development of fine particulate emission factors … · development of fine particulate emission...

DEVELOPMENT OF FINE PARTICULATE EMISSION

FACTORS AND SPECIATION PROFILES FOR

OIL- AND - GAS-FIRED COMBUSTION SYSTEMS

Guide to PM2.5 Mass Emission Factors Stack Test Support Data

Prepared for: American Petroleum Institute

Washington, D.C.

Prepared by: ENVIRON International Corporation

Irvine, California

Date: December 20, 2012 (Revision 1.1)

Project Number: 04-24298F


Contents i ENVIRON

Contents

Page

1 Introduction 1

1.1 Background 3

1.2 Guide to Document 6

2 Dilution Sampler Equipment and Instrumentation 8

2.1 Instrumentation 11

2.1.1 Raw Stack Gas Sample Flow Rate 11

2.1.2 Bypass Blower Flow Rate 12

2.1.3 Dilution Air Flow Rate 13

2.1.4 Data Acquisition System Instrumentation 13

2.1.5 Sample Media Flow Rates 14

2.1.6 Sample Moisture Content 16

2.1.7 Stack Gas Flow Rate 17

3 Test Procedures 18

4 Calculations 19

4.1 Detailed Calculations 20

4.1.1 Nomenclature 20

4.1.2 Ambient Air Water Vapor Fraction (Bw,amb) 22

4.1.3 Diluted Sample Water Vapor Fraction (Bw,rtc) 22

4.1.4 Stack Gas Water Vapor Fraction (Bws) 22

4.1.5 Dry stack Gas Flow Rate (Qsd) 22

4.1.6 Raw (undiluted) sample venturi flow rate at actual temperature and pressure (Qsv) 22

4.1.7 Raw (Undiluted) sample venturi flow rate at standard temperature and pressure (Qsvs) 22

4.1.8 Raw (Undiluted sample venturi flow rate at standard temperature and pressure, dry (Qsvsd) 22

4.1.9 Blower bypass (diluted sample) flow rate at actual temperature and pressure (Qbb) 22

4.1.10 Sample Media Flow Rate and Volume 22

4.1.11 Dilution Ratio and Dilution Factor (Dry) 23

4.1.12 PM2.5 Concentration in Diluted Sample (Dry) 23

4.1.13 PM2.5 Concentration in Stack Gas (Dry) 23

4.1.14 PM2.5 Mass Emission Rate 23

4.1.15 Fuel Firing (Gross Heat Input) Rate 23

4.1.16 PM2.5 Mass Emission Factor 23

5 Guide to Supporting Data in Report Appendices 24

5.1 Sites A, B and C 24

5.2 Sites Alpha to Golf 25


Contents i ENVIRON

Contents

Page

List of Tables

Table 1-1: Gas-Fired Combustion Source Testing Project Reports. 1

Table 1-2: Summary of average field test results using dilution and hot filter/iced impinger

methods and AP-42 PM emission factors for gas-fired boilers, process heaters

and spark-ignited reciprocating engines (lb/MMBtu). 5

Table 2-1: Dilution Sampling Equipment Used for Each Gas-Fired Test. 10

Table 2-2: Beta DAS Instrumentation. 13

Table 2-3: Alpha DAS Instrumentation. 14

List of Figures

Figure 1-1: DRI (top) and compact (bottom) dilution samplers used in the test program. 9

Figure 2-1: Example of sample collection media instrumentation configuration

(with DRI sampler, Site Echo). 15

Figure 4-1: Overall calculation scheme for determining in-stack PM2.5 concentrations

and emission factors. 19

Figure 5-1: Example of data logger field data file (‘Raw Data - Run x’ worksheet,

tunnelflows spreadsheet). 26

Figure 5-2: Example of post-test sample venturi and bypass blower (motor) calculations

(‘Raw Data - Run x’ worksheet, tunnelflows spreadsheet). 26

Figure 5-3: Example of post-test dilution sampler test run data calculations

(‘Run-x’ worksheet, tunnelflows spreadsheet). 27

Figure 5-4: Example of sample media and bypass flow rate field data entry and volume

calculations (‘Run-x’ worksheet, tunnelflows spreadsheet). 27

Figure 5-5: Example of dilution sampler operational summary

(‘Summary’ worksheet, tunnelflows spreadsheet). 28

Figure 5-6: Example of dilution sampler, stack gas and fuel input data for emissions

calculations (‘Input_data’ worksheet, metals_oxides_PM spreadsheet). 29

Figure 5-7: Example PM2.5 laboratory detection limits, sample analysis results and

analytical uncertainty input for samples and blanks

(‘conc_dl’ worksheet, metals_oxides_PM spreadsheet). 29

Figure 5-8: Examples of in-stack PM2.5 concentration intermediate and final calculations

(‘conc_dl’ worksheet, metals_oxides_PM spreadsheet). 30

Figure 5-9: Example of PM2.5 mass emission rate and emission factor calculations

(‘emrate’ worksheet, metals_oxides_PM spreadsheet). 31

Figure 5-10: Example calculations of concentration and emission factor uncertainties

(metals_oxides_PM spreadsheet). 32

List of Appendices

Appendix A: Nomenclature Cross-Reference


Contents ii ENVIRON

Appendix B: Background Document - Proposed Revision to Ap-42 Emission Factors for

Estimating Pm 2.5 Emissions from Gas-Fired Combustion Units

P:\A\API\0424298F_PM2.5_EmissionFactors\Technical\Roadmap\API PM2.5 Roadmap_R1.1_121220.docx


Introduction 1 ENVIRON

1 Introduction

New emission factors for particles with aerodynamic diameter of 2.5 micrometers and smaller (PM2.5) from gas-fired combustion sources were developed based on results of a multi-year test program employing a new, dilution test methodology for PM2.5 measurements. This document summarizes the test program and emission factor development, and provides additional test details to support evaluation of emission factor quality.

The new emission factors justify revision of emission factors for gas-fired combustion sources currently published by U.S. EPA in its AP-42 Compilation of Air Pollutant Emission Factors (in Sections 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). An emission factor Background Document detailing the proposed emission factor revisions and changes to AP-42 sections is provided in Appendix B of this document.

The multi-sponsor collaborative industry-government testing program and results leading to the new emission factors was documented in a series of reports (Table 1-1). Several of these can be found online at either of two agency websites; the remaining reports may be obtained through the American Petroleum Institute. The reports contain details of the individual source tests including process descriptions, operating conditions, sampling and analytical procedures, test results and data analysis. The final report of this program includes an overview of the results, emission factors and other aspects of the tests. In addition, the key project results were subsequently published in two peer-reviewed journal publications1,2..

Table 1-1: Gas-Fired Combustion Source Testing Project Reports.

Report Title Reference

Gas-Fired Boiler – Test Report Site A: Characterization of Fine

Particulate Emission Factors and Speciation Profiles from Stationary

Petroleum Industry Combustion Sources, 2001.

Publication No. 4703. American

Petroleum Institute, Washington,

D.C.

Gas-Fired Heater – Test Report Site B: Characterization of Fine

Particulate Emission Factors and Speciation Profiles from Stationary

Petroleum Industry Combustion Sources, 2001.



D.C.

Gas-Fired Steam Generator – Test Report Site C: Characterization

of Fine Particulate Emission Factors and Speciation Profiles from

Stationary Petroleum Industry Combustion Sources, 2001.



D.C.

PM2.5, PM2.5 Precursor and Hazardous Air Pollutant Emissions

from Natural Gas-Fired Reciprocating Engines – Final Report

Unpublished, American


D.C.

1

England, G.C., J.G. Watson, J.C. Chow, B. Zielinska, M-C. O. Chang, K. Loos, and G.M. Hidy. Dilution-Based Emissions Sampling from Stationary Sources: Part 1. Compact Sampler, Methodology and Performance, J. Air & Waste Manage. Assoc., 57:65-78. 2007.

2 England, G.C., J.G. Watson, J.C. Chow, B. Zielinska, M-C. O. Chang, K. Loos, and G.M. Hidy. Dilution-Based Emissions Sampling from Stationary Sources: Part 2. Gas-fired Combustors Compared with Other Fuel-fired Systems, J. Air & Waste Manage. Assoc., 57:79-93. 2007.



Table 1-1: Gas-Fired Combustion Source Testing Project 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), 2003.

http://www.nyserda.ny.gov/Public

ations/Research-and-

Development/Environmental/EME

P-Publications/EMEP-Final-

Reports.aspx?sc_database=web,

accessed September 17, 2012.

http://www.energy.ca.gov/pier/proj

ect_reports/CEC-500-2005-

032_to_44.html, accessed

September 17, 2012.



Test Results for A Combined Cycle Power Plant with Supplementary

Firing, Oxidation Catalyst, and SCR at Site Bravo, 2004.



Test Results for a Gas-Fired Process Heater with Selective Catalytic

Reduction (Site Charlie), 2004.



Test Results for Dual Fuel-Fired Commercial Boiler at Site Delta,

2004.



Test Results for a Combined Cycle Power Plant with Oxidation

Catalyst and SCR at Site Echo, 2004.



Test Results for a Cogeneration Plant with Supplementary Firing,

Oxidation Catalyst, and SCR at Site Golf, 2004.


Profiles for Oil and Gas-fired Combustion Systems, Final Report,

2004,

Each of the test reports listed in Table 1-1 generally includes the following elements:

Executive Summary

Project Description

Process Description

Test Procedures

Test Results

Emission Factors and Speciation Profiles

Quality Assurance

Discussion and Findings

In addition, a series of Appendices for these reports was prepared containing detailed test data and other information supporting the results presented in each report. In particular, additional details regarding the test equipment not provided in the Test Procedures sections of the reports is provided, and detailed field and laboratory results, calculations, calibration information and quality assurance results are provided.

http://www.energy.ca.gov/pier/project_reports/CEC-500-2005-032_to_44.html





This document is intended to complement the Appendices. The program and key test results are briefly summarized in the following Background section. The remainder of this document is directed primarily to reviewers of these Appendices as a guide to the specific equipment, procedures, and results supporting PM2.5 emissions results for each test.

1.1 Background

In 1997 a national ambient air quality standard (NAAQS) was established for fine particulate matter - particles with aerodynamic diameter of 2.5 micrometers and smaller (PM 2.5). The standards were implemented by U.S. EPA in 2007, and the PM2.5 NAAQS levels recently revised in a December 2012 rule. 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.

The adoption of the PM 2.5 NAAQS makes it essential to have accurate estimates of PM 2.5 emissions to identify major sources and facilitate the development and implementation of effective and 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 Energy and Environmental Research Corporation (EER) and later by GE EER after EER was acquired by General Electric Company.

