning the corrosion cycle again. Another suggested mechanism, of which little Is known, 1s direct gas-to- partlcle conversion of S02 and atomic or molecular oxygen to particulate sulfates. Process Differences The amount of PSE from combustion sources can be affected by several system design parameters, Including fuel type* source type, and equipment configuration. With few exceptions, oil-fired sources are not equipped with emission control systems. In the late 1960's, many existing sources converted to oil from coal to comply with emissions regulations for S02 and partlculates. The mechanical collectors used for part1cu1ate control at these sources are Ineffective for removing significant quantities of ash from oil firing, and thus fall to substantially mitigate PSE. Recently, large p1l-f1red sources have successfully used MgO-based fuel additives, which decrease PSE from these systems. In contrast to oil-fired sources, coal-fired sources often employ both participate and S02 control. Electrostatic predpltators have been shown capable of removing In excess of 50 percent of the primary sulfates generated 14 ------- 18 fro* coal combustion. Flue gas desulfurination systems not only remove S02 from stack gases, but also trap some of the primary sulfates from coal firing. Among coal-fired sources, burner type can affect the characteristics of PSE. For example, pulverized coal firing emits particles which are, on average, smaller than those emitted from stoker-fired units. 15 ------- SECTION 3 REVIEW OF PRIMARY SULFATE EMISSION MEASUREMENT METHODOLOGY The accuracy of primary sulfate emission factors depends on the ability to accurately measure and characterize sulfate emissions. This discussion Includes descriptions and evaluations of the various method used to characterize PSE from combustion sources. The measurement of primary sulfate emissions In combustion sources has been conducted on an extractive basis. The two most commonly known methods for measuring S03/H2S04 are the collection of the acid by absorption and by selectively condensing the add 1n a temperature-controlled condenser. Both of these methods, which Involve the extraction of the sample, have critical parameters which affect the accuracy of the emission measurement. The first element, whlcn Is common to all such extractive sampling of flue gases. Is the separation of the part1cu1ate matter from the gaseous portion of the sample gas. If one Is to speak of acid as a separate species from participate sulfste, this separation must be achieved prior to the collection and measurement method. This separation 1s ordinarily attempted by placing some type of filter on or In the sample entrance end of the probe. The potential difficulty with the probe filter not only Involves the efficiency with which the separation can be achieved, but may well Involve the oxidation of S02 either on the filter material Itself or on the participates which accumulate on the filter surface during sampling. For the acid collection after this separation, problems have also been proposed both with respect to the oxidation of S02 In the absorption medium as well as acid mist collection efficiency for both methods. Extractive sampling of flue gases for the purpose of measuring S03 and H2S04 can be summarized by stating that the accuracy of the measurement Is contingent on how well the separation can be achieved as well as how efficiently the add can be collected. 16 ------- ABSORPTION SYSTEMS A number of Investigators have developed some form of the selective absorption procedure. In selective absorption, the gas stream enters an 1ce cooled bubbler containing a solution of 80 percent Isopropyl alcohol (IPA), which absorbs the H2S04 and passes most of the S02. The S02 Is absorbed downstream 1n H202 bubblers and oxidized to sulfate. There 1s evidence that IPA prevents the oxidation of S02, so that tneoretlcally absorbed S02 can be purged later from the IPA bubbler using S02-free air (normally ambient air). This procedure Is the basis for the standard EPA Method 6. Several Investigators, recognizing the need to collect both metallic sulfates (NS04) and H2S04, have extended the M6 system by the addition of a glass wool plug In the probe. This modified Method 6 (MM6) procedure 1s capable of partially separating MS04 from the gaseous H2S04 (Including S03), and has been used extensively to measure PSE. However, a laboratory study has shown that the alkaline nature of the glass plug actually favors capture of a major portion of the sulfurlc acid In the emission stream. This results 1n an Incomplete separation of H2S04 and MS04. The operation of the MM6 train 1s similar to EPA Method 6. At the end of the test, the probe 1s removed from the stack and any S02 dissolved 1n the IPA Implnger Is purged with clean ambient air. The probe plug and probe are either washed with H20 or rinsed directly with 80 percent IPA and titrated. The IPA bubbler, plug, and H202 Implngers are treated In the same fashion as the EPA M6 procedure.19 The primary