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BACKGROUND DOCUMENT

PROPOSED REVISION TO AP-42 EMISSION FACTORS FOR ESTIMATING PM 2.5 EMISSIONS

FROM GAS-FIRED COMBUSTION UNITS

Submitted by:

Karin RitterAmerican Petroleum Institute

1220 L Street NWWashington, D.C. 20005

202-682-8472

Prepared by:

MACTEC Federal Programs, Inc.560 Herndon Parkway, Suite 200

Herndon, Virginia 20170703-471-8383

September 2005

TABLE OF CONTENTS

1.0 INTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

2.0 AP-42 SECTIONS AFFECTED . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

3.0 AFFECTED SOURCES AND EMISSIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3

4.0 PROPOSED REVISIONS TO AP-42 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34.1 Section 1.4 Natural Gas Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74.2 Section 1.5 Liquefied Petroleum Gas Combustion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74.3 Section Stationary Gas Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74.4 Section 3.2 Natural Gas-Fired Reciprocating Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . 74.5 Section 5.1 Petroleum Refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

5.0 SUPPORTING DATA AND ANALYSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85.1 Test Reports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 85.2 Sampling Methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95.3 Sampling Results and Findings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10

5.3.1 Gas-Fired External Combustion Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 105.3.2 Natural Gas-Fired Reciprocating Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135.3.3 Stationary Gas Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

6.0 SUMMARY AND CONCLUSIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Appendix A - AP-42 Sections Revised Text Markups

Appendix B - Supporting Test Reports

Appendices included in separate PDF files and/or document

LIST OF TABLES

Table 3.0-1 1999 NEI Estimates of PM 2.5 Emissions for Natural Gas-Fired Combustion Units . . . . . . . . . 4

Table 3.0-2 1999 Estimates of PM 2.5 Emissions for LPG-Fired Combustion Units . . . . . . . . . . . . . . . . . . 6

Table 5.3-1 PM 2.5 Emission Factors for Gas-Fired Combustion Units Compared to Test Program Results for Dilution Tunnel Sampling Method and Method PRE-004/202 (lb/MMBtu) . . . . . 11

Table 5.3-2 Analysis of the Components of the PM 2.5 Condensable Fraction as Determined by Method 202 for Gas-Fired External Combustion Units (lb/MMBtu) . . . . . . . . . . . . . . . . 12

Table 5.3-3 Comparison of Sulfate Collected by Methods PRE-004/202 to Sulfate Collected by the Dilution Tunnel Sampling Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Table 5.3-4 PM 2.5 Emission Factors for Gas-Fired Reciprocating Engines Compared to Test Program Results for Dilution Tunnel Sampling Method and Method PRE-004/202 (lb/MMBtu) . . . . . 14

1Corio, L.A. and Sherwell, J. (2000), “In-stack Condensable Particulate Matter Measurements and Issues”,JAWMA, 50, 207-218.

2DeWees, W.G. and Steinsberger, K. C. (1990), “Test Report: Method Development and Evaluation of DraftProtocol for Measurement of Condensable Particulate Emissions,” EPA 450/4-90-012, Office of Air Quality Planningand Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina

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Background Document: Proposed Revision to AP-42 Emission Factors for Estimating PM 2.5 Emissions from Gas-Fired Combustion Units

1.0 INTRODUCTION

In 1997 a national ambient air quality standard (NAAQS) was established for fine particulatematter based on a particle size criterion of 2.5 micron and below (PM 2.5). The many sources of PM 2.5emissions include significant numbers of gas-fired combustion units. AP-42 provides guidance forindustry and regulators on estimating PM 2.5 emissions from the different types of gas-fired combustionunits and reports both filterable and condensable particulate matter emission rates from these sources. For gas-fired units all particulate emissions are believed to be less than 2.5 micron (all PM 2.5). The AP-42 sections addressing gas-fired combustion units are: 1.4 Natural Gas Combustion, 1.5 LiquifiedPetroleum Gas Combustion, 3.1 Stationary Gas Turbines, 3.2 Natural Gas-fired Reciprocating Engines,and 5.1 Petroleum Refining.

The adoption of the PM 2.5 NAAQS makes it essential to have accurate estimates of PM 2.5emissions in order to identify major sources and facilitate the development of realistic StateImplementation Plans (SIP) for non-attainment areas. Consequently, beginning 1998, a joint industry andgovernment program was initiated to evaluate the current methods for measuring and estimating PM 2.5emissions from gas-fired combustion sources. Programs sponsors were the US Department of Energy(DOE), the Gas Research Institute (GRI), the California Energy Commission (CEC), the New York StateEnergy Research and Development Authority (NYSERDA), and the American Petroleum Institute(API). All tests carried out in this program were conducted by GE Energy and Environmental Research(GE/EER).

