|Title||PM Emission Factors: Past, Present, and Future|
|Spatial Coverage||Houston, Texas|
|Subject||2014 AFRC Industrial Combustion Symposium|
|Description||Paper from the AFRC 2014 conference titled PM Emission Factors: Past, Present, and Future by K. Olson.|
|Abstract||Over the last fifteen years, the regulatory requirements for particulate matter (PM) species (namely, PM10 and PM2.5) have become increasingly more rigorous, and our technical understanding of PM emissions sampling has grown significantly. Even so, environmental professionals continue to rely on the historic and conservatively high EPA AP-42 emission factors for estimating PM emissions from fossil fuel-fired combustion units. Demonstrating compliance with the more restrictive PM2.5 NAAQS requires more representative PM species emission estimates to assure that PM2.5 emissions are not unrealistically over-estimated, especially for gas-fired combustion units typically found at refineries and chemical plants. Data collected in test method research programs co-sponsored by governmental and non-governmental organizations within the last 10 years provide more accurate information about PM2.5 emissions formed by gas (natural gas and refinery gas) and oil combustion, and how to more accurately measure PM2.5 emissions in the stack. However, despite this information, AP-42 emission factors for turbines, boilers, and heaters remain unchanged. Even so, technical environmental professionals (within both the private sector and government) are beginning to rely on the available supporting technical information from these research studies to estimate emissions for combustion units, using alternate PM emission factors that better represent actual PM2.5 emissions. This paper summarizes the PM2.5 emission measurement research results for gas-fired combustion units, presents recent successful uses of such alternate PM emission factors by the regulated community and identifies next steps needed to improve PM10 and PM2.5 emission factors.|
|Rights||No copyright issues exist.|
Zephyr AFRC - Page 1 of 12 PM Emission Factors: Past, Present and Future Karen Olson and Louis Corio, Zephyr Environmental Corporation Introduction Over the last fifteen years, the regulatory requirements for particulate matter (PM) species (PM10 and PM2.5) have become increasingly more rigorous. At the same time our technical understanding of PM emission species and measurement in the stack has grown significantly. However, the published PM emission factors for gas-fired combustion sources found in U.S. EPA's AP-42, established in the late- 1990s, have not been revised or "upgraded" since that time to reflect our increased understanding of PM emissions and measurement. Use of AP-42 emission factors for combustion units firing "inherently clean" natural gas overestimate emissions and often result in unnecessary complications in demonstrating compliance with the current PM2.5 NAAQS, permitting and compliance assessments EPA's recently-released PM2.5 modeling guidance1 will require additional levels of detail and accuracy in characterizing emissions from combustion sources for permitting/compliance assessment purposes. As a result, a recent trend has been for both governmental agencies and permit applicants to use alternate PM emission factors in their regulatory analyses, with the "blessing" of EPA and state regulators. This paper summarizes the results (for gas-fired combustion units) from a PM2.5 emission measurement research program, discusses how these results have been successfully used to support development and application of alternate PM emission factors, identifies areas of need for additional PM2.5 emission measurement data, and suggests recommended next steps. 1 Draft Guidance for PM2.5 Permit Modeling, Memorandum from Stephen D. Page, Office of Air Quality Planning and Standards, U.S. EPA, Research Triangle Park, NC, March 2013 PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 2 of 12 Background Background: PM Emission Testing/Measurement In general, PM emissions from fossil fuel combustion are typically composed of two components - filterable PM and condensable PM. A demonstration of compliance with PM10 and/or PM2.5 emission limits requires the use of EPA-approved in-stack test methods to measure the filterable and condensable PM components. PM that is captured in-stack on the filter of an emission test train is referred