purpose In the design and operation of the MM6 train was to efficiently trap sulfates (sulfurlc acid and metallic sulfates) and S02. Data reported from this train 1s typically divided In water soluble sulfate (H2S04, MS04) and S02. Other selective absorption methods Include the standard EPA Method 820 and the Shell-Emeryville method.2 CONDENSATION SYSTEMS Development of the controlled condensation system (CCS) 1s generally 22 attributed to the work of Goksoyr and Ross. In the controlled condensation approach, H2S04 Is separated from the gas stream by cooling the flue gas in a 17 ------- coll below the dew paint for H2S04 but above the dew point of H20. The resulting H2S04 aerosol Is either collected on the walls of the cooling coll or on a back-up frit. The H20 and S02 passes from the controlled condensation coll (CCC) to an 1mp1nger system where the S02 1s trapped and oxidized 1n Implngers containing dilute H202. Laboratory studies have found the precision and accuracy of controlled condensation to be ±6 percent In synthetic gas streams. Recognizing the need to Improve the participate removal capability of the controlled condensation approach, an Improved filtration system was 99 9*1 9A designed, and extensive field testing "»"«^» was conducted to determine the effect of operating parameters. The use of the controlled condensation system 1s considered to be the best state-of-the-art approach for conducting primary sulfate emission measurements at fossil fuel combustion sources. 18 ------- SECTION 4 REVIEW OF AVAILABLE PRIMARY SULFATE EMISSION FACTOR DATA BASES A United number of previous emissions Inventory development programs have considered Inclusion of primary sulfates as a non-criteria pollutant to be Inventoried. Two separate activities which were Identified are: 1, Emissions Inventory for the SURE Region; and 2. Work Group 3B Emissions Inventory. In this section, the sulfate components of each Inventory are reviewed for applicability of emission factors to the NAPAP Emission Inventory. Several recent test reports were Identified which either describe t specific primary sulfate emission assessments or Included a limited number of primary sulfate measurements as part of a comprehensive environmental emissions assessment study. Each test report has been reviewed and 1s summarized. A primary sulfate emission factor has been calculated and 'listed for each source/fuel/em1ss1ons control element discussed 1n the test reports. Although each emission factor presented Is based on multiple measurements at each source, the data sets still require more Intensive study to assess the uncertainties of the source-categorized factors. PRIMARY SULFATE EMISSION FACTORS FROM THE SURE EMISSIONS INVENTORY3 The Electric Power Research Institute sponsored an extensive study which was aimed at defining the mechanisms that link emissions td ambient concen- trations of sulfur dioxide and sulfates and at the development of an air quality model that could relate emissions to ambient concentrations. The monitoring and modeling study (the Sulfate Regional Experiment - SURE) Involved the development of a detailed emissions Inventory for all man-made stationary sources of emissions and surface transportation emissions focused on the eastern United States and parts of southern Canada. 19 ------- Included 1n the inventory are emission estimates for S02 and primary sulfates. Major problems were encountered In acquiring valid and reasonably accurate data for sulfate because of the limited amount of available test data. Those data which were available for major sulfate source emissions such as fossil fuel combustion were acquired by a variety of sampling and analysis methods which had not been validated. Based on available data, the following emission rates were applied to sulfur emissions from boilers. • Coal-fired boilers. SO equivalent to 95"percent of fuel sulfur, S04 equivalent to 1.0 percent of SO , and SC2 equivalent to 99.C percent of SOX. * • Oil-fired boilers. SO equivalent to 94 percent of fuel sulfur, S04 equivalent to 6.0 percent of SO emissions, and S02 equivalent to 94.0 percent of SOX- * Sulfate emissions from sulfuHc acid plants were estimated at 20 percent of the SO emissions based on EPA estimates contained In AP-42. For mobile source gasoline combustion the limited data available on sulfate emissions from catalyst-equipped vehicles reported levels which are Insignificant. The sulfate emissions from overall gasoline combustion was estimated to be about 4 percent of the SOX. Sulfate emissions data for other sources were unavailable. Therefore, the following general assumptions were made. • For those source categories using fossil fuel combustion for process heat or steam, the sulfate emission factors for boilers were used. f Sulfate emission estimates for sulfuMc acid production were used for those source categories which used sulfuric acid in various product manufacturing schemes according to the consumption of sulfuHc add in the process. • For those source categories