The results of this program have shown that the current AP-42 emission factors significantlyoverestimate PM 2.5 emissions for these sources by including large amounts of condensable particulatematter emissions. Condensable emission rates were determined by EPA Method 202 which relies on icedimpingers to rapidly cool the sample air without any dilution. However, this method has long been suspectedof having positive bias by converting vapor phase gases such as SO2 and volatile organic compounds intoparticulate residues such as sulfate in the impinger solutions (Corio and Sherwell1 , 2000; DeWees andSteinsberger2, 1990). Consequently the sample air environment where the stack gas components react,condense, and are measured by Method 202 is not representative of the actual streams released to theatmosphere.

A new sampling methodology was developed to measure PM emissions. This new method is basedon the use of a “dilution tunnel”. The dilution tunnel serves to dilute and cool the sample air at a muchslower rate than Method 202 by diluting the sample with filtered air. The dilution tunnel sampling systemprovides measurement conditions that more closely represent the true atmospheric conditions where

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condensation might occur. This method provides more representative measurements of condensable PMfrom gas-fired combustion units. Similar dilution methods are the internationally accepted standard formeasuring particulate emissions from mobile sources. The EPA has recognized this and has establishedConditional Test Method (CTM), 039 based on dilution sampling, for measuring stationary source PM 2.5emissions. In addition, ASTM’s Technical Committee on Air Quality, Subcommittee D22.03 (Air Quality -Ambient Atmospheres and Source Emissions), has initiated a process to create a standard for the stationarysource dilution tunnel sampling method.

The joint industry-government testing program collected data from several gas-fired combustionunits using both the dilution tunnel sampling system method and traditional test methods, in an effort toestablish more representative PM 2.5 emission rates. The test program results support the need to revisethe AP-42 PM emission factors for gas-fired combustion units. AP-42 states that all PM emissions fromgas-fired combustion units are assumed to be PM 2.5 because there is no ash in natural gas and the particlesize that results from nucleation of PM from combustion products. Thus, these needed changes will alsoimpact the estimation of PM 10 and total PM emissions. The current emission factors for estimatingcondensable particulate emission rates are not representative and their deletion from AP-42 isrecommended. The current emission factors for filterable particulate emissions in AP-42 were found toprovide representative estimates of filterable PM and total PM from gas-fired combustion units.

This report presents background information on the testing program that supports the neededchanges to the AP-42 emission factors for gas-fired combustion units. This report was prepared inaccordance with the “Procedures for Preparing Emission Factor Documents, Appendix B: PublicParticipation Procedures” (EPA-454/R-95-015, Revised, November 1997). The proposed changes to AP-42 would indicate condensable PM from gas-fired combustion units are negligible and would rely on thecurrent emission factors for filterable particulate to represent both filterable PM and total PM.

2.0 AP-42 SECTIONS AFFECTED

Five AP-42 sections are affected by the proposed changes to the emissions factors for gas-firedcombustion units.

Section 1.4 Natural Gas Combustion provides emission factors for estimating emissions from naturalgas-fired boilers. Section 1.4 was last updated in July 1998. PM emission factors are presented forfilterable, condensable, and total PM. AP-42 reports all PM emissions are below 1 micron equivalentdiameter; thus, the emission factors are representative of PM, PM 10 , and PM 2.5 emission rates. Nocorrelation was found between combustion type and emissions; thus, the PM factors are intended torepresent all types of natural-gas fired boilers and heaters. The filterable PM factor represents particulatecollected on an EPA Method 5 or Method 201 filter. The condensable factor represents particulate collectedusing an EPA Method 202 (or equivalent) sampling train. The filterable PM factor was based on 21different emission tests and has a “B” rating (above average quality). The condensable PM emission factorwas based on only four tests and has a “D” rating (below average quality). Section 1.4 emission factors arewidely used to estimate emissions from all types of gas-fired fuel combustion units, particularly when thereare no specific emission factors available for combustion units in a particular industry sector.

Section 1.5 Liquified Petroleum Gas Combustion addresses the combustion of LPGs butane andpropane in industrial and commercial boilers. The emission factors presented for PM are based on thenatural gas emission factors in Section 1.4, adjusted for the heat value of the different fuels. The factorswere given an “E” rating (poor quality) since they are based on data from other than LPG combustion.

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Section 1.5 was last updated in October of 1996.

Section 3.1 Stationary Gas Turbines contains emission factors for both natural gas-fired and distillateoil-fired units. Similar to Section 1.4, condensable, filterable and total emissions factors are included fornatural gas-fired units based on EPA Method 202 and EPA Method 5. The emission factors are intended tobe representative of PM 10, although the condensable emissions are expected to be less the one micron. Allthree factors are rated “C” (average quality). Section 3.1 was last updated in April 2000.

