BACKGROUND DOCUMENT PROPOSED REVISION TO AP-42 EMISSION FACTORS FOR ESTIMATING PM 2.5 EMISSIONS FROM GAS-FIRED COMBUSTION UNITS

BACKGROUND DOCUMENT PROPOSED REVISION TO AP-42 EMISSION FACTORS FOR ESTIMATING PM 2.5 EMISSIONS FROM GAS-FIRED COMBUSTION UNITS Submitted by: Karin Ritter American Petroleum Institute 1220 L Street NW Washington, D.C. 20005 202-682-8472 Prepared by: MACTEC Federal Programs, Inc. 560 Herndon Parkway, Suite 200 Herndon, Virginia 20170 703-471-8383 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...3 4.1 Section 1.4 Natural Gas Combustion...7 4.2 Section 1.5 Liquefied Petroleum Gas Combustion...7 4.3 Section Stationary Gas Turbine...7 4.4 Section 3.2 Natural Gas-Fired Reciprocating Engines...7 4.5 Section 5.1 Petroleum Refining...8 5.0 SUPPORTING DATA AND ANALYSES...8 5.1 Test Reports...8 5.2 Sampling Methods...9 5.3 Sampling Results and Findings...10 5.3.1 Gas-Fired External Combustion Units...10 5.3.2 Natural Gas-Fired Reciprocating Engines...13 5.3.3 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

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 particulate matter based on a particle size criterion of 2.5 micron and below (PM 2.5). The many sources of PM 2.5 emissions include significant numbers of gas-fired combustion units. AP-42 provides guidance for industry and regulators on estimating PM 2.5 emissions from the different types of gas-fired combustion units 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 Liquified Petroleum 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 2.5 emissions in order to identify major sources and facilitate the development of realistic State Implementation Plans (SIP) for non-attainment areas. Consequently, beginning 1998, a joint industry and government program was initiated to evaluate the current methods for measuring and estimating PM 2.5 emissions 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 State Energy 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 significantly overestimate PM 2.5 emissions for these sources by including large amounts of condensable particulate matter emissions. Condensable emission rates were determined by EPA Method 202 which relies on iced impingers to rapidly cool the sample air without any dilution. However, this method has long been suspected of having positive bias by converting vapor phase gases such as SO 2 and volatile organic compounds into particulate residues such as sulfate in the impinger solutions (Corio and Sherwell 1, 2000; DeWees and Steinsberger 2, 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 the atmosphere. A new sampling methodology was developed to measure PM emissions. This new method is based on the use of a dilution tunnel. The dilution tunnel serves to dilute and cool the sample air at a much slower rate than Method 202 by diluting the sample with filtered air. The dilution tunnel sampling system provides measurement conditions that more closely represent the true atmospheric conditions where 1 Corio, L.A. and Sherwell, J. (2000), In-stack Condensable Particulate Matter Measurements and Issues, JAWMA, 50, 207-218. 2 DeWees, W.G. and Steinsberger, K. C. (1990), Test Report: Method Development and Evaluation of Draft Protocol for Measurement of Condensable Particulate Emissions, EPA 450/4-90-012, Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, North Carolina 1