to as the filterable component of primary PM emissions (filterable PM). Solid or liquid particles that condense from gaseous emissions within seconds of exiting a stack (i.e., at ambient conditions) are referred to as the condensable component of primary PM emissions (condensable PM). All condensable PM, if emitted by a source, is in the PM2.5 size fraction; therefore, all condensable PM is a component of both primary PM2.5 and primary PM10 emissions. Total PM is defined as the sum of the filterable and condensable PM components, and is expressed as follows for the different size fractions: Total PM2.5 = Filterable PM2.5 + Condensable PM Total PM10 = Filterable PM10 + Condensable PM Condensable PM is typically the predominant emissions component for gas-fired combustion sources. The evolution of the form of the PM NAAQS over the years, especially as it relates to size fractions, has required that EPA periodically update and revise its reference test methods (TMs) to provide representative measurements of stack emissions. A brief history of the evolution of the PM TMs is provided in the appendix to this paper. The accuracy of measured emission rates needed for compliance assessment is highly dependent on the adequacy of these TMs. As described below, even with the updated TMs, the measurement of condensable PM emissions has historically continued to be a bit more problematic than the measurement of filterable PM emissions. This is evidenced by the April 8, 2014 EPA memo providing interim guidance on revised sample quality control methods for the condensable particulate matter testing2. Despite the periodic improvements in the measurement methods, the fact still remains that the EPA test methods were not designed for the level of detection needed for gas-fired combustion units. The newest combustion units on today's market are extremely efficient and emit minimal concentrations of PM when firing gas. As shown later in this paper for gas-fired units, research conducted using the dilution sampling (DS) method indicated that PM2.5 emissions are extremely low - probably near ambient air background concentrations of PM2.5 in many cases. These levels, which are well below both the estimated minimum detection limit (MDL) of the EPA TMs, are difficult to quantify with high 2 Interim Guidance on the Treatment of Condensable Particulate Matter Test Results in the Prevention of Significant Deterioration and Nonattainment New Source Review Permitting Programs, Memorandum from Stephen D. Page, Director, Office of Air Quality Planning and Standards (C404-04), to EPA Regional Air Division Directors, Regions 1-10, April 8, 2014, Research Triangle Park, NC. PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 3 of 12 confidence.3 With such low PM levels, any foreign matter (e.g., residue on improperly cleaned glassware used to collect/store samples) that is inadvertently included in the analysis can significantly bias the results high. Note that uncertainty in the EPA test method results can be reduced by extending the sampling time period from the standard one-hour run to a multiple-hour run. (The EPA PM test method requires three one-hour sampling runs.) The extended sampling run times (beyond the EPA requirement) allow for the collection of more mass during the test run. And, as acknowledged by EPA, collecting sufficient weighable mass is important for the methods to be precise (75 FR 80118). Background: AP-42 Emission Factor EPA's AP-42 document provides guidance to the regulated community and regulators to estimate emissions when other more representative data are not available. EPA characterizes the quality of emission factors based on the following two factors: 1. the quality of test data the factor is based on, and 2. whether the emission factor can be expected to be representative of the typical emission source. The EPA assessment of an emission factor is typically identified with the emission factor in AP-42 by an assigned quality rating. Per EPA, an "A" rated emission factor is the best available emission factor. As the factor ratings drop to as low as an "E" rating, the reliability of the emission factor is considered a poorer quality. AP-42 emission factors have historically been relied upon to estimate PM emissions (filterable and condensable components) from different types of gas-fired combustion units. The AP-42 emission factors were developed using