which could not be Included in the two previous general classifications discussed above, it was arbitrarily assumed that S04 emissions were equivalent to 0.5 percent of the SO emissions. Primary sulfate allocation factors were then assigned to the entire array of NEDS Source Classification Codes (SCC), as appropriate. As a result of the extensive extrapolation of a limited number of source measurement data sets to a wide rtinge of SCCs, there is some question regarding the uncertainties of sulfate emission estimates for a specific SCC. 20 ------- PRIMARY SULFATE EMISSION FACTORS UTILIZED BY WORKING GROUP 3B4 An missions measurement report was prepared by the U.S./Canada Work Group 38 on emissions, costs and engineering assessment 1n accordance with the Memorandum of Intent on Transboundary A1r Pollution concluded between Canada and tht United States on August 5, 1980. As part of this activity, preliminary estimates of primary sulfate emissions for tht U.S. were developed for the calendar year 1930. The work group concluded that the draft report Anthropogenic Sources and Emissions of Primary Sulfates In Canada, prepared for Environment Canada by the Ontario Research Foundation, contained the most complete collection of Information on primary sulfate emission factors. The emission factors contained In this report were based upon Information obtained from Canadian sources, open technical literature, EPA reports, and EPA data bases. Many of the references cited for the emission factor development were Identical with those used for the preparation of the EPRI-sponsored Emissions Inventory for the SURE Region. Table 4 summarizes the emission factors used to prepare the WG 3B primary sulfate emissions estimates. For consistency and IntercompaHson with similar data, the factors have been recalculated and expressed In units appropriate for NAPAP Inventory development. EMISSION CHARACTERIZATION OF MAJOR FOSSIL FUEL POWER PLANTS IN THE OHIO RIVER VALLEY25 The purpose of the study was to characterize the atmospheric emissions from five major coal-fired power plant units 1n the Ohio River Valley between Portsmouth, Ohio, and Louisville, Kentucky. This characterization provided data that are representative of the boiler fuel emission control combinations of the current power plant population scheduled to go on line before the end of 1983. The selection criteria for the units to undergo testing Included the following: • size of unit; • age and condition of unit; • furnace type and burner arrangement; • load pattern; 21 ------- TABLE 4. PRIMARY SULFATE EMISSION FACTORS UTILIZED FOR WG 38 EMISSIONS ESTIMATES Source category NEDS source classification codes (SCO Normalized primary sulfate emission factors IS} Electric Utilities Coal (1.7-2.64% S content) Residual oil (1.75-2.25X S content) Distillate oil (0.3X S content) Non-Utility Coal (2.2X S content) Industrial Oil (0.3X S content) Commercial 011 (0.3X S content) Residential 011 (0.3% S content) Primary Copper Smelters Primary Zinc Smelters 1-01-001 through 1-01-003 1-01-004 1-01-005 1-02-001 through 1-02-002 1-02-003 1-03-001 through 1-03-002 1-03-003 1-02-005 1-03-005 1-05-002 3-03-005-1 3-03-005-2 3-03-005-3 3-03-005-4 3-03-030 0.456 Ibs/ton 9.143 lbs/1,000 gallons 11.808 lbs/1.000 gallons 0.608 Ibs/ton 0.480 Ibs/ton 0.608 Ibs/ton 0.480 Ibs/ton 11.808 lbs/1.000 gallons 12.960 lbs/1,000 gallons 15.552 lbs/1,000 gallons 22.500 Ibs/ton concentrated ore 1.080 Ibs/ton concentrated ore 5.760 Ibs/ton concentrated ore 15.660 Ibs/ton concentrated ore 55.500 Ibs/ton processed (continued) ------- TABLE 4. (continued) Source category NEOS source classification codes (SCO Nomailzed primary sulfate emission factors ro OJ Primary Aluminum Smelters Iron/Steel Sintering Coke Sulfurlc Acid Kraft Pulp Mill Sulfite Pulp Nils Cement Plants Gypsum Plants Sulfur Recovery Claus Plants Catalytic Cracking Units 3-04-001 3-03-008 3-03-003 3-01-023 3-07-001 3-0/-002 3-05-006 through 3-05-007 3-05-015 3-01-032 3-06-002 0.5% of S0a 2% of S0a 0.328 Ibs/ton coal charged 0.100 Ibs/ton acid produced * t § * 2.8 Ibs/ton produced 15.0 lbs/1,000 barrels fuel * Total sulfate emissions for kraft pulp mills estimated as 85 percent of NEDS total partlculate emissions from kraft recovery boilers. t Total sulfate emissions from sodium-base sulflte mills estimated as 70 percent of NEOS S0a emissions; for calcium-base sulflte mills estimated as 25 percent of NEDS S02 emissions. § Total sulfate emissions from cement kilns estimated as 5.6 Ib/ton of cement on an uncontrolled basis. Average partlculate control efficiency from NEOS data assumed to apply In order to calculate actual emissions. f Total sulfate from gypsum plants estimated as 56 percent of NEDS actual partlculate emissions. ------- • emission control system; • operating status (e.g., retirement, emergency only); and • fuel characteristics. The units selected for testing were grouped according to the following age categories: Group 1: 25 years Or older; Group II: 10 to 25 years old; and Group III: less