condensation might occur. This method provides more representative measurements of condensable PM from gas-fired combustion units. Similar dilution methods are the internationally accepted standard for measuring particulate emissions from mobile sources. The EPA has recognized this and has established Conditional Test Method (CTM), 039 based on dilution sampling, for measuring stationary source PM 2.5 emissions. 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 stationary source dilution tunnel sampling method. The joint industry-government testing program collected data from several gas-fired combustion units using both the dilution tunnel sampling system method and traditional test methods, in an effort to establish more representative PM 2.5 emission rates. The test program results support the need to revise the AP-42 PM emission factors for gas-fired combustion units. AP-42 states that all PM emissions from gas-fired combustion units are assumed to be PM 2.5 because there is no ash in natural gas and the particle size that results from nucleation of PM from combustion products. Thus, these needed changes will also impact the estimation of PM 10 and total PM emissions. The current emission factors for estimating condensable particulate emission rates are not representative and their deletion from AP-42 is recommended. The current emission factors for filterable particulate emissions in AP-42 were found to provide 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 needed changes to the AP-42 emission factors for gas-fired combustion units. This report was prepared in accordance with the Procedures for Preparing Emission Factor Documents, Appendix B: Public Participation 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 the current 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-fired combustion units. Section 1.4 Natural Gas Combustion provides emission factors for estimating emissions from natural gas-fired boilers. Section 1.4 was last updated in July 1998. PM emission factors are presented for filterable, condensable, and total PM. AP-42 reports all PM emissions are below 1 micron equivalent diameter; thus, the emission factors are representative of PM, PM 10, and PM 2.5 emission rates. No correlation was found between combustion type and emissions; thus, the PM factors are intended to represent all types of natural-gas fired boilers and heaters. The filterable PM factor represents particulate collected on an EPA Method 5 or Method 201 filter. The condensable factor represents particulate collected using an EPA Method 202 (or equivalent) sampling train. The filterable PM factor was based on 21 different emission tests and has a B rating (above average quality). The condensable PM emission factor was based on only four tests and has a D rating (below average quality). Section 1.4 emission factors are widely used to estimate emissions from all types of gas-fired fuel combustion units, particularly when there are 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 and propane in industrial and commercial boilers. The emission factors presented for PM are based on the natural gas emission factors in Section 1.4, adjusted for the heat value of the different fuels. The factors were given an E rating (poor quality) since they are based on data from other than LPG combustion. 2

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 distillate oil-fired units. Similar to Section 1.4, condensable, filterable and total emissions factors are included for natural gas-fired units based on EPA Method 202 and EPA Method 5. The emission factors are intended to be representative of PM 10, although the condensable emissions are expected to be less the one micron. All three 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 estimating filterable 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 for condensable emissions is used for each of the three engines. The factor is based on test data from two tests of 4SLB engines, the engine design with the lowest filterable emissions factors. The emission factor quality ratings 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 emissions from natural gas combustion in boilers and process heaters used in the manufacturing of petroleum products and 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 taken from EPA s 1999 National Emission Inventory (NEI). External and internal combustion source categories that consumed natural gas and LPG were identified in the NEI data. The NEI data includes the number of combustion units that burned natural gas or LPG and the PM 2.5 emissions for 1999 in terms of total emissions, condensable PM emissions, and filterable PM emissions. The condensable PM emission estimates most likely were based on Method 202. Table 3.0-1 lists the PM 2.5 source categories in the NEI inventory that burned natural gas. Table 3.0-2 lists the PM 2.5 source categories that burned liquified petroleum gas (LPG). Absent site-specific test data for PM 2.5 emissions, the emissions estimates for the source categories listed on these two tables were likely prepared using AP-42 emission factors. Sitespecific condensable PM was likely determined based on Method 202. AP-42 emission factors are used extensively to estimate PM emissions from gas-fired combustion units in all industry sectors. This includes burners fueled by natural gas and other gaseous fuels including process gas streams when no test data is available. They are also used extensively to estimate emissions from gas burners at commercial and institutional facilities. At sources other than power plants, PM emissions from gas-fired units are not considered significant enough to warrant expenditure of testing resources. The use of AP-42 emission factors has generally been the accepted practice for estimating PM emissions, 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 accurate estimator of PM 2.5 emissions from sources consuming natural gas and other gaseous fuels. Emission estimates 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 3