the results from older versions of EPA test methods (Methods 5 or 201 for filterable PM and Method 202 for condensable PM). The AP-42 emission factor ratings for PM emissions from gas-fired combustion sources are as follows: Section 1.4, External Combustion Sources - Natural Gas Combustion (last updated in 1998): o The filterable PM emission factor has a "B" rating; o The condensable PM emission factor for external combustion sources was based on only four tests and has a "D" rating (below average quality); and o The total PM emission factor rate has a "D" rating (i.e., "below average"). Section 3.1, Stationary Internal Combustion Sources - Stationary Gas Turbines (last updated in April 2000): 3 England, G.C., "Development of Fine Particulate Emission Factors and Speciation Profiles for Oil and Gas-Fired Combustion Systems, Final Report," 2004. PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 4 of 12 o The PM emission factors were based on only three tests conducted in the mid-1990s at one facility; and o The filterable, condensable, and total PM emission factors all have a "C" rating (i.e., "average"). This information shows that the quality of the AP-42 PM emission factors is considered below average or average based on a pre-2000 assessment. Of course, based on our current understanding of the older test method inadequacies which bias test results high, a current assessment would be expected to result in an even lower rating of the existing AP-42 factors. As a result, the AP-42 emission factors for PM can generally be expected to yield unrepresentatively high emission estimates for a specific gas-fired unit, especially as it relates to condensable PM emissions. For reference, the emission factors given in AP-42 for external combustion units and combustion turbines are shown in Table 1 below. Table 1. AP-42 PM Emission Factors4 Source Type Filterable PM (lb/MMBtu) Condensable PM (lb/MMBtu) Total PM (lb/MMBtu) External Combustion Units 0.0019a 0.0056a 0.0075a Combustion Turbines 0.0019 0.0047 0.0066 a Based on a natural gas heat content of 1,020 Btu/ft3 Background: More Recent and Accurate PM Emission Testing and Emission Factors Over the period of 2000-2004, a comprehensive PM test method research program was conducted to characterize PM (in particular PM2.5) for a variety of common oil-fired or gas-fired combustion sources. This test program was co-sponsored by the U.S. Department of Energy (DOE), GE Energy and Environmental Research Corporation (GE EERC), and a number of state agencies and industry trade groups. The data gathered in that test program provide more accurate information about the PM2.5 formed by gas (natural gas and refinery fuel gas) and oil combustion, and how to more appropriately measure such emissions in the stack. The following discussion provides a summary of that test program and the relevant resulting data which can be relied upon to improve PM10 and PM2.5 emission estimates for external and internal combustion sources. A comprehensive PM test method evaluation program, co-sponsored by the New York State Energy Research and Development Authority (NYSERDA), the U.S. DOE, the California Energy Commission, GE EERC, Gas Research Institute, and American Petroleum Institute (API), yielded significant findings regarding the representativeness of PM test methods and emission factors. This program was conducted between 2000 and 2004 under the technical management of Glenn C. England of GE EERC. The focus of the testing program was the assessment of the performance of the DS method 4 Compilation of Air Pollutant Emission Factors, Volume I: Stationary Point and Area Sources, AP-42, Fifth Ed., U.S. EPA, Research Triangle Park, NC, January 1995 (July 1998 updates for gas-fired external combustion sources and April 2000 updates for stationary combustion turbines) PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 5 of 12 and the EPA TMs. The DS method results were used to characterize emission rates and chemical speciation profiles for PM2.5 and gaseous precursors for a variety of common oil- and gas-fired combustion sources. This research culminated in the publication of a series of technical, topical reports in 2004 entitled: Development of Fine Particulate Emission Factors and Speciation Profiles for Oil- and Gas-Fired Combustion Systems. These reports included the results of testing studies conducted separately by the API for