The results of this program show that the current AP-42 emission factors significantly overestimate PM 2.5 emissions for these sources. The overestimate is attributed primarily to positive bias in condensable emissions measurements using iced impinger test methods, and to a lesser degree by the sensitivity of the sampling and gravimetric analysis procedures. Filterable PM concentrations, although small relative to condensable PM concentrations, are the sum of net filter weights plus one or more acetone rinses to recover particles deposited on the surfaces of the sampling equipment. For levels in gas-fired sources, typically net filter weights are less than zero because of unrecovered filter fragments, and the acetone rinse residue weights after drying are indistinguishable from acetone rinse sample train blanks3. Thus, the true filterable PM concentration is often biased by these measurement limitations.

Condensable emission rates used in AP-42 were determined by EPA Method 2024 which bubbles the filtered stack gas sample through water in iced impingers to rapidly cool the stack gas sample without any dilution. Consequently the sample air environment where the stack gas components react and condense leads to higher saturation ratios (and consequently greater condensation) for condensable constituents in the Method 202 apparatus compared to the actual stack gas plume as it mixes in the atmosphere. This method also is known to be subject to positive bias by partially converting non-condensable gases such as SO2 and volatile organic compounds into residues such as sulfate in the impinger solutions which are then

3

Sample train blanks are complete sample trains that are set up and recovered in the same manager as samples, but not exposed to stack gas. These are more representative of overall background levels associated with the entire test method than acetone recovery rinse solvent blanks and others usually specified in the methods.

4 U.S. Environmental Protection Agency, Fed. Regist. 1991, 56, 65433.



indistinguishable from true condensable particulate matter5,6. While the amount of bias is small for many types of sources, test results show it is very large relative to the low PM concentrations found in gas-fired sources7. Recent tests comparing samples and blanks using EPA’s new version of Method 2028 – the “dry impinger” method - on a natural gas-fired gas turbine combined cycle plant show that samples and sample train blanks are statistically similar even when best practices are applied9,10. This illustrates that there remains a need for improved accuracy, sensitivity, and precision for measurements at the true concentrations of particulate matter from gas-fired sources.

A dilution sampling methodology was developed to measure PM emissions. The dilution method dilutes and cools the sample air by diluting the sample with filtered ambient air. The dilution sampling system provides measurement conditions that simulate atmospheric conditions where condensation might occur. This method provides more representative measurements of primary filterable plus condensable PM (measured together on the same filter) from gas-fired combustion units. The EPA recognized the value of dilution methods and developed Conditional Test Method (CTM) 39, based on dilution sampling, as a more accurate means of measuring stationary source PM10 and PM2.5 emissions. Dilution methods also are the internationally accepted standard for measuring particulate emissions from mobile sources.

Further, by appropriate selection of filter media and sampling/analytical equipment and procedures, problems associated with fragmentation of fiber filters can be eliminated and an order of magnitude increase in gravimetric sensitivity can be gained. This greatly increases the overall precision and sensitivity of dilution methods compared with traditional hot filter methods.

In several of the tests supporting the proposed emission factors, acetone rinses of equipment components were performed but the results were neglected since they were not significantly different from blanks. Further, variation of both acetone rinse samples and blanks was very large compared to the means, indicating a more random than systematic nature to the results, so subtraction of the acetone blank from acetone sample results was not considered valid. Therefore, the rinse results were not included in reported dilution sampler results. Laboratory tests of a similar dilution sampling apparatus showed that deposits of 1.3 to 2.5 micrometer diameter particles on the walls of the apparatus were minor, 7 to 21% of total mass, and decreased with decreasing particle size. All but 2-3% of the deposit mass was found in portions of the sampler in contact with the raw sample11. Researchers have characterized the size

5 Corio, L.A. and Sherwell, J., In-stack Condensable Particulate Matter Measurements and Issues, J. Air & Waste

Manage. Assoc., 50, 207-218, 2012. 6

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.

7 Wien, S.E., G.C. England, K.R. Loos, K. Ritter. 2001. Investigation of Artifacts in Condensable Particulate

Measurements for Stationary Combustion Sources. Paper #536. Air and Waste Management Association, 94th Annual Conference and Exhibition, Orlando, Florida, June 2001.

8 \ U.S. Environmental Protection Agency, Methods for Measurement of Filterable PM10 and PM2.5 and Measurement of Condensable PM Emissions From Stationary Sources, Fed. Regist. 2010, 75 (244), 80118-80172.

9 \ Brooks, J., G.C. England, J. Hogan, T.Ponder. 2012. Evaluation of New PM10/PM2.5 Emission Test Methods for NGCC Power Plants, Paper #2012-A-457-AWMA, Air and Waste Management Association, 105th Annual Conference and Exhibition, San Antonio, Texas, June 2012.

10 Haywood, J.M., R. Kagolanu, B. Mahew, K. Liang. 2012. Revised USEPA Particulate Matter Testing Methodology Evaluated on a Gas Turbine, Air and Waste Management Association, 105th Annual Conference and Exhibition, San Antonio, Texas, June 2012.

11 Hildemann, L.M., G.R. Cass, and G.R. Markowski. 1989. A dilution stack sampler for organic aerosol emissions: Design, characterization, and field tests. Aerosol Sci. and Technol. 10:193-204.



distribution of PM2.5 from gas combustion using dilution samplers and laser scattering-scanning mobility particle sizers and found all the particles to be smaller than 1 micrometer12. AP-42 states that all PM emissions from gas-fired combustion units are assumed to be PM 2.5 because there is no mineral matter or refining residue in natural gas to form solid “fly ash” particles, and the particles result from nucleation of soot, trace fuel sulfur, and combustion products to form primarily submicron aerosols. Thus, particle deposits on dilution sampling equipment surfaces is expected to account for a very minor if not negligible fraction of the total PM2.5 emissions and eliminating or neglecting acetone rinse results improves rather than detracts from the quality of the test results.

The joint industry-government testing program collected data from several gas-fired combustion units using both the dilution tunnel sampling system method and traditional hot filter/iced impinger test methods, in an effort to establish more representative PM 2.5 emission rates. The test program results (Table 1-2) show that PM emission factors derived from hot filter/iced impinger tests of external combustion sources are 40 times higher, on average, than those derived from dilution tunnel tests. The difference is attributed to condensable PM emissions measurements. Filterable PM2.5 as measured by the hot filter method (PRE-004) and total PM2.5 (filterable PM plus condensable PM) as measured by dilution tunnel are very similar on average. Because of the aforementioned limitations associated with iced impinger methods for condensable PM, the dilution tunnel tests are believed to be representative of actual emissions. The difference in results for the dilution and hot filter/iced impinger methods for reciprocating internal combustion engines is less dramatic, 1.4 times higher on average for the 4-stroke engines, but still indicates a significant positive bias in emission factors derived from the hot filter/iced impinger method.

Table 1-2: Summary of average field test results using dilution and hot filter/iced impinger methods and AP-42 PM emission factors for gas-fired boilers, process heaters and spark-ignited reciprocating engines (lb/MMBtu).

Test ID

Dilution Tunnel

Total PM2.5

b

Method PRE-004 a /202 (hot filter/iced impingers)

Filterable PM2.5

Condensable PM

Total PM2.5 Condensable

(% of Total PM2.5)

External Combustion

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 c

n/a 0.002 0.006 0.007 75

12

Klippel, N., M. Kasper, K. Bengtsson. “Gas Turbines: Sources or Sinks for Atmospheric Aerosols?,” 6th

International ETH Conference on Nanoparticle Measurement, Zurich, Switzerland, August 19-20, 2002.



Table 1-2: Summary of average field test results using dilution and hot filter/iced impinger methods and AP-42 PM emission factors for gas-fired boilers, process heaters and spark-ignited reciprocating engines (lb/MMBtu).

Test ID

Dilution Tunnel

Total PM2.5

b

Method PRE-004 a /202 (hot filter/iced impingers)

Filterable PM2.5

Condensable PM

Total PM2.5 Condensable

(% of Total PM2.5)

Internal Combustion – Reciprocating Engines (Stationary)

2SLB+PCC

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 d

0.0034 0.0003 0.0043 0.0048 90%

AP-42: 2SLB c

n/a 0.0384 0.00991e

0.0483 21%

AP-42: 4SLB c

n/a 0.0000771 0.00991 0.00999 99%

AP-42: 4SRB+PCCc

n/a 0.0095 0.00991e

0.0195 51%

AP-42: Average c

n/a 0.0160 0.00991 0.0259 38%

a EPA Method PRE-004 is the predecessor to EPA Method 201A as published in December, 2010.

b Dilution tunnel measures filterable and condensable PM2.5 together on the same filter.

c AP-42 factors are for PM10. PM10 and PM2.5 are assumed equal for gas-fired combustion sources.

d Dilution tunnel test average does not include 2SLB data. Average with 2SLB is 0.0089.

e Based on emission factor for 4SLB engines.

2SLB = 2-stroke lean burn; 4SLB = 4-stroke lean burn; 4SRB = 4-stroke rich burn; PCC = precombustion

chamber; NSCR = non-selective catalytic reduction; n/a = not applicable.

These results support the need to revise the AP-42 PM emission factors for gas-fired combustion units. API proposes to revise AP-42 by eliminating 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 (including condensable) PM. The revisions would apply to gas-fired external combustion units, liquefied petroleum combustion units, gas-fired stationary gas turbines, and gas-fired reciprocating engines.

1.2 Guide to Document

The purpose of this document is to guide the review of detailed test appendices for data relative to PM2.5 mass emission factors to support the evaluation of emission factor quality. A companion report (Appendix B) presents background information on the testing program that supports the needed changes to the AP-42 emission factors for gas-fired combustion units.

Dilution tunnel tests were conducted on a number of different sources from 1998 to 2003 for the purposes of characterizing PM2.5 emissions and developing emission factors for gas-fired stationary sources. The results are documented in a series of published research test reports (Table 1-1). The unpublished detailed appendices for these reports (Table 1-2) include both mass and chemically speciated data collected using a variety of different sample collection and analysis methods. This results in a very large appendix for each report that can be difficult to



navigate easily. The chemically-speciated data are not relevant to PM2.5 mass emission factors and in some cases have been omitted to simplify reviews. This document provides a guide to these appendices indicating where the specific data supporting PM2.5 emission factors may be found.

Details of calculations used to convert primary measurement results to in-stack concentrations and emission factors have not been previously reported. A description of the equipment used throughout the program and associated calculations are discussed.

This document is organized as follows:

Section 1: Introduction. Summarizes the test program, key issues and emission factors.

Section 2: Dilution Sampler Equipment and Instrumentation. This section provides details regarding the dilution sampling equipment to supplement the overall description provided in the “Test Procedures” section of the test reports.

Section 3: Test Procedures. This brief section contains notes regarding procedures to supplement information provided in the “Test Procedures” section of the test reports.