Section 3.2 Natural Gas-fired Reciprocating Engines provides emission factors for estimatingfilterable PM 10, filterable PM 2.5, and condensable emissions from three engine types: 2-stroke lean-burn(2SLB), 4-stroke lean burn (4SLB), and 4-stroke rich burn (4SRB) engines. The same emission factor forcondensable emissions is used for each of the three engines. The factor is based on test data from two testsof 4SLB engines, the engine design with the lowest filterable emissions factors. The emission factor qualityratings for filterable emissions are “C” (based on 3 tests), “D” (based on 2 tests), and “E” ( based on 3 tests)for 2SLB, 4SLB, and 4SRB engines, respectively. The quality ratings for condensable emissions factors are“E”, “D”, and “E”, respectively. This section was last updated in July 2000.

Section 5.1 Petroleum Refining refers to Section 1.4 for emission factors for estimating emissionsfrom natural gas combustion in boilers and process heaters used in the manufacturing of petroleum productsand does not include separate emission factors for gas-fired units.

3.0 AFFECTED SOURCES AND EMISSIONS

Estimates of the number of potentially affected sources and their PM 2.5 emissions were takenfrom EPA’s 1999 National Emission Inventory (NEI). External and internal combustion source categoriesthat consumed natural gas and LPG were identified in the NEI data. The NEI data includes the number ofcombustion units that burned natural gas or LPG and the PM 2.5 emissions for 1999 in terms of totalemissions, condensable PM emissions, and filterable PM emissions. The condensable PM emissionestimates most likely were based on Method 202. Table 3.0-1 lists the PM 2.5 source categories in the NEIinventory that burned natural gas. Table 3.0-2 lists the PM 2.5 source categories that burned liquifiedpetroleum gas (LPG). Absent site-specific test data for PM 2.5 emissions, the emissions estimates for thesource categories listed on these two tables were likely prepared using AP-42 emission factors. Site-specific condensable PM was likely determined based on Method 202.

AP-42 emission factors are used extensively to estimate PM emissions from gas-fired combustionunits in all industry sectors. This includes burners fueled by natural gas and other gaseous fuels includingprocess gas streams when no test data is available. They are also used extensively to estimate emissionsfrom gas burners at commercial and institutional facilities. At sources other than power plants, PMemissions from gas-fired units are not considered significant enough to warrant expenditure of testingresources. The use of AP-42 emission factors has generally been the accepted practice for estimating PMemissions, rather than expending resources for site specific tests.

4.0 PROPOSED REVISIONS TO AP-42

The proposed changes to the AP-42 emission factors for PM 2.5 will provide a more accurateestimator of PM 2.5 emissions from sources consuming natural gas and other gaseous fuels. Emissionestimates will be lower than those based on the current factors. For sources subject to emissions fees, e.g.,Title V sources, the reduction in emissions will result in a reduction in assessed emissions fees. Improved

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accuracy of emissions estimates will improve the quality of data available for developing StateImplementation Plan (SIP) revisions for the PM 2.5 NAAQS nonattainment areas. The role that combustionof gaseous fuels plays relative to other sources contributing to PM 2.5 ambient levels will be more accuratelyreflected by regulatory authorities assessing control options.

Table 3.0-1 1999 NEI Estimates of PM 2.5 Emissions for Natural Gas-Fired Combustion Units

Source Category(SCC Codes)

Numberof Units

TotalEmissionstons/year

CondensableEmissionstons/year

FilterableEmissionstons/year

Boilers

Electric Generation (10100601, 10100602, 10100604)

1,672 20,415 17,378 2,903

Industrial (10200601, 10200602, 10200604)

16,460 29,987 22,964 8,825

Industrial CO Boilers(10201401)

34 762 664 91

Commercial/Institutional(10300601, 10300602, 10300603)

6,729 6,115 4,723 1,295

Industrial/Commercial/Institutional Heaters (10500106, 10500206)

1,861 895 19 758

Totals for Boilers 26,656 58,174 45748 13,872

Engines

Electric Generation (20100202, 20100207)

302 137 7 131

Industrial (20200202, 20200204, 20200207, 20200252,20200253, 20200254, 20200256)

6,013 11,301 8,750 2,359


576 180 12 170

Totals for Engines 6,891 11,618 8,796 2,660

Turbines

Electric Generation(20100201, 20100209)

851 9,631 1,665 8,369

Industrial(20200201, 20200203, 20200209)

1,190 8,755 2,365 7,381



Numberof Units




5

Commercial/Institutional (20300202, 20300203, 20300209)

156 731 74 660

Totals for Turbines 2,197 19,117 4,104 16,410



Numberof Units




6

Process Combustion Units

Chemical Manufacturing(30190003, 30190013, 30190023)

787 1,358 360 998

Food and Agriculture(30290003, 30291001)

388 206 55 150

Primary Metal Production(30390003, 30390013, 30390023)

214 376 197 177

Secondary Metal Production(30490003, 30490013, 30490023, 30490033)

807 1,438 1,177 261

Mineral Products(30500206, 30590003, 30590013, 30590023)

453 896 162 733

Petroleum Industry(30600105, 30600903, 30609903)

449 603 222 303

Pulp and Paper and Wood Products(30790003, 30790013)

116 1,601 770 830

Rubber and Miscellaneous Plastics Products(30890003, 30890013, 30890023)