external combustion units ("NYSERDA/API studies"). Versions of the DS method have been used for more than 40 years to collect emission samples from various source types. It was adopted as the regulatory standard method for determination of PM emissions from mobile sources, including heavy-duty diesel engines. Dilution sampling typically involves extracting a sample from the stack or flue, diluting it with purified ambient air or pure compressed gases, and then obtaining samples with ambient air collection and analysis methods. Because the sample is cooled to ambient temperatures, aerosol formation conditions approximately simulate those in actual exhaust plumes and test results are therefore more directly comparable to ambient air measurement results than are those from standard EPA test methods (e.g., EPA TM 5 and TM 202). In general, the DS method test results from the NYSERDA/API studies indicated that substantially all of the PM in the stack was smaller than 2.5 micrometers; these results were generally well below the MDL of the EPA method. The in-stack PM2.5 MDL achieved with the DS method are far lower than can be achieved by traditional EPA test methods due to avoidance of biases and greater analytical sensitivity; therefore, the DS method can detect and report the actual emissions, showing that they are far lower than the total PM measured by the traditional EPA methods. The NYSERDA/API studies results for natural gas-fired boilers and heaters (external combustion units) and turbines (internal combustion units) are summarized in Table 2. The NYSERDA/API studies results for refinery fuel gas-fired external and internal combustion units (which are expected to have more sulfur-based emissions than natural gas-fired units) are summarized in Table 3. Clearly these data provide support for the expectation that actual PM emissions from natural gas and fuel gas (with sulfur) combustion can be expected to be well below that estimated with AP-42 emission factors. The duration of each test run for all test methods was six hours to help ensure the collection of sufficient PM mass to allow a more precise analysis. A comparison of the total PM2.5 emission rates between external combustion units in Tables 2 and 3 shows that, on average, although the DS method results are similar for both natural gas- and refinery fuel gas-fired units, the EPA TM indicates that the total PM2.5 emission rate for refinery fuel gas-fired units is approximately six times higher than that for natural gas-fired units. This difference is most likely due the higher sulfur content of the refinery fuel gas, which led to PM artifact formation due to SO2 conversion to sulfates in the TM 202 impinger solution. Also, note that the maximum PM2.5 emission rate is associated with the unit - Site A - firing the refinery fuel gas with the highest H2S content, where H2S is used as an indicator of fuel S content. Finally, note that purging of the TM 202 impinger liquid (with either nitrogen or air to remove SO2 dissolved in solution) was not conducted for the tests on the refinery fuel gas-fired units. PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 6 of 12 Table 2. PM Emission Test Results for Natural Gas-Fired Combustion Units from the NYSERDA/API Studies5,6 Combustion Category Unit Type Test Site ID Unit Size (MMBtu/hr) Unit Load (%) EPA Test Methodsa Dilution Sampling Method - Total PM2.5 (lb/MMBtu Filterable PM2.5 (lb/MMBtu) Filterable PM10 (lb/MMBtu) Condensable PMb (lb/MMBtu) Total PM2.5 (lb/MMBtu) Total PM10 (lb/MMBtu) External Boiler Cc 62.5 70 0.000068 0.000077 0.0012 0.0013 0.0013 0.000056 Deltad 65 28-39 NM NM NM NM NM 0.00053 Heater (w/SCR) Charliee 300 95-100 0.000055 0.00010 0.0010 0.0011 0.0011 0.00016 External Combustion Unit Testing Average: 0.000062 0.000089 0.0011 0.0012 0.0012 0.00025 Internal Turbine (w/SCR) Bravof NA 85-100 0.00009 0.00029 0.0030 0.0031 0.0033 0.00024 Echog NA 59-100 NM NM NM NM NM 0.00013 Internal Combustion Unit Testing Average: 0.00009 0.00029 0.0030 0.0031 0.0033 0.00019 Notes: NM = No Measurement; NA = Not Available a EPA Conditional Test Method 040 for filterable PM and Test Method 202 for condensable PM, except that each test run was for 6 hours instead of the TM standard of one hour b All condensable PM is smaller than PM2.5 c Site C boiler is retrofitted with flue gas recirculation; otherwise, it has no add-on emissions control equipment d