Section 4: Calculations. This section explains calculations used to relate dilution sampler instrumentation, laboratory data, and calibration data to determine test results.

Section 5: Guide to Supporting Data in Report Appendices. This section provides a guide to the test report appendices noting changes in format and content as the test program evolved. Examples of key spreadsheets are provided so that they are more easily recognized in the appendices.


Dilution Sampler Equipment and Instrumentation 8 ENVIRON

2 Dilution Sampler Equipment and Instrumentation

The test equipment and approach used for the test program are based on a design developed by researchers at California Institute of Technology (CalTech) in the 1980’s and later used extensively by researchers at CalTech, Desert Research Institute (DRI) and others throughout the 1990’s and 2000’s during development and reassessment of the National Ambient Air Quality Standards for PM2.5. The EPA Office of Research and Development also constructed and used similar equipment for research studies. The widespread acceptance of the design concept was a key reason for adoption in the API program.

Two different dilution sampling equipment designs were used, a DRI design developed prior to this test program and a compact design developed during this program (Figure 1):

Two different DRI dilution samplers of identical design were used:

A sampler owned by DRI was used for Sites A, B, C and Alpha (Also referred to as the Beta

sampler in test documentation);

An identical sampler owned by Colorado State University (CSU) was used for Sites Bravo,

Charlie, Delta and Echo (referred to as the Alpha sampler in test documentation);

The compact sampler was used for Sites Echo, Golf and the three RICE tests (Also referred to as the Beta13 sampler in tests at Site Echo).

Conceptually, both of the dilution sampler designs are very similar. A stack gas is extracted continuously at a measured flow rate, mixed with filtered ambient air, and the diluted samples aged. The sample probe was equipped with a buttonhook nozzle with the opening facing into the sample flow (opposite of the flow direction). The nozzle diameter was selected to provide approximately isokinetic sample extraction; however, because isokinetic sample extraction has negligible impact on particles PM2.5 and smaller, isokinetic sampling was only a secondary consideration in establishing the test setup. Aging the diluted sample is one of the distinguishing characteristics of this design, to promote nucleation and condensation of dilute species such as trace organic compounds for “fingerprinting” source species profiles. A high volume blower located between the dilution mixer and aging (residence time) chamber provided the motive force for inducing sample and dilution air flows. The diluted sample flow through the high volume blower exhausted to atmosphere to maximize bulk mean gas residence time in the aging chamber. The diluted and aged stack gas sample passed through an internal sharp-cutoff PM2.5 cyclone (Bendix design) and was distributed to sample collection media and/or analyzers. An in-stack PM2.5 cyclone was added to the compact sampler probe to remove particles larger than 2.5 μm from the raw (undiluted) sample prior to dilution.

The compact sampler was optimized based on development testing to reduce physical size by more rapid mixing of the sample and dilution air, decrease residence time for sample aging and lower diluted sample flow rate for sample collection. Key differences between the DRI and compact sampler are raw sample-dilution air mixing rate (the DRI design uses a cross-flow jet and long mixing tube arrangement, whereas the compact sampler uses a multiple parallel jet

13

The naming of dilution samplers was unfortunately confusing with respect to test site names and naming of dilution sampler sample venturis and bypass blowers (motors) in test documentation. While this may be confusing to the reader and test reviewer, the author has attempted to make the distinctions clear throughout this document.



and short mixing tube arrangement) and sample aging residence time after dilution (approximately 80 seconds for DRI design, 10 seconds for compact sampler). It should be noted that the equipment, instrumentation, and procedures evolved over the course of the program and thus also did data reduction calculations presented in a later section of this summary.

Figure 1-1. DRI (top) and compact (bottom) dilution samplers used in the test

program.

Sample collection media used during the tests included various filters and sorbents. The diluted and size-classified sample gas flow rate through the filter or sorbent media was measured using mass flow meters and/or rotameters to determine the volume of gas that passed through the media during the test run (described later). A wide range particle size spectrometer and/or laser

DilutionAir Inlet

HEPA Filter

ActivatedCharcoal FilterW/Glass Wool

Back-up

Hi-VolPump

& FlowSensor

O18" x 6'Residence Chamber

80 Sec Res Time@ 226 LPM

To Sampler(113 LPM)

To Sampler(113 LPM)

2.5µM Cyclones

Turbulent Dilution TunnelResidence Time 2.4 Sec @ 1200 LPM

Dilution Ratio 25X - 50XO6" x 9' Effective Length

Butt-Weld FerruleTig Weld Only

Heavy DutyClamp W/TFE Gasket

Heated Sample LineW/Temp Sensor

.50" x 2M Long SS

30 LPM Max20 LPM Min

Heated VenturiW/Temp Sensor

0 - 5 In-H2OMagnehelic Gage

Sample Port (Type)

Stack

Sample Inletand

TemperatureSensor

S TypePitot Tube

0 - 0.5 In-H2OPressure XDCR

Temp Controller



photometer with internal flow meters also was used in some tests. A portion of the diluted/aged sample was bypassed if necessary to maintain the target flow rate through the internal PM2.5 cyclone.

The specific test equipment and instrumentation used for each test varied somewhat depending on availability and as equipment and procedures evolved over the course of the program (Table 1). Most of the tests were performed without an in-stack PM2.5 cyclone, using only the internal PM2.5 cyclone after dilution for size classification. In later tests, an in-stack PM2.5 cyclone was added so that recovery rinses of the probe and dilution sampler could be attributed to the PM2.5 size fraction. Different raw sample venturis and high-volume blower with flow orifices of similar design were used depending on availability for a specific test. In later tests using the compact sampler, a dilution air venturi was added for direct measurement of dilution air flow rate.

Table 2-1: Dilution Sampling Equipment Used for Each Gas-Fired Test.

Site (test date)

Dilution Sampler ID

Sample Venturi

(calibration date

m/d/yy) HI-Vol Blower

Dilution Air

Venturi

DAS & pressure

transducer set

In-stack cyclone used?

A (July 1998) DRI (DRI)

LSI ½, s/n T-

304

(7/23/1999)

DRI n/a unknown No

B (October

1998) DRI (DRI)

LSI ½, s/n T-

304

(7/23/1999)

DRI n/a unknown No

C (October

1999) DRI (DRI)

“Covered

venturi” s/n

11920

(7/23/1999)

DRI

(11/3/2000) n/a unknown No

Alpha

(February

2001)

DRI (DRI)

“Covered

venturi” s/n

11920

(8/6/2003)

“Old DRI

motor” s/n

0080

(8/7/2003)

n/a Black No

Bravo

(September

2001)

DRI (CSU)

“Bare venturi”

s/n 11379

(8/11/2003)

“New CSU

motor” s/n

0465

(8/6/2003)

n/a Grey No

Charlie

(December

2001)

DRI (CSU)

“Bare venturi”

s/n 11379

(8/11/2003)

“New CSU

motor” s/n

0465

(8/6/2003)

n/a Grey No

Delta (March

2002) DRI (CSU)

“Covered

venturi” s/n

11920

(8/6/2003)

“New CSU

motor” s/n

0465

(8/6/2003)

n/a Grey No

Echo (May

2002) DRI (CSU)

“Covered

venturi” s/n

11920

(8/6/2003)

“New CSU

motor” s/n

0465

(8/6/2003)

n/a Black No



Table 2-1: Dilution Sampling Equipment Used for Each Gas-Fired Test.

Site (test date)

Dilution Sampler ID

Sample Venturi

(calibration date

m/d/yy) HI-Vol Blower

Dilution Air

Venturi

DAS & pressure

transducer set

In-stack cyclone used?

Echo (May

2002) Compact

“Bare venturi”

s/n 11379

(8/11/2003)

“Old DRI

motor” s/n

0080

(8/7/2003)

n/a Grey PM2.5

cyclone

Golf (October

2003) Compact

“Covered

venturi” s/n

11920

(8/6/2003)

“Old DRI

motor” s/n

0080

(8/7/2003)

“1.5”

venturi” Black

PM2.5

cyclone

RICE – 4SLB

Caterpillar

(November

2003)

Compact

“Covered

venturi” s/n

11920

(8/6/2003)

“Old DRI

motor” s/n

0080

(8/7/2003)

“1.5”

venturi” Black

PM2.5

cyclone

RICE – 4SRB

Ingersoll

Rand

(November

2003)

Compact

“Covered

venturi” s/n

11920

(8/6/2003)

“Old DRI

motor” s/n

0080

(8/7/2003)

“1.5”

venturi” Black

PM2.5

cyclone

RICE – 2S

Cooper

(October

2003

Compact

“Covered

venturi” s/n

11920

(8/6/2003)

“Old DRI

motor” s/n

0080

(8/7/2003)

“1.5”

venturi” Black

PM2.5

cyclone

n/a – not applicable

2.1 Instrumentation

The systems employed a combination of instrumentation, electronic data logging, and manually-logged data to determine key sample collection parameters. The instrumentation and configuration varied as the test procedures and equipment evolved over the course of the program. The key parameters measured to calculate in-stack PM2.5 concentration (dry basis) and mass flow rate are:

Raw (undiluted) sample gas flow rate;

Bypass blower gas flow rate;

Dilution air gas flow rate (compact sampler only);

Sample media flow rates;

Sample moisture content;

Stack gas flow rate.

Each of the above is discussed in the following subsections.

2.1.1 Raw Stack Gas Sample Flow Rate

The raw (undiluted) stack gas sample volumetric flow rate was measured using a heated and thermally insulated venturi. To determine flow rate, the differential pressure across the venturi throat and the temperature and absolute static pressure of the gas at the venturi inlet are



required. Three different sample venturis of similar make and model (Lamba Scientific Inc. 1/2-inch throat diameter, stainless steel) were used over the duration of the project (see Table 1).

The differential pressure across the sample venturi was continuously measured with an electronic differential pressure transducer, the electrical output of which was converted to engineering units and recorded electronically using a data logger. Each pressure transducer and data logger set were calibrated as a unit against an inclined oil manometer reference and a correction factor was applied to the recorded data in final calculations to convert recorded to actual pressure drop.

The temperature of the gas at the sample venturi inlet was continuously measured indirectly via a thermocouple placed on the exterior of the probe under a layer of insulation near the probe connection to the venturi inlet. Heat transfer calculations showed that gas and probe wall temperature should be the same for probes of at least 5 feet in length. Sample probes were longer than about 5 feet in all tests and thus the gas temperature was assumed to be equal to the probe wall temperature at the exit of the probe. The thermocouple output was connected to an electronic data logger.

The sample venturi inlet gas static pressure was determined from preliminary test measurements based on barometric pressure measured using an electronic or aneroid barometer and stack gas static pressure measured with an S-type Pitot tube (in the null position) and an inclined oil manometer. The static pressure data were manually recorded and entered into data reduction spreadsheets. The pressure drop through the in-stack cyclones, when used, and probe upstream of the venturi was determined to be small relative to total pressure, and so was neglected for purposes of gas density calculations.