accuracy of emissions estimates will improve the quality of data available for developing State Implementation Plan (SIP) revisions for the PM 2.5 NAAQS nonattainment areas. The role that combustion of gaseous fuels plays relative to other sources contributing to PM 2.5 ambient levels will be more accurately reflected 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) Boilers Electric Generation (10100601, 10100602, 10100604) Industrial (10200601, 10200602, 10200604) Industrial CO Boilers (10201401) Commercial/Institutional (10300601, 10300602, 10300603) Industrial/Commercial/Institutional Heaters (10500106, 10500206) Number of Units Total Emissions tons/year Condensable Emissions tons/year Filterable Emissions tons/year 1,672 20,415 17,378 2,903 16,460 29,987 22,964 8,825 34 762 664 91 6,729 6,115 4,723 1,295 1,861 895 19 758 Electric Generation (20100202, 20100207) Totals for Boilers 26,656 58,174 45748 13,872 Engines 302 137 7 131 Industrial (20200202, 20200204, 20200207, 20200252, 20200253, 20200254, 20200256) Commercial/Institutional (20300201, 20300204, 20300207) 6,013 11,301 8,750 2,359 576 180 12 170 Electric Generation (20100201, 20100209) Totals for Engines 6,891 11,618 8,796 2,660 Turbines 851 9,631 1,665 8,369 Industrial (20200201, 20200203, 20200209) 1,190 8,755 2,365 7,381 4

Table 3.0-1 1999 NEI Estimates of PM 2.5 Emissions for Natural Gas-Fired Combustion Units Source Category (SCC Codes) Number of Units Total Emissions tons/year Condensable Emissions tons/year Filterable Emissions tons/year Commercial/Institutional (20300202, 20300203, 20300209) 156 731 74 660 Totals for Turbines 2,197 19,117 4,104 16,410 5

Table 3.0-1 1999 NEI Estimates of PM 2.5 Emissions for Natural Gas-Fired Combustion Units Source Category (SCC Codes) Process Combustion Units Chemical Manufacturing (30190003, 30190013, 30190023) Food and Agriculture (30290003, 30291001) Primary Metal Production (30390003, 30390013, 30390023) Secondary Metal Production (30490003, 30490013, 30490023, 30490033) Mineral Products (30500206, 30590003, 30590013, 30590023) Petroleum Industry (30600105, 30600903, 30609903) Pulp and Paper and Wood Products (30790003, 30790013) Rubber and Miscellaneous Plastics Products (30890003, 30890013, 30890023) Fabricated Metal Products (30990003, 30990013, 30990023) Oil and Gas Production (31000205, 31000404, 31000414) Electrical Equipment (31390003) Miscellaneous Manufacturing Industries (39900601, 39990003, 39990013, 39990023) Surface Coating Operations (40201001, 40290013) Organic Solvent Evaporation (49090013, 49090023) Number of Units Total Emissions tons/year Condensable Emissions tons/year Filterable Emissions tons/year 787 1,358 360 998 388 206 55 150 214 376 197 177 807 1,438 1,177 261 453 896 162 733 449 603 222 303 116 1,601 770 830 161 70 26 44 487 119 53 87 1,292 1,149 422 667 19 5 2 3 549 259 126 132 1,273 1,383 955 303 44 59 44 13 Totals for Process Combustion Units 7,039 9,522 4,571 4,701 Totals For Natural Gas-Fired Combustion Units 42,883 98,431 63,192 37,643 6

Table 3.0-2 1999 Estimates of PM 2.5 Emissions for LPG-Fired Combustion Units Electric Generation (10101001, 10101002) Source Category (SCC Codes) Boilers Industrial (10201001, 10201002, 10201003) Commercial/Institutional (10301001, 10301002, 10301003) Industrial/Commercial/Institutional Heaters (10500110, 10500210) Number of Units Total Emissions tons/year Condensable Emissions tons/year Filterable Emissions tons/year 89 8 1 7 356 495 433 47 402 203 181 22 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) Petroleum Industry (30600107, 30600905) Rubber and Miscellaneous Plastics Products (30890004) Miscellaneous Manufacturing Industries (39901001) Surface Coating Operations (40201004) 21 8 1 7 6 8 3 4 6 0 0 0 2 0 0 0 16 5 0 4 Total for Process Combustion Units 56 21 4 15 Total For LPG-Fired Combustion Units 1,195 841 627 193 7