than 10 years old. The relative size of the units In these age categories was similar. Group I ranged from 69 to 215 MW (113 MW average); Group II from 150 to 225 MW (192 MW average); and Group III from 227 to 610 MW (469 MW average). For the purposes of the test program, one unit was selected from Group I and two units each were selected from Groups II and III. One unit from Group II and one from Group III are equipped with control devices for controlling partlculate emissions only. The other two units 1n Groups II and III are equipped with full partlculate and S02 control devices. The unit tested from Plant A has a rated nameplate generating capacity of 560 MW and was placed Into service In 1970. This Babcock and Wllcox unit has an opposed-fired burner configuration and 1s equipped with a Buell weighted wire electrostatic predpltator to control partlculate emissions. The unit for Plant fl which was selected from Group I has a rated nameplate generating capacity of 125 MW and was placed Into service In 1954. This Babcock and Wllcox unit has a front-fired burner configuration and Is equipped with a retrofit Research Cottrell CSP Installed In 1973 to control partlculate emissions. The Plant C unit, which was selected from Group II, has a rated nameplate generating capacity of 163 MW and was placed Into service In 1958. This Combustion Engineering unit has a tangential-fired burner configuration. The partlculate emission control system consists of two ESP's In series. The newer retrofit Research Cottrell ESP was Installed 1n 1975. 24 ------- A unit was selected at Plant D to represent Group III. The unit tested has a rated nameplate generating capacity of 411 MW and was placed Into service In .1978. This Sabcock and W11cox unit has an opposed-fired burner configuration. The air pollution control equipment consists of an American Air Filter (AAF) rigid frame ESP that was Installed In 1978. After passing through the ESP, the flue gas enters a carbide Hme mobile bed flue gas d«sulfur1zat1on (F6D) system which was also Installed 1n 1978 by AAF. The unit at Plant E from Group II has a rated nameplate generating capacity of 156 MW and was placed Into service In 1962. This Combustion Engineering unit has a horizontal-fired burner configuration. The air pollution control equipment consists of a Research Cottrell weighted wire ESP Installed In 1962. After passing through the ESP, the flue gas enters an AAF 11* slurry FGD system which was Installed In 1976. During onslte testing, the units were operated 1n a normal manner with the loads changing according to demand. Tests were conducted over a 5-day sampling period In an effort to obtain emission data under a number of operating conditions. The Controlled Condensation System (CCS) was utilized to simultaneously collect and differentiate particulate sulfate, H2S04, and S02. Two CCS samples were collected each day over the five day testing period. Table 5 summarizes the primary sulfate emission factors calculated from the source measurements taken at each unit. PRIMARY SULFATE EMISSIONS FROM A LIGNITE AND A WESTERN BITUMINOUS COAL-FIRED | i UTILITY SOURCE26 The purpose of the study was to provide background data on the sulfur dioxide and primary sulfate emissions from power plants burning North Dakota lignite, and Western coal. The two plants tested were the Lei and Olds Steam Plant of the Basin Electric Company, Stanton, North Dakota, and the Sherburne County (Sherco) generating plant of North States Power Company, Becker, Minnesota. The unit tested at the Leiand Olds Station 1s sized at 440 MW and went Into commercial operation In December 1975. The unit 1s a Babcock and Wllcox cyclone-fired boiler with a rated steam capacity of 3,000,000 Ib/hour. A Joy Manufacturing Company electrostatic predpltator provides a design partlculate 25 ------- TABLE 5. PRIMARY SULFATE EMISSION FACTORS FOR BITUMINOUS COAL-FIRED UTILITY SOURCES Group I II III Plant B C E E A 0 Size (MW) 125 163 156 156 560 411 Fuel sulfur Normalized primary content Emissions sulfate emission (weight X) controls factor (Ibs/ton) j 0.9 0.9 3.3 3.3 1.0 3.5 ESP ESP ESP ESP and FGD* ESP ESP and FGO 0.293 0.296 0.381 0.269 0.162 0.279 * FGD sulfate removal efficiency = 29.4 percent. 26 ------- removal efficiency of 99.5 percent. During the tests, the unit was burning a North Dakota lignite with a dry heating value of 10,515 Btu/lb containing 1.38 weight percent sulfur. Primary sulfate emissions were determined using EPA Modified Method 6. The unit tested at the Sherco plant was sized at 700 MW and employed a Combustion Engineering controlled circulation, single-reheat, balanced draft steam generator. The emission control utilizes a Combustion Engineering scrubber system which Is a tall-end limestone, negative pressure, two-stage wet scrubber. A rod venturl Is used as the first stage for particulate removal and a marble bed as the second stage for sulfur dioxide removal. The complete scrubber consists of 12 modules, 11 of which are required for full load