161 70 26 44

Fabricated Metal Products(30990003, 30990013, 30990023)

487 119 53 87

Oil and Gas Production(31000205, 31000404, 31000414)

1,292 1,149 422 667

Electrical Equipment(31390003)

19 5 2 3

Miscellaneous Manufacturing Industries(39900601, 39990003, 39990013, 39990023)

549 259 126 132

Surface Coating Operations(40201001, 40290013)

1,273 1,383 955 303

Organic Solvent Evaporation(49090013, 49090023)

44 59 44 13

Totals for Process Combustion Units 7,039 9,522 4,571 4,701

Totals For Natural Gas-Fired CombustionUnits

42,883 98,431 63,192 37,643

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Table 3.0-2 1999 Estimates of PM 2.5 Emissions for LPG-Fired Combustion Units


Number ofUnits




Boilers

Electric Generation (10101001, 10101002)

89 8 1 7

Industrial (10201001, 10201002, 10201003)

356 495 433 47


402 203 181 22

Industrial/Commercial/Institutional Heaters (10500110, 10500210)

78 9 0 9

Totals for Boilers 925 715 615 85

Engines

Industrial (20201001, 20201002)

167 100 8 88

Commercial/Institutional(20301001, 20301002)

47 5 0 5

Totals for Engines 214 105 8 93

Process Combustion Units

Food and Agriculture(30290005)

5 0 0 0

Mineral Products(30500209)

21 8 1 7

Petroleum Industry(30600107, 30600905)

6 8 3 4

Rubber and Miscellaneous Plastics Products(30890004)

6 0 0 0

Miscellaneous Manufacturing Industries(39901001)

2 0 0 0

Surface Coating Operations(40201004)

16 5 0 4

Total for Process Combustion Units 56 21 4 15

Total For LPG-Fired Combustion Units 1,195 841 627 193

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The recommended revisions are based on using the AP-42 emissions factors for filterable particulate asrepresentative of both filterable and total PM 2.5 emissions from natural gas-fired and LPG-fired combustionunits. We propose elimination of the current AP-42 emission factors for Condensable particulate emissionsfrom each section. The test program results show that the use of Method 202 is inappropriate fordetermining PM 2.5 emissions from these sources as its use introduces a positive sulfate bias forcondensable emissions. The filterable PM data based on Method 201(or equivalent) is a better predictor oftotal PM emissions from all gas-fired combustion units. The proposed changes to the affected AP-42sections, 1.4, 1.5, 3.1, 3.2, and 5.1, are summarized below. The specific changes required to be made toeach Section are presented in Appendix A.

4.1 Section 1.4 Natural Gas Combustion

Subsection 1.4.3, Emissions, describes the nature of particulate matter from natural gas combustion. The section should be revised to indicate that the condensable fraction is negligible relative to the filterablefraction. The particulate matter emission factors are presented in Table 1.4-2. The emission factor for “PM(condensable)” should be changed to “negligible”. The emission factor for “PM (total)” should be changedfrom 7.6 to 1.9 lb/106 scf, or the same factor for “PM (filterable)”. Footnote “c” should be revised toindicate that based on a dilution tunnel sampling system method, condensable particulate emissions fromnatural gas combustion are negligible relative to filterable particulate emissions. In addition, the reference toMethod 202 should be deleted. Subsection 1.4.5 should be revised to reference this revision.

4.2 Section 1.5 Liquefied Petroleum Gas Combustion

Table 1.5-1 indicates in footnote “a” the emissions are the same as natural gas based on heat input. For both industrial and commercial boilers, the values listed for PM in the table should be changed to 0.17 forpropane, and 0.19 for butane based on equivalency with natural gas emission factors considering heatingvalue. Footnote “d” should be revised to indicate the values represent filterable and total particulate and thatbased on a dilution tunnel sampling system method for natural gas emissions, condensable emissions arenegligible relative to filterable particulate emissions. In addition, the footnote should indicate all PM isexpected to be below 2.5 um in aerodynamic equivalent diameter (PM 2.5). Subsection 1.5.5 should berevised to reference this update.

4.3 Section Stationary Gas Turbine

Subsection 3.1.3.3, Particulate Matter, should be revised to indicate for natural gas-fired units,Method 202 results are not considered valid for measuring condensable emissions. In addition, thisSubsection should indicate that based on a dilution tunnel sampling system method, condensable particulateemissions from natural gas combustion are negligible relative to filterable particulate emissions. The PMemissions factors for Natural Gas-Fired Turbines in Table 3.1-2a should be changed to “negligible” for “PM(condensable)” and from 6.6 E-03 to 1.9 E-03 for “PM (total)”, or the same factor for “PM (filterable)”. Subsection 3.1.5 should be revised to reference this update.