Site Delta boiler has no add-on emissions control equipment e The heater at Site Charlie is equipped with a selective catalytic reduction (SCR) system, which was on for all tests f Site Bravo is a combined cycle facility with one combustion turbine and one HRSG with duct burners (on for test nos. 1, 2, and 3 [part time] and off for test no.4). The total generating capacity of the facility is 240 MW. The unit is equipped with a lean pre-mix combustion system, SCR system, and oxidation catalyst, which were in operation during all tests. g Site Echo is a combined cycle facility with two combustion turbines and one HRSG with duct burners (off for all test runs). The total baseload capacity of the facility is 512 MW. The unit is equipped with an SCR system and oxidation catalyst, which were in operation during all tests. 5 Final NYSERDA studies for sites Bravo, Charlie, Delta, and Echo are available on NYSERDA website: http://www.nyserda.ny.gov/Publications/Research-and-Development-Technical-Reports/Environmental-Reports/EMEP-Publications/EMEP-Final-Reports.aspx 6 Final API study for Site C: Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum Industry Combustion Sources, Publication No. 4712, American Petroleum Institute: Washington, DC, 2001 PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 7 of 12 Table 3. PM Emission Test Results for Refinery Fuel Gas-Fired Combustion Units from the NYSERDA/API Studies7,8 Combustion Category Unit Type Test Site ID Unit Size (MMBtu/hr) Unit Load (%) Fuel Sulfur Content (ppmv H2S) EPA Test Methodsa Dilution Sampling Method - Total PM2.5 (lb/MMBtu) Filterable PM2.5 (lb/MMBtu) Filterable PM10 (lb/MMBtu) Condensable PMb (lb/MMBtu) Total PM2.5 (lb/MMBtu) Total PM10 (lb/MMBtu) External Boiler Ac 650 57 42 0.000025 0.000025 0.0097 0.0097 0.0097 0.00036 Heater Alphad 184.9 85-91 2.8e 0.00043 0.00060 0.0079 0.0083 0.0085 0.000052 Bf 114 44 7.7 0.00022 0.00064 0.0046 0.0048 0.0052 0.000054 External Combustion Unit Testing Average: 0.00023 0.00042 0.0075 0.0077 0.0079 0.00020 Internal Turbine (w/SCR) Golfg NA 99 28 NM NM NM NM NM 0.00029 Notes: NA = Not Available; NM = No Measurement a EPA Conditional Test Method 040 for filterable PM and Test Method 202 for condensable PM, except that each test run was for 6 hours instead of the TM standard of one hour b All condensable PM is smaller than PM2.5 c Site A boiler has no add-on emissions control equipment. d Site Alpha consists of a two heaters - a 78.9 MMBtu/hr unit and a 106 MMBtu/hr unit - that vent to a common stack with no add-on emissions control equipment. e Gas sample analyses also noted an average of 65.4 ppmv of unidentified S compounds for the test runs f Site B heater has no add-on emissions control equipment. g Site Golf is a cogeneration facility with one combustion turbine and one HRSG with duct burners (on for all test runs). The rated capacity of the facility is 48 MW. The unit is equipped with an SCR system and oxidation catalyst, which were in operation during all tests. 7 Final NYSERDA studies for sites Alpha and Golf are available on NYSERDA website: http://www.nyserda.ny.gov/Publications/Research-and-Development-Technical-Reports/Environmental-Reports/EMEP-Publications/EMEP-Final-Reports.aspx 8 Final API studies for sites A and B: Characterization of Fine Particulate Emission Factors and Speciation Profiles from Stationary Petroleum Industry Combustion Sources, Publication Nos. 4703 and 4704, American Petroleum Institute: Washington, DC, 2001 PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 8 of 12 Alternate PM Emission Factors for Regulatory Assessment and Permitting The following provides examples of specific uses of alternate PM emissions factors for emission inventories, regulatory assessments, and permitting. 