A two-parameter curve fit for actual volumetric flow rate as a function of differential pressure was used to represent the venturi calibration. Measured temperature and pressure were used to correct measured flow rate to standard temperature (20 ˚C) and pressure (760 mm Hg). The sample venturi calibration constants for each venturi used in final calculations were determined from laboratory calibrations against a calibrated flow measurement device (secondary calibration standard). The sample venturi calibrations for Sites A, B, C, and Alpha were performed by DRI at their facility using a Roots positive displacement flow meter as the secondary calibration standard. The sample venturi calibration for all the remaining sites was performed by GE EER at their facility using a dry gas meter as the secondary calibration standard.

2.1.2 Bypass Blower Flow Rate

The diluted sample flow rate through the bypass high volume blower was used in dilution factor calculations except for tests using the compact sampler at Site Golf and the three reciprocating engines. The blower housing exit serves as a calibrated flow orifice. The differential pressure between the inlet to the blower exit orifice and ambient air was determined using an electronic pressure transducer, the electrical output of which was converted to engineering units and recorded electronically using a data logger. Each set of pressure transducers and data logger were calibrated as a unit against an inclined oil manometer reference and a correction factor was applied to raw data logger results to convert recorded values to actual pressure drop.

Gas temperature at the orifice inlet was measured using a thermocouple placed in the gas flow at the inlet to the exit orifice. Gas pressure at the orifice inlet was determined by summing



barometric pressure (measured manually with an electronic or aneroid barometer before the test) and the differential pressure across the orifice.

Throughout the tests, one of at least three different high volume blowers (General Metal Works B/M 2000H, TE-5005 and TE-5070) with different calibration constants was used. In the documentation and final spreadsheets, the latter two are variously identified in the test documentation as “Old,” “DRI,” “Beta” for one motor and “New,” “CSU,” “Alpha” for the other. These designations should not be confused with site code names (Site Alpha) or sampler names (at Site Echo, Alpha for DRI sampler, Beta for compact sampler) given in the test reports. Documentation for the blower(s) used at Sites A and B was not available.

Each blower was calibrated against either a calibrated venturi or a calibrated orifice as the secondary calibration standard. A two-parameter curve fit was used to represent the blower calibration. High- and low-range (above and below 0.33 inches of water differential pressure) calibration constants were determined for Sites Alpha to Golf.

2.1.3 Dilution Air Flow Rate

In the DRI dilution sampler design, the dilution air flow rate was not measured.

In the compact sampler design, a venturi (Lamda Scientific Inc., 1.6-inch throat diameter, stainless steel with ball valve) was added to directly measure dilution air flow rate for the tests at Site Golf and the three reciprocating internal combustion engine tests (Cooper, Ingersoll-Rand, and Caterpillar). The differential pressure across the sample venturi was continuously measured with an electronic differential pressure transducer, the electrical output of which was recorded electronically using a data logger. The data logger was set up to convert raw electrical signals to engineering units (inches of water). Each pressure transducer and data logger were calibrated as a unit against an inclined oil manometer and a correction factor was applied to raw data logger results to convert recorded to actual pressure drop.

The dilution air venturi was calibrated by the manufacturer. Tests were performed within 12 months of the venturi’s first use, so recalibration during the program was unnecessary. A two-parameter curve fit was used to represent the venturi calibration in calculations.

2.1.4 Data Acquisition System Instrumentation

Separate data acquisition systems and instrumentation sets were used for the CSU (Alpha) and DRI (Beta) DRI design dilution samplers.

Table 2-2: Beta DAS Instrumentation.

Process ID Equipment Description

Manufacturer/Model Operating Range

(Units) Accuracy

Output Signal

BTC1 Stack

Thermocouple Omega, KQXL-18G-6 -328 to 2282 (F)

1%

Reading

4-20

mA

BTC2 Sample Venturi


1%

Reading

4-20

mA

BTC3 Motor


1%

Reading

4-20

mA

BTC4

Residence

Chamber

Thermocouple

Omega, KQXL-18G-6 -328 to 2282 (F) 1%

Reading

4-20

mA

BTC5 Ambient Omega, KQXL-18G-6 -328 to 2282 (F) 1% 4-20



Table 2-2: Beta DAS Instrumentation.



(Units) Accuracy

Output Signal

Thermocouple Reading mA

BH1

Residence

Chamber

Relative

Humidity

Omega, HX94V 3 - 90 (% RH) 2% FS 0-1

VDC

BH2 Ambient Relative

Humidity Omega, HX94V 3 - 90 (% RH) 2% FS

0-1

VDC

BP1 Stack Pressure

Transducer PX653-10D5V 0-10 (in H2O) 0.25% FS

0-5

VDC

BP2

Sample Venturi

Pressure

Transducer

PX653-03D5V 0-3 (in H2O) 0.25% FS 0-5

VDC

BP3 Motor Pressure


0-5

VDC

Table 2-3: Alpha DAS Instrumentation.



(Units) Accuracy

Output Signal

ATC1 Stack


1%

Reading

4-20

mA

ATC2 Mixing Chamber


1%

Reading

4-20

mA

ATC3 Post Mixing


1%

Reading

4-20

mA

ATC4 Motor


1%

Reading

4-20

mA

ATC5 Ambient


1%

Reading

4-20

mA

ATC6

Residence

Chamber

Thermocouple

AH1

Residence

Chamber

Relative

Humidity

Omega, HX94V 3 - 90 (% RH) 2% FS 0-1

VDC

AH2 Ambient Relative

Humidity Omega, HX94V 3 - 90 (% RH) 2% FS

0-1

VDC

AP1 Stack Pressure


0-5

VDC

AP2

Sample Venturi

Pressure

Transducer

PX653-03D5V 0-3 (in H2O) 0.25% FS 0-5

VDC

AP3 Motor Pressure


0-5

VDC

2.1.5 Sample Media Flow Rates

After dilution and aging, the diluted sample passed through an internal PM2.5 cyclone and was distributed to the various sample collection media (Figure 1).



Figure 2-1. Example of sample collection media instrumentation configuration (with

DRI sampler, Site Echo).

The total flow rate through the sample media and media bypass was used with the raw sample flow rate and bypass flow rate to calculate dilution factor and in-stack PM2.5 concentrations when dilution air was not directly measured.

To achieve the target internal PM2.5 cyclone cutoff diameter, total flow rate through the cyclone was maintained at the target flow rate (225 L/min) by bypassing any excess flow not consumed by the sample collection media channels, if necessary. Sample flow rates through the media and bypass were measured with rotameters and/or thermal mass flow meters, depending on the



number of channels and instrumentation available at the time of each test. All flow meters were factory-calibrated for air. Because dilution ratios generally exceeded 10:1 (in all but the initial test at Site A, dilution ratio was approximately 20:1 or higher), calibration deviation due to combustion gas composition was considered negligible.

In the DRI dilution sampler design, two (or in one test, three) identical PM2.5 cyclones at the exit of the aging chamber supplied the range of sample collection media. In most tests, one of these channels was devoted to the Polyurethane Foam (PUF) sampler (see Figure 2.1) which required a higher flow rate than the others. In tests when the PUF sampler was not used, the flow through one of the cyclones was bypassed to maintain constant flow through the aging chamber from test to test.

In tests at Sites A, B, C and Alpha, flow control valves for the filter and sorbent media channels and the bypass were preset to the desired flow rate using a precision Dwyer rotameter before each run and verified after completion of the run. The average of the pre- and post-test rates was used with the sampling duration to calculate flow rates. These data were manually logged by DRI (documentation was not included in DRI’s electronic test reports).

At Sites Bravo, Charlie, Delta, Echo, Golf and the three RICE tests, flow rates for filter and sorbent media channels, bypass and multiple-orifice uniform deposit impactor (MOUDI) were measured during test runs using rotameters or thermal mass flow meters (TSI, Inc.) installed between the sample media and the flow control valve. Data were manually logged at intervals during test runs. Rotameter data were corrected to standard temperature and pressure based on ambient air temperature and vacuum pump pressure (vacuum). The thermal mass flow meters were internally compensated for temperature and no correction for pressure was required. Vacuum pressure at each vacuum pump was measured with a dial gage and recorded manually.

Canister sample flow rates were maintained at a constant rate during test runs with a Tisch 3-channel electronic flow controller. Sample volumes were determined from pre- and post-test canister pressures measured by a dial gage attached to the canister inlet. Pressures were manually logged on DRI’s sample custody sheets.

When used, flow rates through instrumental analyzers (DustTrak, WRPS) were determined from the analyzer’s internal instrumentation. The instrumentation was factory calibrated. Data were recorded by the analyzer’s internal data loggers.

2.1.6 Sample Moisture Content

PM2.5 concentration in the raw and diluted stack gases is reported on a dry gas volume basis. To correct measured wet sample gas volumes to dry, sample moisture content was determined by either of two methods:

Relative humidity and temperature of the diluted sample and ambient air, measured by sensors in the aging chamber and ambient air with use of standard psychrometric lookup tables. This method was generally used to correct diluted sample media volumes to dry conditions and to calculate dry dilution factors; or

EPA Method 4 (condensation in iced impingers & gravimetric analysis, usually included as part of other test methods) measurements made concurrently with the dilution sampler tests. This method was generally used to correct measured stack gas volumes to dry conditions.



The measured relative humidity and temperature of the diluted sample were used to correct the diluted sample media volumes to dry basis. In most tests, stack gas moisture measurements determined using both methods were available. Results were compared for quality assurance purposes. Because the moisture contributions to the diluted sample from the stack gas sample and ambient air were often of similar magnitude, EPA Method 4 measurements were considered more accurate and used in final calculations of in-stack moisture content and pollutant concentrations when a significant discrepancy between the two methods was observed.

2.1.7 Stack Gas Flow Rate

PM2.5 mass emission rate was determined from PM2.5 concentration and stack gas flow rate measurements. In these tests, samples were collected at a single point within the stack to facilitate comparison of different PM2.5 test methods (sample probes for different test methods approximately co-located). Therefore, a complete velocity traverse before and after each test run was performed and results used to calculate mass emission rates. Velocity at the sampling point also was measured continuously during the test to detect unplanned changes in process operating conditions. In some tests, the average of the single point velocity measurement and the average pre- and post-test velocity profiles were used to calculate stack gas flow rate.


Test Procedures 18 ENVIRON

3 Test Procedures

The overall test approach is described in the main test reports. A few additional details pertinent to calculations are described here.

Based on preliminary velocity traverse results, a nozzle diameter was selected for the buttonhook nozzle and PM2.5 cyclone to provide approximately isokinetic sample extraction.