4.4 Section 3.2 Natural Gas-Fired Reciprocating Engines

Subsection 3.2.3.3 Particulate Matter should be revised to indicate condensable PM is negligiblerelative to filterable PM for natural gas-fired units. Tables 3.2-1 (2-stroke lean burn engines), 3.2-2 (4-

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stroke-lean burn engines), and 3.2-3 (4-stroke rich-burn engines) should be revised to indicate the “PMCondensable” emission factors are “negligible”. Footnotes “i”, “j”, and “k” for each table, respectively,should be revised to indicate that condensable emissions are negligible relative to filterable particulateemissions based on test data using a dilution tunnel sampling system method. Subsection 3.2.5 should berevised to reference this update.

4.5 Section 5.1 Petroleum Refining

This Section refers to Section 1.4 to find emission factors for use in estimating emissions fromnatural gas-fired “boilers and process heaters” used in the petroleum industry. No changes are required toSection 5.1.

5.0 SUPPORTING DATA AND ANALYSES

The joint industry and government test program included extensive testing to measure and comparePM emission rates from gas-fired combustion sources using both traditional sampling methods and a dilutiontunnel sampling system method. The test program goals included developing improved methods formeasuring fine particulate levels and estimating PM 2.5 emissions. Traditional methods for measuring PMinclude in-stack filters (e.g., Method 201) for measuring filterable particulate and iced impingers (e.g.,Method 202) for determining condensable particulate emissions. Method 201 and Method 202 were used tocollect the majority of the emission measurement data that was used to develop the current filterable PM andcondensable PM emission factors in AP-42 for gas-fired combustion units. The test program also includedextensive analysis of the chemical constituents that makeup the PM collected by both traditional methods andthe dilution tunnel sampling method to better define the nature and origin of PM emissions.

The dilution tunnel sampling system method used by the test program measures total particulateemissions, that is combined filterable PM and condensable PM. The method was chosen because itsimulates what happens in the combustion gases in the plume as they leave the stack. To achieve this themethod mixes the stack gas emissions with cleaned ambient air, cooling and diluting them, prior to detection. The dilution tunnel method provides for a longer residence time for condensation to occur allowing for thegrowth of dilute organic aerosols while at the same time eliminating the formation of artifacts such assulfates, which have been shown to be created by Method 202.

5.1Test Reports

The test program measured emission rates in several different gas-fired combustion units at sevendifferent test sites. Test reports were prepared for each site describing the sampling methods and approach,the measurement data, the test results, and the findings from each test. A copy of each test report isincluded in Appendix B. The subject of each test report is summarized below.

1. Development of Fine Particulate Emission Factors and Speciation Profiles for Oil- and Gas-Fired Combustion Systems. Topical Report: Test Results for a Gas-Fired Process Heater (SiteAlpha)

Unit Tested: combined exhaust from two refinery process heatersMaximum Heat Input Capacity: 184.9 MMBtu/hourFuel: refinery process gasControl Systems: none

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2. Development of Fine Particulate Emission Factors and Speciation Profiles for Oil- and Gas-Fired Combustion Systems. Topical Report: Test Results for a Gas-Fired Process Heater withSelective Catalytic NOx Reduction (Site Charlie)

Unit Tested: feed preheater to a refinery vacuum unitMaximum Heat Input Capacity: 300 MMBtu/hourFuel: natural gasControl Systems: ammonia injection, selective catalytic reduction NOx control system

3. Development of Fine Particulate Emission Factors and Speciation Profiles for Oil- and Gas-Fired Combustion Systems. Topical Report: Test Results for a Dual Fuel-Fired CommercialBoiler (Site Delta)

Unit Tested: industrial watertube package boilerMaximum Heat Input Capacity: 65 MMBtu/hourFuel: separate tests for fuel oil and natural gasControl Systems: none

4. Characterization of Fine Particulate Emission Factors and Speciation Profiles from StationaryPetroleum Industry Combustion Sources. Gas Fired Boiler - Test Report Refinery Site A

Unit Tested: steam boilerMaximum Heat Input Capacity: 650 MMBtu/hourFuel: refinery process gasControl Systems: none

5. Characterization of Fine Particulate Emission Factors and Speciation Profiles from StationaryPetroleum Industry Combustion Sources. Gas Fired Heater - Test Report Site B

Unit Tested: process heaterMaximum Heat Input Capacity: 114 MMBtu/hourFuel: refinery process gasControl Systems: none

6. Characterization of Fine Particulate Emission Factors and Speciation Profiles from StationaryPetroleum Industry Combustion Sources. Gas-Fired Steam Generator - Test Report Site C

Unit Tested: steam generatorMaximum Heat Input Capacity: 62.5 MMBtu/hourFuel: natural gasControl Systems: exhaust gas recirculation for NOx control

7. PM 2.5, PM 2.5 Precursor and Hazardous Air Pollutant Emissions from Natural Gas-Fired

Reciprocating EnginesThe three engines that were tested are described below:

UnitsTested

2-Stroke Lean-Burn

4-Stroke Rich-Burn

4-Stroke Lean Burn

Horsepower

2,700 1,626 1,665

Fuel Natural Gas Natural Gas Natural Gas

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ControlSystem

PrecombustionChambers

Non-SelectiveCatalytic Reduction

None

5.2 Sampling Methods

The sampling methods used to collect PM data were essentially the same at each of the sites. Measurements were taken for total PM, PM 10, and PM 2.5 as well as the chemical composition of the PM. The filterable particulate sampling method used was a variation of Method 201 designated by EPA asPreliminary Method PRE-004. This method requires the use of in-stack cyclones and an in-stack filter formeasuring filterable particulate as total PM and in PM 10 and PM 2.5 particle size fractions. CondensiblePM emission rates were measured using Method 202 (iced impingers).