The recommended revisions are based on using the AP-42 emissions factors for filterable particulate as representative of both filterable and total PM 2.5 emissions from natural gas-fired and LPG-fired combustion units. We propose elimination of the current AP-42 emission factors for Condensable particulate emissions from each section. The test program results show that the use of Method 202 is inappropriate for determining PM 2.5 emissions from these sources as its use introduces a positive sulfate bias for condensable emissions. The filterable PM data based on Method 201(or equivalent) is a better predictor of total PM emissions from all gas-fired combustion units. The proposed changes to the affected AP-42 sections, 1.4, 1.5, 3.1, 3.2, and 5.1, are summarized below. The specific changes required to be made to each 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 filterable fraction. 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 changed from 7.6 to 1.9 lb/10 6 scf, or the same factor for PM (filterable). Footnote c should be revised to indicate that based on a dilution tunnel sampling system method, condensable particulate emissions from natural gas combustion are negligible relative to filterable particulate emissions. In addition, the reference to Method 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 for propane, and 0.19 for butane based on equivalency with natural gas emission factors considering heating value. Footnote d should be revised to indicate the values represent filterable and total particulate and that based on a dilution tunnel sampling system method for natural gas emissions, condensable emissions are negligible relative to filterable particulate emissions. In addition, the footnote should indicate all PM is expected to be below 2.5 um in aerodynamic equivalent diameter (PM 2.5). Subsection 1.5.5 should be revised 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, this Subsection should indicate that based on a dilution tunnel sampling system method, condensable particulate emissions from natural gas combustion are negligible relative to filterable particulate emissions. The PM emissions 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 negligible relative to filterable PM for natural gas-fired units. Tables 3.2-1 (2-stroke lean burn engines), 3.2-2 (4-8

stroke-lean burn engines), and 3.2-3 (4-stroke rich-burn engines) should be revised to indicate the PM Condensable 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 particulate emissions based on test data using a dilution tunnel sampling system method. Subsection 3.2.5 should be revised 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 from natural gas-fired boilers and process heaters used in the petroleum industry. No changes are required to Section 5.1. 5.0 SUPPORTING DATA AND ANALYSES The joint industry and government test program included extensive testing to measure and compare PM emission rates from gas-fired combustion sources using both traditional sampling methods and a dilution tunnel sampling system method. The test program goals included developing improved methods for measuring fine particulate levels and estimating PM 2.5 emissions. Traditional methods for measuring PM include 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 to collect the majority of the emission measurement data that was used to develop the current filterable PM and condensable PM emission factors in AP-42 for gas-fired combustion units. The test program also included extensive analysis of the chemical constituents that makeup the PM collected by both traditional methods and the 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 particulate emissions, that is combined filterable PM and condensable PM. The method was chosen because it simulates what happens in the combustion gases in the plume as they leave the stack. To achieve this the method 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 the growth of dilute organic aerosols while at the same time eliminating the formation of artifacts such as sulfates, 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 seven different 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 is included 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 (Site Alpha) Unit Tested: combined exhaust from two refinery process heaters Maximum Heat Input Capacity: 184.9 MMBtu/hour Fuel: refinery process gas Control Systems: none 9

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 with Selective Catalytic NO x Reduction (Site Charlie) Unit Tested: feed preheater to a refinery vacuum unit Maximum Heat Input Capacity: 300 MMBtu/hour Fuel: natural gas Control 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 Commercial Boiler (Site Delta) Unit Tested: industrial watertube package boiler Maximum Heat Input Capacity: 65 MMBtu/hour Fuel: separate tests for fuel oil and natural gas Control Systems: none 4. Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum Industry Combustion Sources. Gas Fired Boiler - Test Report Refinery Site A Unit Tested: steam boiler Maximum Heat Input Capacity: 650 MMBtu/hour Fuel: refinery process gas Control Systems: none 5. Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum Industry Combustion Sources. Gas Fired Heater - Test Report Site B Unit Tested: process heater Maximum Heat Input Capacity: 114 MMBtu/hour Fuel: refinery process gas Control Systems: none 6. Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum Industry Combustion Sources. Gas-Fired Steam Generator - Test Report Site C Unit Tested: steam generator Maximum Heat Input Capacity: 62.5 MMBtu/hour Fuel: natural gas Control 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 Engines The three engines that were tested are described below: Units Tested 2-Stroke Lean- Burn 4-Stroke Rich- Burn 4-Stroke Lean Burn Horsepowe r 2,700 1,626 1,665 Fuel Natural Gas Natural Gas Natural Gas 10