After setting up the equipment, making preliminary measurements, entering site data (date, time, stack gas static pressure, barometric pressure, etc.) into the data logger and inserting the probe into the stack, the test run was initiated by first starting the high volume blower and adjusting the blower speed and dilution air control valve until the desired raw sample flow rate (nominally 20-25 liters per minute) and dilution ratio were achieved. Once stabilized, the actual test run was started by starting the data logger, turning on the pump(s) for the sample collection media, adjusting the sample media flow rates (except when control valves were pre-adjusted as noted earlier) and making minor adjustments to the dilution air bypass flow rate to achieve the target operating conditions.

Dilution sampler operating conditions were recorded by an electronic data logger. For tests at Sites A, B and C, DRI recorded all manually logged dilution sampler data (start/stop times, pre-/post-test sample media flow settings, barometric pressure, etc.). These records were not included in electronic test data summaries provided by DRI for those sites and hence are unavailable. For the remaining tests, logs of key operating parameters were recorded manually on forms at intervals during the test both to collect data not recorded electronically (e.g., sample media flow rates) and to provide a backup of electronic data in the event of a data logging error. The manual logs for these sites are included in Appendices.


Calculations 19 ENVIRON

4 Calculations

The samplers used in the API program bypassed a portion of the diluted sample upstream of the sample collection media, thus it is necessary to apply a dilution factor to PM2.5 mass concentrations measured in the diluted sample to determine in-stack PM2.5 mass concentrations. The overall calculation approach is illustrated in Figure 2.

Figure 4-1. Overall calculation scheme for determining in-stack PM2.5 concentrations and emission factors.

First, the PM2.5 concentration in the diluted sample was determined by dividing the net filter mass by the volume of gas drawn through the filter. The volume of gas drawn through the filter was calculated using the measured gas flow rate through the filter and the duration of the test run. This PM2.5 concentration was then multiplied by a dilution factor to calculate PM2.5 concentration in the wet stack gas. The relative humidity and temperature of the diluted sample were used to calculate stack gas moisture content and PM2.5 concentration in the dry stack gas. To calculate PM2.5 emission factors, the PM2.5 mass flow rate was calculated using the in-stack PM2.5 concentration and dry stack gas flow rate, and then dividing this by the measured fuel chemical heat input (product of measured fuel flow rate and gross (higher) heating value).

The flow rate in engineering units was calculated from measured data via a calibration regression formula (with coefficients derived from venturi calibration).

The dilution factor was calculated using one of two approaches:

In the DRI dilution sampler design, the dilution air flow rate was not measured. The dilution factor was determined from the diluted sample flow rate (sum of measured diluted sample volumetric flow rates through the bypass blower, sample collection media and sample media bypass) divided by raw stack gas sample volumetric flow rate;

In the compact sampler, a single venturi was used to measure dilution air flow at the inlet to the sampler. The dilution factor was determined from the sum of measured dilution air volumetric flow rate and raw stack gas sample volumetric flow rate, divided by the raw stack gas sample volumetric flow rate.

Mass of PM2.5

filter net weight

Diluted Sample

volume

sample flow rate

sampling time

PM2.5

Concentration

(diluted-dry)

mass/volume

water vapor fractionDilution Factor

(dry)

Stack sample volume

venturi dP

venturi T

stack static P

Barometric P

venturi calibration constants

Sampling duration

Diluted sample volume

(DRI)

blower dP

chamber T

Barometric P

blower calibration constants

Sample media flow rates

sampling time

Diluted Sample

Moisture

relative humidity

chamber temperature

In-stack PM2.5

concentration

concentration (dry)

dilution factor (dry)

Stack Gas Water Vapor

Impinger weight gain

sample volume

Dilution air volume

(Compact)

venturi dP

venturi T

barometric P

venturi calibration constants

Stack Gas Velocity

Pre- and Post-Test

Velocity Traverses

Avg. single point velocity

Molecular weight

O2, CO2, H2O

Stack Gas Flow

Rate (dry)

velocity

temperature

stack diameter PM2.5 Mass Emission

Rate

concentration (dry)

stack gas flow rate (dry)

Fuel Flow Rate

and Higher

Heating Value

heat input

PM2.5 Emission

Factor

mass/heat input

Stack Sample

Volume

(undiluted-dry)

concentration

water vapor fraction



4.1 Detailed Calculations

4.1.1 Nomenclature

Bw,amb = ambient air water vapor volume fraction

Bw,rtc = diluted sample water vapor volume fraction in residence time (aging) chamber

Bws = stack gas water vapor volume fraction

DR = dilution ratio

DRd = dilution ratio (dry)

DF = dilution factor

DFd = dilution factor (dry)

CPM2.5sd = PM2.5 mass concentration in stack gas, dry basis, mg/dscm

cPM2.5dd = PM2.5 concentration in diluted sample, dry basis, mg/dscm

dPbb = bypass blower orifice pressure drop (inches w.c.)

dPsv = dilution air venturi pressure drop (inches w.c.)

EFPM2.5 = PM2.5 mass emission factor, lb/MMBtu

GHV = fuel gas gross (higher) heating value, British thermal units (Btu) per cubic foot

K1 = sample venturi calibration constant (in test documentation, referred to as “A”)

K2 = sample venturi calibration constant (in test documentation, referred to as “B”)

K3 = bypass blower calibration constant (in documentation, referred to as “motor m” or “Mcal”)

K4 = bypass blower calibration constant (in documentation, referred to as “motor b” or “Bcal”)

MPM2.5 = PM2.5 mass emission rate in stack gas, lb/hr

mPM2.5 = PM2.5 mass on Teflon membrane filter, μg

Pbar = barometric (ambient) pressure, mm Hg

Ps = stack gas static pressure, in. w.c.

Psat,w,amb = saturated water vapor pressure at ambient air temperature, mm Hg

Psat,w,rtc = saturated water vapor pressure at diluted sample temperature in residence time (aging) chamber, mm Hg

Pstd = standard pressure, mm Hg = 760



Qbb = bypass blower flow rate at actual temperature and pressure, liters per minute

Qbbs = bypass blower flow rate at standard temperature and pressure, liters per minute

Qda,s = dilution air flow rate (dry) at standard temperature and pressure, liters per minute

Qf = Fuel volumetric flow rate at standard fuel temperature (60 ˚F) and pressure, cubic feet per hour

QH = fuel firing rate (gross heat input), million Btu per hour

Qi = volumetric diluted sample gas flow rate through ith sample media or bypass, liters per minute

Qid = volumetric diluted dry sample gas flow rate through ith sample media or bypass, liters per minute

Qsd = dry stack gas volumetric flow rate, dry standard cubic meters per hour

Qsmts = sum of all sample media and bypass flow rates determined from thermal mass flow meters and rotameters corrected to standard conditions, liters per minute

Qsr = indicated rotameter volumetric flow rate, milliliters per minute

Qsv = raw (undiluted) sample venturi flow rate at actual temperature and pressure, liters per minute

Qsvs = raw (undiluted) sample venturi flow rate at standard temperature and pressure, liters per minute

Qsvsd = dry raw (undiluted) sample venturi flow rate at standard temperature and pressure, liters per minute

QTMFd = volumetric flow rate of dry diluted sample gas through Teflon membrane filter, liters per minute

RHamb = ambient air relative humidity, %

RHrtc = diluted sample relative humidity in residence time (aging) chamber, %

Tamb = ambient air temperature, K

Tstd = standard temperature, K = 293.15

Tsv = sample venturi temperature (from temperature controller setpoint), K

Θ = run duration, minutes



4.1.2 Ambient Air Water Vapor Fraction (Bw,amb)

Bw,amb = Psat,w,amb/Pstd * RHamb/100

4.1.3 Diluted Sample Water Vapor Fraction (Bw,rtc)

Bw,rtc = Psat,w,rtc/Pstd * RHrtc/100

4.1.4 Stack Gas Water Vapor Fraction (Bws)

Stack gas water vapor was determined by direct measurement using EPA Method 4 (iced impingers and gravimetric analysis). EPA Method 4 calculations may be found in the test method.

4.1.5 Dry stack Gas Flow Rate (Qsd)

Dry stack gas flow rate was determined using EPA Methods 1, 2, 3A and 4, usually as part of measurements using EPA Method 201A/202. Refer to the methods for calculations.

4.1.6 Raw (undiluted) sample venturi flow rate at actual temperature and pressure (Qsv)

Qsv, liters per minute = K1 * EXP(K2*LOG(dPsv))

4.1.7 Raw (Undiluted) sample venturi flow rate at standard temperature and pressure (Qsvs)

Qsvs, liters per minute = Qsv * (Pbar + 1.87 * Ps)/Pstd * Tstd/Tsv

4.1.8 Raw (Undiluted sample venturi flow rate at standard temperature and pressure, dry (Qsvsd)

Qsvsd, liters per minute = Qsvs * (1-Bws)

4.1.9 Blower bypass (diluted sample) flow rate at actual temperature and pressure (Qbb)

Qbb = K3 * EXP(K4*LOG(dPbb)), in actual liters per minute

Qbbs = Qbb * 293.15/Tm * (Pbar + dPbb*25.4/13.6)/760

4.1.10 Sample Media Flow Rate and Volume

When rotameters were used for measurement of sample media flow rates, the following temperature and pressure corrections were applied to convert rotameter indicated flow to standard temperature and pressure.

Qsrs, liters per minute = Qsr/1000 * Pbar/Pstd * Tstd/Tamb

Because the rotameters were attached to sample media outlets via a length of uninsulated Teflon tubing and the sample gas was likely cooled to ambient conditions, ambient temperature was considered representative of gas temperature at the flow meter. The contributions of stack static pressure and pressure loss through the sampler were considered very small compared to total pressure and were neglected.

Thermal mass flow meters with display readout in liters per minute (calibrated for dry air) also were used for measurement of sample media flow rates. Thermal mass flow meter calibration



depends on the specific heat of the measured gas. The effect of water vapor, oxygen, carbon dioxide and nitrogen concentration deviations from dry air on specific heat of sample gases was determined to be very small over the range of dilution ratios used in this program (about 1 percent or less); therefore, no correction for specific heat was applied to measured flow rates at actual conditions. Measured thermal mass flow meter flow rates were corrected to dry basis based on relative humidity and temperature of the diluted sample as for Qsrsd above.