The dilution tunnel sampling system method was also used to measure total PM 2.5. The methoduses an in-stack PM 2.5 cyclone to withdraw the exhaust gas sample into a dilution chamber for mixing withambient air. The ambient air is purified using a HEPA filter and an activated carbon bed. A portion of thediluted sample is then sent through two PM 2.5 cyclones to remove larger particles. The sample air fromone cyclone is sent through resin media for further analysis to identify semivolatile compounds. The sampleair from the second cyclone is sent to a manifold that feeds different sampling media for analyzing forcarbonyls, VOCs, organic carbon/elemental carbon, ammonia, sulfur dioxide, and total PM 2.5. The PM 2.5mass is collected on a Gelman Teflon filter.

Grab samples of the fuel gas supplies, refinery gas or natural gas, were also collected to determinetheir major components including the level of sulfur contaminants.

All sampling methods are described in complete detail in each of the test reports.

5.3 Sampling Results and Findings

The results of the test program are summarized in this section. The reader is referred to each testreport in the Appendices for a detailed discussion of the test findings for the individual test program sites.

5.3.1 Gas-Fired External Combustion Units

The PM 2.5 sampling results for the gas-fired boilers and heaters are summarized in Table 5.3-1. Results from the traditional sampling (Method PRE-004/202 ) and the dilution tunnel sampling system methodare presented for the six natural gas-fired external combustion units studied in the test program. BothMethod PRE-004 filterable PM and Method 202 condensible PM results are shown for each unit as well asthe combined average values for all six units studied. Based on the test program data for PM 2.5 samplingof external combustion units the following findings are made:

• Method PRE-004/202 Test Results versus AP-42 - On a lbs/MMBtu basis, the Method PRE-004/202 test results for PM 2.5 are essentially the same as the emission rate predicted by the AP-42emission factors for gas-fired external combustion units. This is not surprising since both sets ofemission factors are based on in-stack filter (Method PRE-004) and chilled impinger (Method 202)tests methods.

• Measurement of Condensibles - Both the AP-42 emission factors and the Method PRE-004/202 testprogram results indicate the majority of emissions from gas-fired units are condensible PM, 75% by

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AP-42 and 98% by the test program. Only 25% and 2% of the PM 2.5, respectively, are filterablePM.

• Inorganic Component - The condensable PM measured by Method 202 almost entirely consists ofinorganic compounds. Conversion of SO2 to SO3 is followed by reaction with available species suchas NH3, Na, or K to form inorganic sulfates (especially ammonium sulfate) and these comprise themajor fraction of this component.

• Dilution Tunnel Sampling System Method Test Results versus Method PRE-004/202 - The dilutiontunnel sampling system method measured PM emission rates similar to the filterable PMmeasurements by Method PRE-004, and about 1/40 of the combined Method PRE-004/202. Thus,Method 202 results show a substantial condensable PM emission rate that is not reflected in the

Table 5.3-1 PM 2.5 Emission Factors for Gas-Fired Combustion Units Compared to TestProgram Results for Dilution Tunnel Sampling Method and Method PRE-004/202 (lb/MMBtu)

Test Site(unit)

DilutionTunnel

Method PRE-004/202

Filterable Condensable Total%

Condensable

A (Boiler) 0.00036 0.00003 0.0097 0.0097 100

B (Heater) 0.00005 0.00022 0.0046 0.0048 95

C (Boiler) 0.00006 0.00007 0.0012 0.0013 94

Alpha (Heater) 0.00005 0.00044 0.0241 0.0245 98

Charlie (Heater) 0.00016 0.00006 0.0010 0.0011 95

Delta (Boiler) 0.00053 Not Measured Not Measured Not Measured Not Measured

Test Average 0.0002 0.0002 0.008 0.008 98

AP-42 0.002 0.006 0.007 75

dilution tunnel results. The magnitude of condensable emissions determined by Method 202 are believed tobe an artifact of this method, are not evident in the dilution tunnel sampling system method findings.

Analyses were also conducted to determine the components that make up the condensable PM fractiondetermined by Method 202. The results of these analyses are presented in Table 5.3-2. Based on theMethod 202 component data from the test program there are two key findings:

• Inorganic Component - The condensable PM measured by Method 202 is almost entirely inorganiccompounds. More than half of the Method 202 inorganic compounds are sulfate compounds.