Control System Precombustion Chambers Non-Selective Catalytic 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 as Preliminary Method PRE-004. This method requires the use of in-stack cyclones and an in-stack filter for measuring filterable particulate as total PM and in PM 10 and PM 2.5 particle size fractions. Condensible PM 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 method uses an in-stack PM 2.5 cyclone to withdraw the exhaust gas sample into a dilution chamber for mixing with ambient air. The ambient air is purified using a HEPA filter and an activated carbon bed. A portion of the diluted sample is then sent through two PM 2.5 cyclones to remove larger particles. The sample air from one cyclone is sent through resin media for further analysis to identify semivolatile compounds. The sample air from the second cyclone is sent to a manifold that feeds different sampling media for analyzing for carbonyls, VOCs, organic carbon/elemental carbon, ammonia, sulfur dioxide, and total PM 2.5. The PM 2.5 mass is collected on a Gelman Teflon filter. Grab samples of the fuel gas supplies, refinery gas or natural gas, were also collected to determine their 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 test report 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 method are presented for the six natural gas-fired external combustion units studied in the test program. Both Method PRE-004 filterable PM and Method 202 condensible PM results are shown for each unit as well as the combined average values for all six units studied. Based on the test program data for PM 2.5 sampling of 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-42 emission factors for gas-fired external combustion units. This is not surprising since both sets of emission 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 test program results indicate the majority of emissions from gas-fired units are condensible PM, 75% by 11

AP-42 and 98% by the test program. Only 25% and 2% of the PM 2.5, respectively, are filterable PM. Inorganic Component - The condensable PM measured by Method 202 almost entirely consists of inorganic compounds. Conversion of SO 2 to SO 3 is followed by reaction with available species such as NH 3, Na, or K to form inorganic sulfates (especially ammonium sulfate) and these comprise the major fraction of this component. Dilution Tunnel Sampling System Method Test Results versus Method PRE-004/202 - The dilution tunnel sampling system method measured PM emission rates similar to the filterable PM measurements 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 Test Program Results for Dilution Tunnel Sampling Method and Method PRE-004/202 (lb/mmbtu) Test Site (unit) Dilution Tunnel 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 to be 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 fraction determined by Method 202. The results of these analyses are presented in Table 5.3-2. Based on the Method 202 component data from the test program there are two key findings: Inorganic Component - The condensable PM measured by Method 202 is almost entirely inorganic compounds. 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 of PM from gas-fired external combustion units. The role that sulfur in the fuel plays in generating condensable PM was also analyzed using the test program results. The test program included monitoring the stack gases for sulfur dioxide levels. Sulfate levels were determined by analyzing the collected samples by both the traditional Method PRE-004/202 testing and the 12

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 than 100 times more sulfate as condensable particulate than the sulfates collected by the dilution tunnel sampling method. The difference in the conversion rate of sulfur oxides in the stack exhaust to sulfates by the two methods indicates sulfur oxide is being absorbed in the impingers and oxidized to form sulfates, i.e, an artifact of the Method 202 sampling train. The sulfate is not created in the stack 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) Total Condensable Inorganic Condensable Sulfate Condensable Organic Condensable 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) Sulfur Dioxide in Stack Gas (ppm) Sulfate in Stack Gas (mg/m 3 ) Method 202 Dilution Tunnel Method 202 Percent SO 2 in Stack Gas Converted to Sulfate Dilution Tunnel A (Boiler) 3.6 1.49 0.014 11% 0.10% 13