Measured volumetric flow rates in liters per minute (Qi) through the sample media and bypass were converted to dry basis (Qid) using diluted sample moisture volume fraction based on the relative humidity and temperature measured in the aging (residence time) chamber,

Qid, liters per minute = Qi * (1-Bw,rtc)

PM2.5 mass was collected on Teflon membrane filters. The volume of diluted sample gas passed through the filter during a test run was determined from the volumetric flow rate and duration of the test run,

VTMFd, dry standard cubic meters = QTMFd/1000 * θ

4.1.11 Dilution Ratio and Dilution Factor (Dry)

DRd = (Qbbs + Qsmts – Qsvs) *(1-Bw,amb)/Qsvsd

DFd = 1+DRd

4.1.12 PM2.5 Concentration in Diluted Sample (Dry)

cPM2.5d, mg/dscm = mPM2.5/(VTMFd)

4.1.13 PM2.5 Concentration in Stack Gas (Dry)

CPM2.5sd, mg/dscm = cPM2.5d * DFd

4.1.14 PM2.5 Mass Emission Rate

MPM2.5, lb/hr = CPM2.5sd / 453590 * Qsd

4.1.15 Fuel Firing (Gross Heat Input) Rate

QH = (Qf * GHV/1000000)

All facilities tested provided fuel flow rate information. At some sites, process data provided by the facility included fuel firing rate based on fuel flow and fuel heating value analysis. These data were used when available.

4.1.16 PM2.5 Mass Emission Factor

EFPM2.5, lb/MMBtu = MPM2.5/QH


Guide to Supporting Data in Report Appendices 24 ENVIRON

5 Guide to Supporting Data in Report Appendices

Supporting data and calculations for calculating PM2.5 emission factors in each test are provided in the corresponding appendices for each test report. The supporting data generally consists of:

Dilution sampler field data sheets with manually recorded data;

Dilution sampler electronically logged data (in spreadsheets);

Laboratory results providing dilution sampler Teflon membrane filter net weights

(in spreadsheet reports);

Emission calculation spreadsheets;

Calibration results for dilution sampler venturis and bypass blower orifices;

EPA Method 2 field data sheets and calculation spreadsheets;

EPA Method 4 water vapor field data sheets and calculation spreadsheets (generally as part

of other concurrent measurements employing EPA Method 4);

Process operating data for fuel flow rate and/or fuel heat input rate.

It should be noted that the tests were performed over a period spanning 5 years, and detailed appendices for Sites Alpha through Golf were not prepared until nearly 8 years after the first tests were completed and more than 5 years after the last test report was submitted. Some of the original supporting data not archived in project files were lost in the intervening periods. Further, GE EER relocated to a different facility during this period resulting in accidental loss of a small number of archival project files. While the overall documentation of the supporting data is very good and good quality practices are evident throughout, there remain a few minor gaps in some of the ancillary measurement data.

The objectives of the latter tests also were changed to provide more robust documentation for development of emission factors, quality assessment and associated uncertainty. These latter appendices are more complete in terms of traceability to primary measurements and field documentation. The presentation of dilution test supporting data is somewhat different for these two groups of tests reflecting adjustments in project objectives as the program evolved.

The nomenclature used in Section 4 of this document was selected for clarity in showing calculation formulas; however, this nomenclature differs from that shown in the spreadsheets shown in the appendices. Attachment 1 provides a nomenclature list with both conventions shown.

To assist the reviewer in reviewing the appendices to assess data quality, the following two sections discuss data presentation and location of key data in the appendices.

5.1 Sites A, B and C

Documentation related to dilution sampler PM2.5 emission factors consists of spreadsheet and other summary reports. Documentation of dilution sampler results is less comprehensive than in the later tests. Typical support data include:



Dilution tunnel operation summary, volumes and dilution ratios, derived from data logger files and calibration data.

Laboratory summary reports providing Teflon membrane filter net (final – tare) weights (i.e., PM2.5 mass) in spreadsheet format.

PM2.5 concentration summary, using dilution sampler data to convert PM2.5 filter mass to in-stack concentration equivalents;

PM2.5 lab results summary reports;

Dilution venturi calibration;

Uncertainty calculations.

Much of the field documentation (e.g., field logs, chain of custody forms, instrument calibrations other than sample venturi) was retained by DRI and was not available for these appendices. The documentation was generally consistent with project objectives as a screening phase to establish the feasibility and usefulness of the dilution method prior to embarking on a broader test program.

5.2 Sites Alpha to Golf

Data reduction for Sites Alpha to Golf was performed using the same set of Microsoft Excel spreadsheet templates. In each of these site report appendices, supporting data and calculations for PM2.5 emission factors are contained primarily in two spreadsheets, titled:

[site name]_tunnelflows_[date or version].xls (“tunnelflows spreadsheet”)

[site name]_metals_oxides_pm-[date or version].xls (“metals_oxides_PM spreadsheet”)

The tunnel flows spreadsheet includes electronically-recorded dilution sampler field data, run by run dilution sampler flow and dilution factor calculations and a summary of dilution sampler average results for each run. Figure 5-1 shows an example of the dilution sampler field data worksheet. Key data used in calculating dilution sampler flows and dilution factor are:

Tamb, ambient air temperature (Amb_Tmp, column F);

RHamb, ambient relative humidity (Amb_RH, column G);

Trtc, diluted sample temperature in the aging chamber (Chmbr_Temp, column H);

RHrtc, relative humidity of the diluted sample in the aging chamber (Chmbr_RH, column I);

Tbb, diluted sample temperature at the bypass blower (Mtr_Tmp, column N);

dPsv, raw sample venturi differential pressure (Vntri_dP, column R); and

dPbb, bypass blower orifice differential pressure (Motor_dP, column S).

The data logger recorded 1-minute average data which then were averaged over the duration of the test run in the worksheet. Sample venturi and bypass blower flow rates recorded by the data



logger shown in Figure 5-1 are for reference only, which may not reflect final pressure transducer and flow meter calibrations. Final flows were recalculated from the measured differential pressures and temperature data using final calibration results and averaged for each test run (Figure 5-2). Averaged data then were used with data from other measurements (stack gas moisture, barometric pressure, sample venturi temperature, stack gas static pressure, sample media and bypass flows) to calculate sample media and bypass volumes and dilution factors for each test run (Figures 5-3 and 5-4). A summary worksheet tabulates dilution sampler operating data and sample media volumes from all test runs and QA samples (Figure 5-5).

Figure 5-1. Example of data logger field data file (‘Raw Data - Run x’ worksheet, tunnelflows spreadsheet).

Figure 5-2. Example of post-test sample venturi and bypass blower (motor) calculations (‘Raw Data - Run x’ worksheet, tunnelflows spreadsheet).

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A B C D E F G H I J K L M N O P Q R S T U V

Confid

entialDate Time RunID Amb_Tmp Amb_RH

Chmbr_Tem

pChmbr_RH Stk_Tmp Up_Tmp

Down_Tem

p

Chmbr_Tmp

2Mtr_Tmp Spare

Panel_T

empPitot_dP Vntri_dP

Motor_d

P

Motor_lp

m

Venturi_l

pm

Mixing

Ratio

Units degC % degC % degC degC degC degC deg C deg C inH2O inH2O inH2O lpm lpm

Averages:

360 26.04 21.13 33.69 39.83 170.41 35.76 39.89 -999.00 48.12 0.00 32.23 0.04 1.30 0.25 341.15 26.64 25.13

Stdev 3.16 4.78 5.44 8.30 2.99 6.02 5.87 0.00 7.00 0.00 4.06 0.05 0.74 0.04 27.16 6.43 30.67

RSD 12.12 22.62 16.16 20.85 1.76 16.82 14.72 0.00 14.55 #DIV/0! 12.60 139.10 56.97 14.10 7.96 24.14 122.08

min.

118 340 1015 100 23.12 26.89 21.58 38.58 177.3 48.58 30.89 -999 37.92 0 24.7 0.033 0.948 0.177 283 23.38 20.77

118 340 1016 100 23.08 26.13 21.57 38.63 177.4 49.28 30.92 -999 38.09 0 24.73 0.033 0.969 0.14 247.1 23.58 19.3

118 340 1017 100 23.12 25.04 21.56 38.95 177.4 50.01 31.04 -999 38.44 0 24.75 0.033 1.619 0.025 92.7 30.71 9.32

118 340 1018 100 23.19 25.55 21.57 46.32 177.5 44.27 31.13 -999 39 0 24.78 0.033 1.628 0.196 289.1 30.76 16.08

118 340 1019 100 23.25 25.31 21.79 56.99 177.5 32.37 31.12 -999 39.38 0 24.82 0.034 1.389 0.268 349.9 28.46 19.23

118 340 1020 100 23.14 25.14 21.89 59.33 177.4 29.42 31.1 -999 39.59 0 24.85 0.038 1.347 0.247 336.2 28.01 19.07

118 340 1021 100 23.01 25.46 22.43 59.27 177.1 28.66 31.02 -999 39.8 0 24.87 0.033 1.29 0.285 361.5 27.35 20.61

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AE AF AG AH AI AJ AK AL AM AN

NEW Stack P Static (" H2O) -> -0.12 P Ambient = 766.60

NEW DAS = Beta Venturi = BetaMotor = Alpha

A = 20.5047 M (dP > 0.33) = 1.2116 B (dP > 0.33) = -0.081666

B = 0.49499 M (dP =< 0.33) = 0.94908 B (dP =< 0.33) = 0.031506

Average = 1.37 27.66 0.27 320.97

STDEV = 0.77 6.29 0.04 27.87

Motor dP Avg = 0.2704 0.031506 <- "Average" B

Alpha DAS

Venturi dP

Correction ("

H2O)

Beta DAS

Venturi dP

Correction ("

H2O)

Alpha DAS

Motor dP

Correction ("

H2O)

Beta DAS

Motor dP

Correction ("

H2O)

Venturi dP ("

H2O)

Venturi Flow

(lpm)

Motor dP (" H2O)

Motor Flow

(lpm)

0.991 0.977 0.196 0.192 0.977 24.05 0.1924 261.14

1.013 0.999 0.168 0.164 0.999 24.32 0.164 238.22

1.627 1.696 0.043 0.038 1.696 31.60 0.038 98.15

1.636 1.705 0.217 0.213 1.705 31.68 0.213 277.07

1.396 1.455 0.282 0.291 1.455 29.29 0.291 329.83

1.381 1.411 0.273 0.268 1.411 28.85 0.268 315.43

1.322 1.351 0.300 0.310 1.351 28.24 0.310 341.42



Figure 5-3. Example of post-test dilution sampler test run data calculations (‘Run-x’ worksheet, tunnelflows spreadsheet).

Figure 5-4. Example of sample media and bypass flow rate field data entry and volume calculations (‘Run-x’ worksheet, tunnelflows spreadsheet).

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A B C D E F G H I J K

Ambient T ( C ) *** Ambient T (K)Ambient P

(in Hg)

Ambient P

(torr) ****

Motor T (

C )

Motor T

(K)

Venturi T

( C ) *

Venturi T (

K )

Venturi dP

(inch H2O)

Motor dP

(inch H2O)

Stack Static P

(inch H2O)

26.04 299.2 30.18 766.60 48.12 321.3 150.00 423.2 1.37 0.27 -0.12

Avg. corrected probe flow from DAS (lpm) 27.66 ' = 'Raw Data - Run #'!AJ5

Actual Probe Flow (lpm) 27.66 ' = Avg. corrected probe flow from DAS (lpm) - Pressure correction now done in the Raw Data sheet.