• Organic Components - Organic compounds make up a small portion of the condensable fraction ofPM from gas-fired external combustion units.

The role that sulfur in the fuel plays in generating condensable PM was also analyzed using the test programresults. The test program included monitoring the stack gases for sulfur dioxide levels. Sulfate levels weredetermined by analyzing the collected samples by both the traditional Method PRE-004/202 testing and the

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dilution tunnel sampling method testing. The results of this analysis are presented in Table 5.3-3.

Key findings from the sulfur analyses are as follows:

• Sulfate Formation - Method 202 test program results generally show the formation of greater than100 times more sulfate as condensable particulate than the sulfates collected by the dilution tunnelsampling method. The difference in the conversion rate of sulfur oxides in the stack exhaust tosulfates by the two methods indicates sulfur oxide is being absorbed in the impingers and oxidized toform sulfates, i.e, an artifact of the Method 202 sampling train. The sulfate is not created in thestack gas.

Table 5.3-2 Analysis of the Components of the PM 2.5 Condensable Fraction as Determined by Method 202 for Gas-Fired External Combustion Units (lb/MMBtu)

Test Site(unit)

TotalCondensable

InorganicCondensable

SulfateCondensable

OrganicCondensable

A (Boiler) 0.0097 0.0091 0.0040 0.0006

B (Heater) 0.0046 0.0048 0.0033 0.0002

C (Boiler) 0.0012 0.0005 0.0001 0.0005

Alpha (Heater) 0.0241 0.0222 0.0180 0.0016

Charlie (Heater) 0.0010 0.0009 0.0006 0.0003

Delta (Boiler) Not Measured Not Measured Not Measured Not Measured

Test Average 0.0081 0.0075 0.0052 0.0007

% of Total PM 2.5 98 91 63 8

% of Condensable PM 92 64 8

Table 5.3-3 Comparison of Sulfate Collected by Methods PRE-004/202 to Sulfate Collected by

the Dilution Tunnel Sampling Method

Test Site(unit)

SulfurDioxide inStack Gas

(ppm)

Sulfate in Stack Gas(mg/m3)

Percent SO2 in Stack GasConverted to Sulfate

Method 202DilutionTunnel Method 202

DilutionTunnel

A (Boiler) 3.6 1.49 0.014 11% 0.10%

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B (Heater) 0.3 0.55 0.012 41% 0.88%

C (Boiler) 0.9 0.23 0.006 7% 0.19%

Alpha (Heater) 8.9 4.75 0.029 14% 0.08%

Charlie(Heater)1

0.1 0.73 0.008 153% 1.77%

Delta (Boiler) 0.4 Not Measured 0.007 Not Measured 0.49%

Test Average 2.8 1.75 0.015 17.9% 0.35%1 The results for Site Charlie appear to be incorrect and were excluded from the averages.

• Sulfate Particulate - Little sulfate is found as a constituent of the particulate collected by the dilutiontunnel sampling method. On average less than half of a percent of the sulfur oxides in the stack isconverted to sulfates, while 18% of the sulfur oxides is converted to sulfates by Method 202, againan artifact of the method.

• Nitrogen Purging - The use of the Method 202 alternative for post-test purging of collected impingersamples using nitrogen gas did not eliminate the formation of the sulfate artifact.

5.3.2 Natural Gas-Fired Reciprocating Engines

The test program results for the PM 2.5 testing of gas-fired reciprocating engines are presented inTable 5.3-4. Three engine types were tested, 2SLB, 4SLB, and 4SRB. The 4SRB engine was equippedwith a non-selective catalytic reduction (NSCR) NOx control device. The test results are compared to theemission factors from AP-42. The AP-42 factors are based on a limited number of tests as evidenced bytheir lower quality ratings. Although there is greater uncertainty in both the AP-42 emission factors and theemission estimates from the test program for reciprocating engines relative to external combustion gas-firedunits, similar patterns are observed when comparing the test program results to AP-42. Care must be takenwhen making direct comparisons between the test data and AP-42 considering the data limitations and theimpact control systems may have had on both AP-42 and test program results.

Key findings from the reciprocating engine emission data are:• Comparison of 2.5 Results - The PM 2.5 mass emission factors based on the dilution tunnel sampling

system method are approximately one half the value measured by the traditional methods. In thesetests the fuel gas had extremely low sulfur content and essentially no sulfate was found in thecondensable fraction.

• Organic Carbon - Most of this difference is attributed to differences in the organic fraction of PM2.5 collected by the two methods. As shown in the test report organic carbon accounts for themajority of PM 2.5 collected by both methods. The differences are likely due to the condensationand absorption of volatile and semi-volatile organics in the iced impingers used in Method 202.

5.3.3 Stationary Gas Turbines

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The test program did not include testing of any gas-fired stationary gas turbines. However, the testresults are believed to be directly transferrable to any gas-fired combustion unit including stationary gasturbines.