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 0.1 0.73 0.008 153% 1.77% (Heater) 1 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 dilution tunnel sampling method. On average less than half of a percent of the sulfur oxides in the stack is converted to sulfates, while 18% of the sulfur oxides is converted to sulfates by Method 202, again an artifact of the method. Nitrogen Purging - The use of the Method 202 alternative for post-test purging of collected impinger samples 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 in Table 5.3-4. Three engine types were tested, 2SLB, 4SLB, and 4SRB. The 4SRB engine was equipped with a non-selective catalytic reduction (NSCR) NO x control device. The test results are compared to the emission factors from AP-42. The AP-42 factors are based on a limited number of tests as evidenced by their lower quality ratings. Although there is greater uncertainty in both the AP-42 emission factors and the emission estimates from the test program for reciprocating engines relative to external combustion gas-fired units, similar patterns are observed when comparing the test program results to AP-42. Care must be taken when making direct comparisons between the test data and AP-42 considering the data limitations and the impact 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 these tests the fuel gas had extremely low sulfur content and essentially no sulfate was found in the condensable fraction. Organic Carbon - Most of this difference is attributed to differences in the organic fraction of PM 2.5 collected by the two methods. As shown in the test report organic carbon accounts for the majority of PM 2.5 collected by both methods. The differences are likely due to the condensation and absorption of volatile and semi-volatile organics in the iced impingers used in Method 202. 5.3.3 Stationary Gas Turbines 14

The test program did not include testing of any gas-fired stationary gas turbines. However, the test results are believed to be directly transferrable to any gas-fired combustion unit including stationary gas turbines. 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) Engine Type Dilution Tunnel Method PRE-004/202 Filterable Condensable Total % Condensable Test Results 2SLB+PCC 1 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 Average 2 0.0034 0.0003 0.0043 0.0048 90% AP-42 Factors 2SLB N/A 0.0384 0.00991 3 0.0483 21% 4SLB N/A 0.0000771 0.00991 0.00999 99% 4SRB+PCC 1 N/A 0.0095 0.00991 3 0.0195 51% AP-42 Average N/A 0.0160 0.00991 0.0259 38% 1 Based on test data for engine with a pre combustion chamber (PCC) for NOx control. 2 Dilution tunnel sampling test average does not include 2SLB data. Average with 2SLB data is 0.0089. 3 Based 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 gasfired combustion units. Emission factors are included for estimating both filterable and condensable fractions of PM. For gas-fired units, all PM is expected to be PM 2.5. The filterable PM emission factors are based on a test method using a heated, in-stack filter, i.e, Methods 5 and 201. The condensable PM emission 15

factors are based cooling sampled air streams using iced impingers, i.e., Method 202. The filterable emission 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 estimating PM 2.5. The test program included the conduct of PM emission tests of several gas-fired combustion units including boilers, heaters, and engines. Tests were conducted using both EPA traditional methods and a newer dilution tunnel sampling system method. The dilution tunnel sampling method was chosen because the method creates a sampling environment that more closely matches the actual environment that plumes encounter, dilution and cooling when released from exhaust stacks. On the other hand, Method 202's iced impingers provide dramatic cooling without dilution. The results from Method 202 testing are not representative of the actual PM emissions from gas-fired units because they include a positive bias that results from the artificial conversion of SO 2 vapor to sulfate particulate. The dilution tunnel sampling method provides 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 determine condensable PM when burning low sulfur content fuel gas gives positively biased results because of artificial conversion of SO 2 to sulfate in the impinger solution. The dilution tunnel sampling method results were found to be similar to the filterable particulate determinations based on the use of traditional in-stack filter methods. Thus, the formation of condensable particulate in gas-fired combustion is negligible relative to filterable particulate emission rates. The engine tests provided similar results, although the majority of the condensable emissions created by Method 202 were found to be organic materials captured in the impingers but not in the PM collected by the dilution tunnel sampling method. Revisions are proposed to AP-42 to eliminate the Method 202-based condensable PM emission factors for gas-fired combustion units because they are not representative of actual emissions. The filterable PM emission factors would be retained as representative of both filterable PM and total PM. The revisions would apply to gas-fired external combustion units, liquified petroleum combustion units, gas-fired stationary gas turbines, and gas-fired reciprocating engines. 16

APPENDIX B SUPPORTING TEST REPORTS 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 (Site Alpha) 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 with Selective Catalytic NO x Reduction (Site Charlie) 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 Commercial Boiler (Site Delta) Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum Industry Combustion Sources. Gas Fired Boiler - Test Report Refinery Site A Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum Industry Combustion Sources. Gas Fired Heater - Test Report Site B Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum 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-Fired Reciprocating Engines