Avg. probe flow (slpm) 19.31 ' = avg probe flow (lpm) * [Ambient P (mm Hg) + 1.87 * P Stack Static (inch H2O)]/760 * 293/Venturi T (K)

Av. Corrected Motor flow from DAS (lpm) 320.97 ' = 'Raw Data - Run #'!AL5

Actual Motor Flow (lpm) 320.97 ' = Av. Motor flow from DAS (lpm) - Pressure correction now done in the Raw Data sheet.

Avg. Motor flow (slpm) 295.27 ' = avg motor flow (lpm) * [Ambient P (mm Hg)]/760 * 293/Motor T (K)

Dilution ratio (wet) 31.83

Dilution Ratio + 1 (wet) 32.83

Ambient RH (%) 21.13 ' ='Raw Data - Run #'!G5

Ambient T (C) 26.04

Water Vapor Saturation P at Ambient T (mm Hg) 25.19 From relative_humidity worksheet.

Ambient Water Vapor P (mm Hg) 5.368 ' = Ambient P (mmHg)/ 760 (mmHg) * Ambient RH /100 * Water Saturation P at Ambient T (mmHg)

Ambient Water Vapor (vol fraction) 0.00700 ' = Ambient Water Vapor P (mmHg) /Ambient P (mmHg)

Stack Water Vapor (vol fraction) 0.1316 From Moisture and/or Manual Methods sample train(s) (Bws)

Chamber Water Vapor (volume fraction) -

calculated 0.01080

(Avg Motor Flow (slpm) +Total Sample Flow (slpm))

Chamber RH (%) 39.83 ' = 'Raw Data - Run #'!I5

Chamber T ( C ) 33.69 ' = 'Raw Data - Run #'H5

Water Vapor Saturation P at Chamber T (mm Hg) 39.08 From relative_humidity worksheet.

Chamber Water Vapor (volume fraction) -

"measured" 0.0205 ' = Water Vapor Saturation P at Chamber T (mm Hg)/760 * Chamber RH (%) / 100

Chamber Water Vapor: calculated/measured - QA

Check 0.53

Avg Probe Flow (dry slpm) 16.77 ' = Avg Probe Flow (slpm) * (1 - Stack water vapor)

Avg Dilution Air Flow (dry slpm) 610.49

Dilution Ratio (dry) 36.40 ' = Avg Dilution Air Flow (dry slpm) / Avg Probe flow (dry slpm)

Dilution Ratio + 1 (dry) 37.40 ' = Dilution Ratio + 1

* verify that venturi operating Temp was 150 C.

** flow corrected to standard conditions using chamber temperature. If Chamber temperature not recorded, correct using ambient temperature.

*** Ambient Temperature from data logger, make sure it is operational.

**** Ambient P in torr calculated from Ambient P in mm Hg.

' = (Avg Motor Flow (slpm) + Total Sample Flow (slpm) - Avg Probe Flow (slpm)) / Avg Probe Flow (slpm) - these

are wet flows

' = (Avg probe flow (slpm) * Stack Water Vapor (%) + (Avg Motor Flow (slpm) + Total Sample Flow (slpm) - Avg

Probe Flow (slpm))*Ambient Water Vapor (%))/

' = Chamber Water Vapor (volume fraction) - calculated / Chamber Water Vapor (volume fraction) - "measured"

[should be close to 1.0]

' = (Avg Motor Flow (slpm) + Total sample flow (slpm) - Avg Probe Flow (slpm)) * (1 - Ambient water vapor)

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A B C D E F G H I J K L M N O P Q R

Sample Clock Time

Elapsed

Sampling

Time

(min.)

PUF flow

(slpm)

Carbonyl

Flow

(mL/min)

Tenax A

(mL/min)

Tenax B

(mL/min)

Quartz/

citric acid

(slpm)

Teflon/

quartz (slpm)

Quartz/

K2CO3

filter pack

(slpm) MOUDI (lpm)

CEMS

(lpm)

X1?

(slpm)

X2?

(slpm)

Bypass

flow

(cfh)

Bypass

Vacuum

(inches

Hg)

Bypass

flow

(scfh)**

Sample Module Color Confidential X Y Z XX Clear Yellow Gray ZZ XYZ

DRI Sample Number XXX XXX XXX XXX XXX XXX XXX XXX XXX

GE EER Sample Number(s) YYY YYY YYY YYY YYY YYY YYY YYY YYY

4/3/2003 13:40 0 0 0 0 0 0 2 0.0

30 113.5 399 110 114 78.5 76.48 75.16 2

60 113.5 399 112 119 78.4 76.1 74.9 2

90 113.5 400 113 110 78.4 75.7 74.5 2

120 113.4 400 116 116 78.2 75.2 74.3 2

150 113.3 400 115 115 77.9 74.7 74 2

180 112.4 402 111 111 77.3 74.2 73.1 2

210 112.8 402 115 115 77.2 73.9 73.1 2

240 112.5 404 111 111 76.5 72.8 72.5 2

270 112.4 403 111 111 77 73 72.9 2

300 112.3 403 110 110 77.6 73.3 73.5 2

330 112.4 401 107 107 78.1 73.6 73.9 2

360 108.1 401 106 106 77.3 73.2 72.1 2

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2

2

2

2

2

Average Flow 112.51 401.17 111.42 112.08 77.70 74.35 73.66 0.00 0.00 0.00 0.00 0.00

Avg. Flow, Standard T, P 112.5 396.5 110.1 110.8 77.7 74.3 73.7 0.0 0.0 0.0 0.0 0.0

Flow Units slpm slpm slpm slpm slpm slpm slpm slpm slpm slpm slpm slpm

Total Sample Flow

(slpm)

Average Flow (slpm) 112.508 0.396 0.110 0.111 77.700 74.348 73.663 0.000 0.000 0.000 0.000 0.000 338.837

RSD 1.3 0.4 2.7 3.4 0.8 1.7 1.3

St Dev 1.5 1.6 3.1 3.8 0.6 1.3 1.0

Total Sample

Volume (scm)

Dry Sample Volume (dscm) 40.0657 0.1412 0.0392 0.0394 27.6700 26.4764 26.2325 0.0000 0.0000 0.0000 0.0000 0.0000 122.0



Figure 5-5. Example of dilution sampler operational summary (‘Summary’ worksheet, tunnelflows spreadsheet).

The metals_oxides_PM spreadsheet calculates in-stack PM2.5 concentrations, mass emission rates, emission factors, and related uncertainties for all test runs and associated QA samples (tunnel blanks, field blanks, ambient air runs). Only the PM2.5-related data contained in this spreadsheet will be discussed here.

The summary data table in the tunnelflows spreadsheet was copied to the ‘Input_data’ worksheet in the metals_oxides_PM spreadsheet (Figure 5-6). Stack gas flow rates and fuel heat input rate (or fuel flow rates and heating values) also are entered on this worksheet, from separate calculations on other spreadsheets. Laboratory analytical data for detection limits, net weights and analytical uncertainty were entered on the ‘conc_dl’ worksheet (Figure 5-7). The ‘conc_dl’ worksheet also includes intermediate and final calculations for in-stack PM2.5 concentrations (Figures 5-7 and 5-8).

Teflon membrane filter tare and final weights were always greater than detection limits. Because of the sensitivity of the analytical balance (1 microgram) and weighing procedures used for this program, Teflon membrane filter net (final minus tare) weights (=PM2.5 mass) were only occasionally below detection limits, e.g., if damage to the filter resulting in loss of material occurred. Results below detection limits were not included in calculating average concentrations, emission factors or uncertainties. Results below detection limits were treated as zero for calculating speciation profiles (not relevant for PM2.5 mass emission factors).

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Run ID Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-Amb Char-TB

Date 12/6/2001 12/7/2001 12/10/2001 12/11/2001 12/12/2001 12/5/2001

Sample Module Color Run 1 Run 2 Run 3 Run 4 Ambient TB

Avg Run 1 -

4

STDEV Run

1 - 4

RSD Run 1

- 4 (%)

Quartz/Citric Acid Volume (ions, OC/EC, NH3) (dscm) Clear 27.670 23.194 23.432 26.685 26.390 24.599 25.245 2.3 8.99

Quartz/K2CO3 Volume (SO2) (dscm) Gray 26.232 25.130 25.430 26.795 26.640 25.481 25.897 0.8 2.93

Teflon/Quartz Volume (mass, XRF) (dscm) Yellow 26.476 26.194 26.015 26.208 26.465 25.629 26.224 0.2 0.73

Dilution Ratio (wet) 31.83 34.64 29.24 28.90 NA 31.15 31.153 2.7 8.57

Dilution Ratio + 1 (wet) 32.83 35.64 30.24 29.90 NA 32.15 32.153 2.7 8.31

Dilution Ratio (dry) 36.40 39.58 33.24 32.97 NA 35.55 35.549 3.1 8.73

Dilution Ratio + 1 (dry) 37.40 40.58 34.24 33.97 NA 36.55 36.549 3.1 8.49

Avg Run 1 -

4

STDEV Run

1 - 4

RSD Run 1

- 4 (%)

PUF (SVOC) Volume (dscm) X 40.07 40.15 40.12 40.20 40.16 40.21 40.135 0.1 0.15

Carbonyl Volume (dscm) Y 0.1412 0.1397 0.1447 0.1424 0.1436 0.1445 0.1420 0.0 1.49

Tenax A Volume (dscm) Z 0.0392 0.0378 0.0394 0.0397 0.0392 0.0405 0.0390 0.0 2.08

Tenax B Volume (dscm) XX 0.0394 0.0395 0.0399 0.0401 0.0402 0.0410 0.0398 0.0 0.83

MOUDI Volume (dscm) YY 0.00 0.00 0.00 0.00 0.00 0.00 0.000 0.0 #DIV/0!

X1 Volume (dscm) ZZ 0.00 0.00 0.00 0.00 0.00 0.00 0.000 0.0 #DIV/0!

X2 Volume (dscm) XYZ 0.00 0.00 0.00 0.00 0.00 0.00 0.000 0.0 #DIV/0!



Figure 5-6. Example of dilution sampler, stack gas and fuel input data for emissions calculations (‘Input_data’ worksheet, metals_oxides_PM spreadsheet).

Figure 5-7. Example PM2.5 laboratory detection limits, sample analysis results and analytical uncertainty input for samples and blanks (‘conc_dl’ worksheet, metals_oxides_PM spreadsheet).