Table 5.3-4 PM 2.5 Emission Factors for Gas-Fired Reciprocating Engines Compared to TestProgram Results for Dilution Tunnel Sampling Method and Method PRE-004/202 (lb/MMBtu)

Engine TypeDilutionTunnel

Method PRE-004/202

Filterable Condensable Total%

Condensable

Test Results2SLB+PCC1 0.020 Not Measured Not Measured Not Measured Not Measured

4SLB 0.0050 0.0003 0.0060 0.0066 91%

4SRB+NSCR 0.0018 0.0003 0.0026 0.0029 90%

Test Average2 0.0034 0.0003 0.0043 0.0048 90%

AP-42 Factors2SLB N/A 0.0384 0.009913 0.0483 21%

4SLB N/A 0.0000771 0.00991 0.00999 99%

4SRB+PCC1 N/A 0.0095 0.009913 0.0195 51%

AP-42 Average N/A 0.0160 0.00991 0.0259 38%1Based on test data for engine with a pre combustion chamber (PCC) for NOx control.2Dilution tunnel sampling test average does not include 2SLB data. Average with 2SLB data is 0.0089.3Based on test data for 4SLB engine.

6.0 SUMMARY AND CONCLUSIONS

AP-42 provides emission factors for estimating PM 2.5 emissions for several different types of gas-fired combustion units. Emission factors are included for estimating both filterable and condensable fractionsof PM. For gas-fired units, all PM is expected to be PM 2.5. The filterable PM emission factors are basedon a test method using a heated, in-stack filter, i.e, Methods 5 and 201. The condensable PM emission

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factors are based cooling sampled air streams using iced impingers, i.e., Method 202. The filterableemission factors are based on the results of more tests than the condensable emission factors.

A joint industry-government test program was conducted to evaluate the methods used for estimatingPM 2.5. The test program included the conduct of PM emission tests of several gas-fired combustion unitsincluding boilers, heaters, and engines. Tests were conducted using both EPA traditional methods and anewer dilution tunnel sampling system method. The dilution tunnel sampling method was chosen because themethod creates a sampling environment that more closely matches the actual environment that plumesencounter, dilution and cooling when released from exhaust stacks. On the other hand, Method 202's icedimpingers provide dramatic cooling without dilution. The results from Method 202 testing are notrepresentative of the actual PM emissions from gas-fired units because they include a positive bias thatresults from the artificial conversion of SO2 vapor to sulfate particulate. The dilution tunnel sampling methodprovides more accurate determination of total PM 2.5 emissions, filterable and condensable combined.

The results from the test program have confirmed that the use of Method 202 to determinecondensable PM when burning low sulfur content fuel gas gives positively biased results because of artificialconversion of SO2 to sulfate in the impinger solution.

The dilution tunnel sampling method results were found to be similar to the filterable particulatedeterminations based on the use of traditional in-stack filter methods. Thus, the formation of condensableparticulate in gas-fired combustion is negligible relative to filterable particulate emission rates. The enginetests provided similar results, although the majority of the condensable emissions created by Method 202were found to be organic materials captured in the impingers but not in the PM collected by the dilutiontunnel sampling method.

Revisions are proposed to AP-42 to eliminate the Method 202-based condensable PM emissionfactors for gas-fired combustion units because they are not representative of actual emissions. The filterablePM emission factors would be retained as representative of both filterable PM and total PM. The revisionswould apply to gas-fired external combustion units, liquified petroleum combustion units, gas-fired stationarygas turbines, and gas-fired reciprocating engines.

APPENDIX B

SUPPORTING TEST REPORTS

Development of Fine Particulate Emission Factors and Speciation Profiles for Oil- and Gas-FiredCombustion Systems. Topical Report: Test Results for a Gas-Fired Process Heater (Site Alpha)

Development of Fine Particulate Emission Factors and Speciation Profiles for Oil- and Gas-FiredCombustion Systems. Topical Report: Test Results for a gas-Fired Process Heater with SelectiveCatalytic NOx Reduction (Site Charlie)

Development of Fine Particulate Emission Factors and Speciation Profiles for Oil- and Gas-FiredCombustion Systems. Topical Report: Test Results for a Dual Fuel-Fired Commercial Boiler (SiteDelta)

Characterization of Fine Particulate Emission Factors and Speciation Profiles from StationaryPetroleum Industry Combustion Sources. Gas Fired Boiler - Test Report Refinery Site A

Characterization of Fine Particulate Emission Factors and Speciation Profiles from StationaryPetroleum Industry Combustion Sources. Gas Fired Heater - Test Report Site B

Characterization of Fine Particulate Emission Factors and Speciation Profiles from StationaryPetroleum Industry Combustion Sources. Gas-Fired Steam Generator - Test Report Site C

PM 2.5, PM 2.5 Precursor and Hazardous Air Pollutant Emissions from Natural Gas-FiredReciprocating Engines

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