operation. When tested, the unit was burning a Western bituminous coal with a dry heating value of 11,649 Btu/lb containing 1.10 percent sulfur. Samples were collected at both the Inlet and outlet of a representative scrubber module. Primary sulfate emission measurements were made using EPA Modified Method 6. Table 6 summarizes the primary sulfate emission factors calculated for both units tested during the program. The scrubber Inlet sulfate emissions measured at Sherco were taken prior to any particulate removal. MEASUREMENT OF SULFATE EMISSIONS AT KCP&L HAWTHORNE STATION, KANSAS CITY, MISSOURI27 The objectives of the testing Included obtaining measurements data on total water-soluble sulfates emitted from a power plant burning a mixture of Chelrea (Oklahoma) and Wyoming coals. The unit tested was built 1n 1969 by Combustion Engineering as a corner-fired boiler. It has six coal feeders and the entire boiler system 1s under positive pressure. The boiler 1s rated for 468 MW and uses two Buell Engineering electrostatic predpltators 1n series with a design load of 400 MW. During operation, two of the coal feeders use a high-sulfur Oklahoma coal with the remaining four fed with low-sulfur Wyoming coal. Total sulfate emission samples were collected at the breaching of the stack after the predpltators using EPA Modified Method 6. Table 7 summarizes the calculated primary sulfate emission factor derived from the source 27 ------- TABLE 6. PRIMARY SULFATE EMISSION FACTORS FOR A LIGNITE AND A WESTERN BITUMINOUS COAL-FIRED UTILITY SOURCE Unit size 440 MW 700 MW 700 MW Fuel sulfur content 1.38 weight X (Lignite) 1.10 weight X (Western Bituminous) 1.10 weight X (Western Bituminous) Emissions controls ESP (None) FGD* Normalized primary sulfate emission factor (Ibs/ton) 1.951 1.627 0.761 * FGO sulfate removal efficiency = 53 percent. 28 ------- TABLE 7. PRIMARY SULFATE EMISSION FACTORS FCR A MIXED BITUMINOUS COAL-FIRED UTILITY BOILER Normalized primary Fuel Emissions sulfate emission Unit size sulfur content controls factor (Ibs/ton) 468 MM 1.67 weight X* ESP 1.290 * Based on "as-fired" mixture of 1.37 percent Wyoming coal and 2.19 percent Oklahoma coal. 29 ------- measurements. The normalized emission factor represents sulfate emissions for the particular ratio of high and low sulfur coals that were being used during the testing. CCEA — SULFATES SAMPLING AND ANALYSIS ON A UTILITY FGO UNIT28 The cbntrolled-condensatlon system was used to collect reactive sulfur species at the, Inlet and cutlet of the FGO unit on Columbus and Southern Ohio Electric's Conesvllle Power Station. The Conesvllle Power Station 1s a 2,055 MW six-unit, coal-fired facility located on the Musklngum River near Coshocton, Ohio. Tests were conducted on Unit 5 which Is equipped with an FGO system. The unit Is a coal-fired, dry bottom Combustion Engineering steam generator rated at 411 MW. The fuel 1s a blend of high-sulfur Ohio coals containing approximately 4.7 percent sulfur and 15 percent ash. The air pollution control system consists of a cold-side electrostatic predpltator by Research-Cottrel1 and a Universal 011 Products/Air Correction Division sulfur dioxide scrubber. The predpltator Is designed for 99.65 percent partlculate removal. The turbulent contact S02 absorber module Is designed for an S02 removal efficiency of 89.6 percent. Gas samples were taken at the Inlet and outlet of the FGO module using the controlled-condensatlon sampling and analysis method. Table 8 summarizes the calculated primary sulfate emission factors for the source with and without FGO controls. PRIMARY SULFATE EMISSIONS FROM RESIDUAL OIL-FIRED BOILERS29 A specific point source of sulfate emissions was chosen In the Northeastern United States to assess the Impact of sulfate emissions on air quality. A comprehensive partlculate and sulfur emission characterization was performed at the Albany Steam Station, owned and operated by the Niagara Mohawk Power Corporation In Glenmont, New York. Each of four boilers at the plant Is a Combustion Engineering unit wth tangential combustion, rated at 675,000 Ibs steam/hour and 100 MW net power output. During the period of study, the plant was firing residual fuel oil of Venezuelan origin with an approximate heating value of 18,600 Btu/lb. The 30 ------- TABLE 8. PRIMARY SULFATE EMISSION FACTOR FOR A BITUMINOUS COAL-FIREO UTILITY SOURCE Unit size 411 MM Fuel sulfur content 4.7 weight X Emissions controls ESP ESP and FGD* Normalized primary sulfate emission factor (Ibs/ton) 0.793 0.480 * FGD sulfate removal efficiency = 39.5%. 