2002 National Emissions Inventory In August 2005, EPA stated that they intended to revise the PM emissions from gas combustion in the final version of the 2002 National Emissions Inventory (NEI)9. The reason for the adjustment was that EPA believed that the current AP-42 emission factors for condensable PM emissions were too high. The EPA based their emission factor adjustments on the NYSERDA/API studies results for gas-fired external and internal combustion units; however, specific information on the assumptions and methodology used in developing these adjustments is not available. Emission factor adjustments were made to a broad range of gas-fired combustion units, including external combustion boilers used for electric generation, industrial purposes, and commercial/institutional purposes; internal combustion engines used for electric generation, industrial purposes, and commercial/institutional purposes; and industrial processes used in the petroleum industry, oil and gas production industry, and for in-process fuel use. At the request of the Region 5 states, EPA developed and made available in 2010 a comprehensive spreadsheet of revised PM/PM10/PM2.5 emission factors for the various combustion units firing gas, including natural gas and refinery fuel gas. The subset of emission factors for external combustion units and combustion turbines is shown in Table 4. These emission factors apply to the firing of either natural gas or refinery fuel gas. Note that the revised filterable PM and PM10 emission factors are equivalent and nearly double the revised filterable PM2.5 emission factor. Table 4. Revised EPA PM Emission Factors for the 2002 NEI10 Source Type PM Emission Component Emission Factors % Reduction from AP-42 Factor Revised 2002 NEI AP-42 (lb/MMft3) (lb/MMBtu)a (lb/MMBtu) External Combustion Units Filterable PM2.5 0.11 0.00011 0.0019 94 Filterable PM10 0.2 0.0002 0.0019 89 Condensable PM 0.32 0.00031 0.0056 94 Combustion Turbines Filterable PM2.5 0.11 0.00011 0.0019 94 Filterable PM10 0.2 0.0002 0.0019 89 Condensable PM 0.32 0.00031 0.0047 93 a Converted from lb/MMft3 to lb/MMBtu assuming a natural gas heat content of 1,020 Btu/ft3; a similar conversion for refinery fuel gas, which generally has a higher heat content than natural gas, would yield slightly lower lb/MMBtu emission factors 9 ftp://ftp.epa.gov/EmisInventory/2002finalnei/documentation/point/pm_adjustment_2002_nei.pdf, accessed on February 26, 2013. 10 ftp://ftp.epa.gov/EmisInventory/2002finalnei/documentation/point/pm_adjustment_2002_nei.pdf: ratios_to_adjust_pmvalues_in_nei_for_naturalgas_combustion082005.xls, accessed on February 26, 2013. PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 9 of 12 Federal Regional Haze Rule An additional example of use of the EPA-adjusted emission factors in assessing compliance with air quality regulations was demonstrated by the Western Regional Air Partnership (WRAP) in its Federal Regional Haze Rule evaluation analyses11. The WRAP, formed in 1997, is a voluntary organization of western states, native tribes, and federal agencies. The WRAP Stationary Sources Joint Forum used the EPA-adjusted emission factors in the development of baseline and future (2018) PM10 and PM2.5 emissions inventories for assessing impacts and evaluating emission control strategies pertaining to regional haze within its extensive geographic domain. These assessments were used by WRAP states in support of their regional haze State Implementation Plans, which were submitted to and approved by EPA in the 2007-2012 timeframe. Permitting of Combustion Units At least two permit applicants have used alternate PM emission factors based on the NYSERDA/API studies results as the basis for the PM2.5 emissions calculations in their permit application, which included modeling to assess compliance with the PM2.5 NAAQS. These two projects are located in different states - North Dakota and New Mexico. North Dakota In November 2012, a permit application was submitted to the North Dakota Department of Health (NDDH) for a proposed combustion turbine in Morton County, North Dakota. This application showed that the application emission estimates were based on EPA's rationale in developing the total (filterable plus condensable) PM2.5 emission rate for the proposed combustion turbine12. In particular, for estimating condensable PM emissions, the application took into account the EPA-adjusted emission factor, while allowing for the uncertainty/variation typical of stack test results based on EPA test methods. Based on this approach, a condensable PM emission factor was assumed to equal 50% of the AP-42 emission factor (i.e., 0.00235 lb/MMBtu). For filterable PM emissions, the application relied on the manufacturer's guarantee that was provided for the turbine. In February 2013, on this basis, the NDDH issued the construction permit for the combustion turbine project. New Mexico In 2010, a permit application was submitted to the New Mexico Environment Department Air Quality Bureau (NMED-AQB) for the construction of a natural gas-fired simple cycle combustion turbine equipped with SCR. The application used an alternative emission factor for total PM of 0.0040 lb/MMBtu based on an analysis of available test data for the appropriate class of turbines13 including the NYSERDA/API studies results. The filterable and condensable components of this emission factor 11 WRAP Point and Area Source Emissions Projections for the 2018 Base Case Inventory, Version 1, prepared by Eastern Research Group, Inc., Sacramento, California, for the Western Governors' Association and the Western Regional Air Partnership, Stationary Sources Joint Forum, January 2006. 