31 ------- average sulfur content was 1.9 percent with vanadium and ash concentrations of 200~~ppm snd 0.12 percent , respectively. A fuel additive, consisting of magnesium and magnesium oxide in a petroleum liquid, was added to the oil just prior to combustion to inhibit corrosion caused by sulfuric acid. The additive was injected into the fuel oil feed lines at a nominal ratio of 2,500:1 (oil, additive by volumetric measure). The boilers were operated at an average of 80 percent maximum generation capacity during the measurement period. Each boiler exhaust is vented to an individual stack Three of the four boiler exhaust stacks were sampled for primary sulfate emissions using the controlled condensation sampling and analysis method. The calculated primary sulfate emission factors for each of the units is summarized in Table 9. PRIMARY SULFATE EMISSIONS FROM A COAL AND OIL-FIRED INDUSTRIAL BOILER WITH FGO CONTROLS30 s^ " . » , The study was designed to provide a comparative multimedia assessment of coal-firing and oil-firing In an industrial boiler. The boiler 1s an Integral furnace, once-through, Babcock and Wllcox unit which was installed in 1958. In 1967, the unit was converted to f1>>3 either coal or oil with a 10 MW equivalent generating capacity. The flue gases are treated by en air pollution system which consists of multlcone units and a pilot FGO unit- The multiclones are the primary participate control device. All of the flue gas passes through the multiclones after which the steam is split and two*thirds of the flue gas is ducted to the stack. The other one-third is ducted to the pilot FGD system which removes S02 and additional particulate matter. The flue gas desulfurizatlon (FGO) system was designed and manufactured by FMC Corporation. The process utilizes a sodium sulflte-sodlunf bisulfite solution as the absorbent. A high volatile bituminous feed coal was utilized for all coal-fired tests. The coal contained 1.64 weight percent sulfur with a heating value of 12,683 Btu/pound. Simultaneous primary sulfate emission measurements were made simultaneously at the inlet and outlet of the FGO unit using the controlled condensation sampling and analysis method. 32 ------- TABLE 9. PRIMARY SULFATE EMISSION FACTORS FOR RESIDUAL OIL-FIRED UTILITY BORERS Unit S1zt Fuel sulfur content (weight %) Emissions controls Normalized primary sulfate emission factor (lbs/1,000 gallons) 1 2 4 100 loo 100 1.88 Magnesium fuel oil additive 1.72 Magnesium fuel oil additive 1.45 Magnesium fuel oil additive 5.089 5.589 5.640 33 ------- Oil-fired tests were conducted with the unit fired with a No. 6 residual fuel oil containing 1.96 weight percent sulfur and a heating value of approximately 16,600 Btu/pound. The fuel vanadium content was approximately 36.5 ppm. During the tests, the furnace exit oxygen content averaged about 3.5 percent. Primary sulfate emission measurements were conducted simultaneously at the inlet and outlet of the FGO using the controlled condensation sampling and analysis method. Table 10 summarizes the calculated primary sulfate emission factors for the unit burning either coal or oil. Emission factors have been calculated for the unit operating with or without the FGO system by assuming that the FGO inlet concentrations approximate the atmospheric emissions from the boiler In the absence of sulfur dioxide controls. PRIMARY SULFATE EMISSIONS FROM A DRY BOTTOM INDUSTRIAL BOILER FIRING PULVERIZED BITUMINOUS COAL31 The study Includes an assessment of the potential Impact of air emissions, wastewater effluents, and solid wastes resulting from the operation of dry bottom industrial boilers firing pulverized bituminous coal. Consuming approximately '3 million metric tons of such coal per year, this source category constitutes the primary method of firing coal in industrial boilers. The boiler chosen for sampling and analysis was a horizontally-fired, dry bottom unit burning pulverized Appalachian bituminous coal to produce steam for process and space heating at an industrial site. The boiler has a rated firing capacity of 123 MBtu/hour and an output capacity of 100,000 Ibs steam/hour. The air emissions from the unit are controlled by a tiigh efficiency electrostatic precipitator. The coal burned has an as received heating value of 28.78 MJ/kg and a sulfur content of 0.91 percent. Air emission samples were collected at the outlet duct of the ESP using a modified EPA Method 8 procedure. Table 11 summarizes the calculated primary sulfate emission factor for the unit. 34 ------- TABU 10. PRIMARY SULFATE EMISSION FACTORS FOR A BITUMINOUS COAL OR RESIDUAL OIL-FIRED INDUSTRIAL BOILER WITH FGD Fuel type Fuel sulfur content Emissions controls NonMllzcd primary sulfate Mission factor BUunlnous coal Residual oil 1.64 weight X 1.64 weight X 1.96 weight X 1.96 weight X Multlclone Multlclone and FGD Multlclone Multlclone and FGD 2.646 Ibs/ton 0.462 Ibs/ton 5.296 lbs/1,000 gallons 2.616 lbs/1,000 gallons 35 ------- TABLE 11. PRIMARY SULFATE EMISSION FACTOR FOR A COAL-FIRED DRY BOTTOM INDUSTRIAL BOILER Fuel type Fuel sulfur content Emissions controls Normalized primary sulfate emission factor (Ibs/ton) Appalachian coal 0.91 weight % ESP 0.199 36 ------- PRIMARY SULFATE EMISSIONS FROM LOW-SULFUR RESIDUAL OIL-FIRED COMMERCIAL AND INSTITUTIONAL BOILERS32 The study Involved the measurement of primary sulfate emissions from four non-Industrial packaged boilers located In the New York, NY metropolitan area. All units tested were burning a 0.3 percent sulfur hydrodesulfurlzed residual fuel oil. Boiler No. 1 was at the Starrett City residential apartment complex 1n Brooklyn, New York which generates fts electricity, heating, and cooling requirements by a central power complex. The power station centers around four boilers, each rated at 110,000 Ibs/hour steam, at a firing rate of 7,850 Ibs/hour of fuel oil. The design primary fuel Is natural gas, but due to economic and availability considerations, the units have been operated on No. 6 fuel otT. Testing was done on the No. 4 boiler, a Combustion Engineering Type 28-VP-12W constructed 1n 1971, rated at 110,000 Ibs/hour steam. During the tests, a No. 6 residual fuel oil with a rated sulfur content of less than 0.3 percent was used as the sole fuel source. Boiler No. 2 was located at Long Island University In Brooklyn, New York. Steam requirements for the university building complex are supplied by three Compak Water Tube Generators, Model FPL-21-600, manufactured by the International Boiler Works Company. Each unit 1s rated at 24,000 Ibs/hour steam. Emission tests were run on the outlet of the No. 3 boiler. The fuel used was a No. 4 low-sulfur oil. During all test periods, the boiler was on lead status and was to run continuously at uniform load conditions. Testing was conducted at Boiler 3 which IS located at the Columbia Presbyterian Hospital in New York, NY. Five boilers supply the steam needs, two Combustion Engineering and one Babcock and Wilcox units rated at 120,000 Ibs/hour steam, and two Babcock and Wilcox units rated at 45,000 Ibs/hour steam. The units are fired with a No. 6, low sulfur oil with Gilbert Fire-Side Additive continuously Injected to the oil. All emission tests were run on the No. 3 Babcock and Wilcox boiler, rated at 120,000 Ibs/ hour steam at 250 psig built in 1975. Boiler No. 4 (a confidential source 1n New York, NY) 1s rated at 125,000 Ibs/hour steam at 300 psig. The fuel burned during all tests was a No. 6 low-sulfur residual oil. 37 ------- TABLE 12. PRIMARY SULFATE EMISSIONS FROM RESIDENTIAL/INSTITUTIONAL BOILERS BURNING LOW-SULFUR RESIDUAL OIL Unit Size (Ib/hr steam) Fuel sulfur content (weight X) Emissions controls Normalized primary sulfate emission factor (Ibs/1,000 gallons) 1 2 3 4 110,000 24,000 120,000 125,000 0.3 0.3 0.3 0.3 None None Fuel oil additive None 21.55 19.20 35.47 24.07 38 ------- All primary sulfate emission measurements were made using the modified EPA Method 6 sampling and analysis procedure. Table 12 summarizes the calculated primary sulfate emission factors for the four boilers tested during the study. PRIMARY SULFATE EMISSIONS FROM A BARK/COAL-FIRED BOILER33 A three week monitoring study was carried out to assess the Impact of stationary source emissions from a typical pulp and paper mill on local ambient air quality. Primary sulfate emission measurements were taken at a coal/wood bark-fired boiler at the mill. The unit Is a Rlley bark boiler which Is a combination stoker coal- and bark-fired boiler which 1s used for supplemental power generation. Typical steam production Is about 80 tons/hour which 1s achieved by burning a steady stream of bark from the chipping operation. Coal 1s fed by a chute as a supplemental fuel In order to maintain load. The unit 1s equipped with primary and secondary Corn multlclone mechanical collectors and a venturl scrubber. During the measurements, the unit was fired with about 29 tons/hour of bark with an average sulfur content of 0.1 percent along with about 1 ton/hour of coal. A series of seven primary sulfate emission measurements were made using the controlled condensation sampling and analysis method. Table 13 summarizes the normalized primary sulfate emission factor for the unit. PRIMARY SULFATE EMISSIONS FROM OIL-FIRED RESIDENTIAL HEATING SOURCES34 During the study, emissions from gas- and oil-fired residential heating sources were assessed through a critical examination of existing emissions data, followed by the conduct of a phased measurement program to fill gaps In the emissions data base. Partlculate sulfate, S02, and S03 omission data were obtained at two of the oil-fired sites. The cho1-». of the specific sites In the program was based on the representativeness of the sites as measured against Important characteristics of systems within each source category such as: e burner type and age; e firing rate; and e duty cycle. 