12 Application for a PSD Permit to Construct a Simple Cycle Combustion Turbine, November 2012 (updated). 13 Air Quality Permit Application, Dona Ana County, New Mexico, June 2010. PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 10 of 12 used were 0.0012 and 0.0028 lb/MMBtu, respectively. The available test data were carefully screened, with the focus placed on tests with extended sampling run times where no contamination issues were noted. In June 2011, the NMED-AQB issued the construction permit, stipulating the 0.0040 lb/MMBtu emission rate for the new combustion turbine. Summary and Concluding Remarks Table 5 summarizes all the emission factors for natural gas-fired combustion sources discussed in this paper, including the current AP-42 emission factors for comparison. Additional testing using EPA's latest methods and interim guidance would be helpful in developing more representative emission factors for combustion of sulfur containing fuel gas. It is technically reasonable to rely on the NYSERDA/API studies results as the most representative emission estimate basis to justify the development and use of alternate PM emission factors, especially for condensable PM. These alternate emission factors should be used to develop PM10 and PM2.5 emission rates for a permit applicant's low-sulfur fuel gas- or natural gas-fired combustion units, especially for the purposes of NAAQS compliance assessment. There is precedent for using the NYSERDA/API studies data to justify the use of alternate emission factors, which are lower than AP-42 factors or vendor guarantees. Such factors have received regulatory approval as part of the permitting of projects in at least two states. In addition, governmental organizations, guided by the NYSERDA/API studies results, have relied on alternate PM emission factors for their own regulatory assessments. Both regulators and non-regulators alike recognize that the AP-42 emission factors are not representative of actual PM emissions from combustion units. The use of alternate PM emission factors will only grow over time, driven by the restrictive PM2.5 NAAQS and more detailed accounting of PM2.5 emissions now required for NAAQS compliance demonstrations and other regulatory assessments. In developing an alternate PM emission factor, it is important for permit applicants to provide total PM10 and PM2.5 emission rates in the application that demonstrate compliance with NAAQS, as well as an emission limit for which compliance can be reasonably demonstrated with standard EPA test methods using extended test run durations and other issued guidance. In the early stages of permit application development for combustion units, applicants should carefully analyze and consider available PM stack test results for similar units under similar duties, vendor data, and research study (e.g., NYSERDA/API) results. Finally, after permit issuance, construction and start of operation, it is very important that combustion unit PM10 and PM2.5 performance tests (especially Method 202) be conducted very carefully, avoiding as best as possible, contamination in sample collection, processing, and analysis. Such performance tests should be conducted using extended sampling periods to help assure collection of an adequate sample amount that can be measured more precisely. Also, EPA's April 2014 interim guidance for the treatment of condensable PM results should be applied in the processing of Method 202 measurements to increase the representativeness of resulting emission factors. PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 11 of 12 Table 5. Summary of PM Emission Factors for Natural Gas-Fired Combustion Units Discussed in this Paper Unit Type PM Emission Component Emission Factors (lb/MMBtu) NYSERDA/API Studies EPA 2002 NEI