39 ------- TABLE 13. PRIMARY SULFATE EMISSION FACTOR FOR A WOOD BARK- AND COAL-FIRED BOILER Normalized primary Mixed-fuel Combustion fuel Emissions sulfate emission type sulfur content controls factor Wood bark 0.1 weight X Dual multlclone 3.6 Ibs/ton (96%) and venturl Coal (4X) 40 ------- On« of the oil-fired residential combustion units tested as an Arcollner No. W.O. 351, Series 3AS3 unit with a conventional high pressure burner using a forced air heating medium with a rated capacity of 141,000 Btu/hour. The unit tested was 16 years old. The second unit tested was an Armstrong, Model L61-95 A527 device with a conventional high pressure burner. The unit, approximately six years old, was rated at 120,000 Btu/hour and employed a forced air heating medium. Both units were burning a distillate fuel oil containing approximately 0.25 percent sulfur. The controlled condensation sampling and analysis method was used to collect two samples from the emissions of each unit. Table 14 summarizes the calculated primary sulfate emission factors based on the emission iwasurements. PRIMARY SULFATE EMISSIONS AT A SCRUBBER-EQUIPPED COAL-FIRED BOILER35 The controlled condensation sampling and analysis method was used to evaluate the performance of two prototype sulfurlc acid monitors at a coal-fired boiler employing FGD. The testing was done at the Widows Creek Steam Plant Unit No. 8 operated by the Tennessee Valley Authority at Bridgeport, Alabama. The unit Is a 300 MW balanced draft, tangentially-flred coal boiler burning a 4.3 percent sulfur coal. TVA retrofitted this unit with a limestone FGD system with a designed S02 removal efficiency of 80 percent. The emission control system consists of an electrostatic preclpUator followed by four variable-throat ventuH scrubber/multl-grld tower absorber trains containing oie packed tower. SamnHng was conducted at the outlet of Module A. Table 15 contains ir-> normalized primary sulfate emission factor calculated from the measurements data. 41 ------- TABLE 14. PRIMARY SULFATE EMISSION FACTORS FOR DISTILLATE OIL-FIRED RESIDENTIAL HEATING SOURCES Unit Heating rate (Btu/hr) Age Fuel sulfur content (weight X) Normalized primary sulfate emissions factor (lbs/1,000 gallons) Arcollner Series 141,000 16 years 0.25 No. W.O. 351, 3AS3 Armstrong L61-95 A527 120,000 6 years 0.25 7.09 4.21 42 ------- TABLE 15. PRIMARY SULFATE EMISSION FACTORS FOR A SCRUBBER EQUIPPED COAL-FIRED BOILER Nomal 1 zed Unit •"*• primary sulfate slzt Fuel sulfur content •*fn1ss1ons controls emissions factor 300 MW 4.3 wt. % butunlnous FGD 0.005 Ibs/ton 43 ------- REFERENCES 1. Homolya, J.B. NAPAP Emissions Inventory Implementation Plan, TRW, EPA Contract No. 68-02-3174, Task 96, August 1, 1983. \ 2. 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Measurement otjMTand S04 Emissions at KCP&L Hawthorne Station, Kansas City, Missouri, Jtttwest Research Institute, EPA Contract No. 68-02-1403, Task No. 38, September, 1977. 28. Oelumyea, R.O. and C.A. Zee. CCEA^fulfates Sampling and Analysis on Utility FGO Unit, TRW, EPA Contract^o, 68-02-2613, Task 25, April, 1980. 29. Boldt, K.R., C.P., Chang, E.J. KaplfnfJ.M. Stansfleld, and B.R. Wuebber. Impact of a Primary Sulfate Emissions Source on Air Quality, York Research Corporation, EPA Contract No. 68-02-2965, Report EPA-600/2-80-10?, May, 1980. 30. leavltt, C., K. Arledge, C. Shin, R. Orsinl, W, Hammersma, R. Maddalone, R. Belmer, 6. Richard, and M. Yamada. Environmental Assessment of Coal- and 011-fired In a Controlled Industrial Boiler; Volume III. Comprehensive Assessment and Appendices, TRW EPA Contract No. 68-02-2613, Report EPA-600/7-78-164c, August, 1978. 31. McCurTey, W.R., E.M. Moscowltz, J.C. Ochsner, and R.B. Reznik. Source Assessment: Dry Bottom Industrial Boilers Firing Pulverized Bituminous Coal, Monsanto Research Corporation. EPA Contract No. 68-02-1874, Report EPA-600/2-79-019e, June, 1973. 32. Lambert, S., New York City Package Boilers: Particulate and Sulfur Oxide Emissions Test Report, Engineering-Science, EPA Contract No. 68-02-2815, Work Assignment No. 25, Final Report, May, 1979. 33. Dellinger, B., C. Fortune, 6. Grotecloss, J. Lorrain, and M. Pleasant, Impact on Air Qualtiy Due to Source Emissions from a Kraft Pulp and Paper Mill, Northrop Services Inc., EPA Contract No. 68-02-2566, Final Report, November, 1980. 46 ------- 34. Suprenant, N.F., R.R. Hall, K.T., McGregor, and R.S. Werner (GCA Technology Division), Emissions Assessment of Conventional Stationary Combustion Systems; Volume I. Gas- and 011-f1red Residential Heating Sources, TRW. EPA Contract No. 68-02-2197, Report EPA-bOO/7-79-0295, May, 1979. 35. Delumyea, R.D., and M.O. Cole. Field Evaluation of Two Prototype Sulfurlc Acid Monitors at a Scrubber: Equipped Coal Fired Boiler, TRW, EPA Contract No. 68-02-2812. Task No. 56, Final Report. August. 1980. 36. Anthropogenic Sources and Emissions of Primary Sulfates In Canada, Ontario Research Foundation, Draft Report P-3901/6, Contract No. 47SS.KE204-1-0318, November 30, 1981. 47 ------- ------- Page Intentionally Blank ------- -0 OJ I-1 > IH o •£ 0 fc 8 oJ £ OJ OJ > ^^^ LJ ^i ^^^1 ^B^ ^^J oj § «Q y OJ ;0 £ •"H iiii OJ £ O O ., d b rT 11 VH OJ OJ U O OJ a in c/3 < j O •0 •—i O u OJ • u 2 •g S Reproduced by NTIS National Technical Information Service U.S. Department of Commerce Springfield, VA 22161 This report was printed specifically for your order from our collection of more than 2 million technical reports. For economy and efficiency, NTIS does not maintain stock of its vast collection of technical reports. Rather, most documents are printed for each order. 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