AP-42 North Dakota New Mexico Natural Gas-Firing RFG-Firing DS Method EPA TMs DS Method EPA TMs External Combustion Unit (Boiler or Heater) Filterable PM2.5 - 0.000062 - 0.00023 0.00011 0.0019 - - Filterable PM10 - 0.000089 - 0.00042 0.0002 0.0019 - - Condensable PMa - 0.0011 - 0.0075 0.00031 0.0056 - - Total PM2.5 0.00025 0.0012 0.00020 0.0077 0.00041 0.0075 - - Total PM10 - 0.0012 - 0.0079 0.00051 0.0075 - - Combustion Turbine Filterable PM2.5 - 0.00009 - - 0.00011 0.0019 0.0051b 0.0012 Filterable PM10 - 0.00029 - - 0.0002 0.0019 0.0051b 0.0012 Condensable PMa - 0.0030 - - 0.00031 0.0047 0.0023 0.0028 Total PM2.5 0.00019 0.0031 0.00029 - 0.00041 0.0066 0.0074 0.0040 Total PM10 - 0.0033 - - 0.00051 0.0066 0.0074 0.0040 Notes: RFG = Refinery Fuel Gas; DS = Dilution Sampling; TM = Test Method; NEI = National Emissions Inventory a All condensable PM is smaller than PM2.5 b Filterable PM for the North Dakota project was based on manufacturer's guarantee, not on testing results analysis PM Emission Factors: Past, Present and Future Presented at the AFRC 2014 Industrial Combustion Symposium Karen Olson and Louis Corio, Zephyr Environmental Corporation Zephyr AFRC - Page 12 of 12 Appendix: History of PM Measurement The history of PM measurement methods begins in 1971 with promulgation of EPA TM 5, following on the heels of promulgation of the TSP NAAQS earlier that same year. In 1978, EPA promulgated TM 17 as an alternative method for measuring PM, where the stack gas PM concentration is known to be independent of temperature. Both TMs 5 and 17 rely on a filter media to capture PM for emissions quantification, thus measuring filterable PM. With the promulgation of the PM10 NAAQS in 1987, a new method was needed to quantify PM10 emissions specifically because TMs 5 and 17 provided a PM measurement that included all size fractions. Therefore, in April 1990, EPA promulgated TM 201/201A as the stack test method for filterable PM10. (See 40 CFR Part 51, Appendix M.) EPA recognized that condensable PM emissions can be a significant fraction of the actual total PM10 emissions from combustion sources that needed to be measured. As a result, in December 1991, EPA promulgated TM 202. (See 40 CFR Part 51, Appendix M.) TM 202 is typically used in conjunction with TM 5 or TM 201A to measure total (filterable plus condensable) PM. The TM 202 apparatus actually is the "back half" of the TM 5 or 201A sampling equipment "train." In the originally-promulgated version of TM 202, exhaust gases were bubbled through water-filled impingers, with the solution being analyzed in a laboratory to quantify the organic and inorganic PM fractions. (Typically, for combustion sources, the inorganic fraction predominates, with sulfates comprising most of this fraction.) However, numerous studies conducted both inside and outside EPA indicated that non-condensable gases (e.g., SO2) could react in the water solution to form condensable PM (sulfates) that would not have otherwise formed in the stack. The formation of this sulfate artifact or "pseudo-particulate" resulted in elevated TM 202 stack test results. The promulgation of the PM2.5 NAAQS in 1997 and revised, more restrictive PM2.5 NAAQS in 2006 provided increased impetus to improve stack gas PM measurement methods for the smaller size fraction. As a result, in December 2010, EPA promulgated revised versions of TMs 201A and 202. Changes to TM 201A involved mainly hardware, most notably adding a PM2.5 cyclone and a PM2.5 filter after the PM10 cyclone to enable the measurement of filterable PM2.5 in addition to filterable PM10. TM 202 was modified to incorporate a condenser and "dry impinger" set-up in the back-half of the sampling train. Also, TM 202 sample recovery and processing procedures were revised, mainly to incorporate existing procedures in the TM that had been optional. The revised version of EPA TM 202 ensures consistency of method application and is intended to improve measurement precision by reducing sulfate artifact (or pseudo-particulate) formation. In fact, EPA research studies showed that these revisions to TM 202 would reduce sulfate artifact formation by at least 90% (75 FR 80118). On April 8, 2014, EPA issued interim guidance allowing permit applicants to use field train proof blanks in lieu of field train recovery blanks and to use blank values as high as 5.1 mg in the processing of TM 202 condensable PM measurements.