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A B C D E F G H I J

Test Site Name: Charlie

Test Site Location: Confidential

Test Series Name: Site Charlie

Source Description: Process Heater

Fuel(s) Fired During Testing: Natural Gas

Combustor Heat Rating: MMBtu

Project Manager: Stephanie Wien (949) 859-8851 ext 155

Spreadsheet data entry by: Tom McGrath (949) 859-8851 ext 154

Total Number of Samples/Test Runs 4

Sample

Module Color Run 1 Run 2 Run 3 Run 4 Tunnel Blank Field Blank Ambient

Run ID Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-DSB Char-FB Char-Amb Test-Runs-Avg

Date 12/6/2001 12/7/2001 12/10/2001 12/11/2001 12/5/2001 12/11/2001 12/12/2001

Q Volume (ions, OC/EC, NH3) (dscm) Clear 27.67 23.19 23.43 26.69 24.60 25.25 26.39 25.25

Q Volume (SO2) (dscm) Grey 26.23 25.13 25.43 26.80 25.48 25.90 26.64 25.90

T Volume (mass, XRF) (dscm) Yellow 26.48 26.19 26.02 26.21 25.63 26.22 26.65 26.22

T2 Volume (mass, metal speciation) (dscm) Green #DIV/0! #DIV/0!

Dilution Ratio (dry) 36.40 39.58 33.24 32.97 35.55 35.55 0.00 35.55

Dilution Ratio + 1 (dry) * 37.40 40.58 34.24 33.97 36.55 36.55 1.00 36.55

Dry stack flow (dscmh) 112,034 111,074 109,304 108,356 110,192

Heat input (MMBtu/hr) 299 293 289 284 291.27

Fuel HHV (Btu/lb) #DIV/0!

Fuel Flowrate (lb/hr)* #DIV/0! #DIV/0! #DIV/0! #DIV/0! #DIV/0!

* Calculated Value

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Element Protocol A

Q Volume (ions, OC/EC, NH3) (m3) 25.245 27.67 23.19 23.43 26.69 24.60 25.25 26.39

Q Volume (SO2) (m3) 25.897 26.23 25.13 25.43 26.80 25.48 25.90 26.64

T Volume (mass, XRF) (m3) 26.224 26.48 26.19 26.02 26.21 25.63 26.22 26.65

1 + Dil. Ratio 36.5 37.4 40.6 34.2 34.0 36.5 36.5 1.0

Detection Limit Detection Limit ug/dscm

ng/cm2 ug/filter Average Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-DSB Char-FB Char-Amb

Ag 12 0.1548 0.2157 0.2187 0.2398 0.2037 0.2006 0.2207 0.2157 0.0058

Al 10 0.1290 0.1798 0.1822 0.1998 0.1698 0.1672 0.1840 0.1798 0.0048

Au 3.1 0.0400 0.0557 0.0565 0.0620 0.0526 0.0518 0.0570 0.0557 0.0015

Ba 52 0.6708 0.9349 0.9476 1.0392 0.8829 0.8695 0.9566 0.9349 0.0252

Br 1.0 0.0129 0.0180 0.0182 0.0200 0.0170 0.0167 0.0184 0.0180 0.0005

Ca 4.5 0.0581 0.0809 0.0820 0.0899 0.0764 0.0752 0.0828 0.0809 0.0022

…

PM2.5 mass 1 1.3937 1.4126 1.5492 1.3162 1.2962 1.4260 1.3937 0.0375

Cl- 1.5 2.1715 2.0275 2.6243 2.1918 1.9095 2.2286 2.1715 0.0568

Nitrate (NO3-) 1.5 2.1715 2.0275 2.6243 2.1918 1.9095 2.2286 2.1715 0.0568

SO4= 1.5 2.1715 2.0275 2.6243 2.1918 1.9095 2.2286 2.1715 0.0568

NH4+ 1.5 2.1715 2.0275 2.6243 2.1918 1.9095 2.2286 2.1715 0.0568

…

Detection limits

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M N O P Q R S T W X Y Z AA AB AC

Input Run data below Input Uncertainty data below

ug/sample ug/sample

Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-DSB Char-FB Char-Amb Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-DSB Char-FB Char-Amb

Ag 0.0000 0.0449 0.0309 0.0000 0.0529 0.0000 0.0513 0.0300 0.0101 0.0095 0.0293 0.0110 0.0271 0.0103

Al 1.3991 6.6490 0.0880 0.1001 0.3332 0.0497 8.7406 0.0331 0.0586 0.0227 0.0230 0.0239 0.0555 0.0823

Au 0.0000 0.0277 0.0000 0.0000 0.0000 0.0000 0.0295 0.0219 0.0458 0.0093 0.0096 0.0117 0.0084 0.0899

Ba 0.0466 0.3583 0.0000 0.0000 0.0000 0.0000 0.8754 0.2855 0.0872 0.2484 0.2618 0.2977 0.2567 0.0918

Br 0.0205 0.0228 0.0065 0.0037 0.0234 0.0000 0.1935 0.0015 0.0014 0.0011 0.0009 0.0012 0.0026 0.0028

Ca 2.6281 10.1793 0.5987 0.4515 0.5328 0.0000 20.4215 0.0133 0.0275 0.0082 0.0079 0.0088 0.0201 0.0487

PM2.5 Mass 141.0000 229.0000 -16.0000 23.0000 47.0000 -16.0000 1085.0000 4.3710 4.3710 4.3710 4.3710 4.3710 4.3710 4.3710

Cl- 1.0200 1.5600 1.2300 0.8400 0.7800 0.6900 17.0700 0.5061 0.5142 0.5089 0.5042 0.5036 0.5028 1.4047

NO3- 7.4400 5.1600 2.1600 1.4700 3.1500 0.0000 131.2200 0.9936 0.7775 0.5587 0.5280 0.6182 0.5000 15.1510

SO4= 10.8300 5.7600 2.6400 3.7500 6.9300 0.0000 35.9100 0.6203 0.5368 0.5079 0.5159 0.5524 0.5000 1.3160

NH4 3.8100 1.5000 0.7800 1.2300 2.5500 0.6000 22.5600 0.5077 0.5012 0.5003 0.5008 0.5034 0.5002 0.7217

…



Figure 5-8. Examples of in-stack PM2.5 concentration intermediate and final calculations (‘conc_dl’ worksheet, metals_oxides_PM spreadsheet).

In the same spreadsheet, the ‘emrate’ worksheet calculates PM2.5 mass emission rates, emission factors and other parameters related to speciation profiles (Figure 5-9). Concentration

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AJ AK AL AM AN AO AP AQ

ug/dscm - in-stack concentration

Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-DSB Char-FB Char-Amb

Ag 0.0000 0.0696 0.0407 0.0000 0.0754 0.0000 0.0019

Al 1.9763 10.3005 0.1158 0.1297 0.4752 0.0693 0.3280

Au 0.0000 0.0429 0.0000 0.0000 0.0000 0.0000 0.0011

Ba 0.0658 0.5551 0.0000 0.0000 0.0000 0.0000 0.0329

Br 0.0290 0.0353 0.0086 0.0048 0.0334 0.0000 0.0073

Ca 3.7124 15.7696 0.7880 0.5852 0.7598 0.0000 0.7664

…

PM2.5 mass 199.1735 354.7633 -21.0585 29.8117 67.0230 -22.2990 40.7206

Cl- 1.3787 2.7293 1.7973 1.0693 1.1589 0.9989 0.6468

NO3- 10.0562 9.0278 3.1563 1.8713 4.6801 0.0000 4.9723

SO4= 14.6383 10.0775 3.8577 4.7737 10.2961 0.0000 1.3607

… 5.1498 2.6243 1.1398 1.5658 3.7886 0.8686 0.8549

Run data

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AS AT AU AV AW AX AY AZ BA BB BC BD

Detected Data

mg/dscm in-stack concentrations greater than detection limit or NDmg/dscm

mg/dscm Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-DSB Char-FB Char-Amb Flag Average RSD (%) count

Ag ND ND ND ND ND ND ND ND n/a 0

Al 2.0E-3 1.0E-2 ND ND 4.8E-4 ND 3.3E-4 < 6.1E-3 95.9 2

Au ND ND ND ND ND ND ND ND n/a 0

Ba ND ND ND ND ND ND 3.3E-5 ND n/a 0

Br 2.9E-5 3.5E-5 ND ND 3.3E-5 ND 7.3E-6 < 3.2E-5 14.0 2

Ca 3.7E-3 1.6E-2 7.9E-4 5.9E-4 7.6E-4 ND 7.7E-4 5.2E-3 137.7 4

…

PM2.5 mass 2.0E-1 3.5E-1 ND 3.0E-2 6.7E-2 ND 4.1E-2 < 1.9E-1 83.5 3

Cl- ND 2.7E-3 ND ND ND ND 6.5E-4 < 2.7E-3 n/a 1

NO3- 1.0E-2 9.0E-3 3.2E-3 ND 4.7E-3 ND 5.0E-3 < 7.4E-3 50.2 3

SO4= 1.5E-2 1.0E-2 3.9E-3 4.8E-3 1.0E-2 ND 1.4E-3 8.3E-3 60.2 4

NH4+ 5.1E-3 2.6E-3 ND ND 3.8E-3 ND 8.5E-4 < 3.9E-3 45.9 2

…

1

2

3

4

5

6

7

8

9

10

12

13

14

15

49

50

51

52

53

54

55

BG BH BI BJ BK BL BM BN BO BP BQ

Detected Data; set ND's = Zero. Missing data will cause sum of averages to not equal average of sums.

mg/dscm in-stack concentrations greater than detection limit and ND = 0.

mg/dscm Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Char-DSB Char-FB Char-Amb Average RSD (%) count

Ag 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.00E+0 n/a 4

Al 2.0E-3 1.0E-2 0.0E+0 0.0E+0 4.8E-4 0.0E+0 3.3E-4 3.07E-3 160.0 4

Au 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.00E+0 n/a 4

Ba 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 0.0E+0 3.3E-5 0.00E+0 n/a 4

Br 2.9E-5 3.5E-5 0.0E+0 0.0E+0 3.3E-5 0.0E+0 7.3E-6 1.61E-5 116.6 4

Ca 3.7E-3 1.6E-2 7.9E-4 5.9E-4 7.6E-4 0.0E+0 7.7E-4 5.21E-3 137.7 4

…

PM2.5 mass 2.0E-1 3.5E-1 0.0E+0 3.0E-2 6.7E-2 0.0E+0 4.1E-2 1.46E-1 112.8 4

Cl- 0.0E+0 2.7E-3 0.0E+0 0.0E+0 0.0E+0 0.0E+0 6.5E-4 6.82E-4 200.0 4

NO3- 1.0E-2 9.0E-3 3.2E-3 0.0E+0 4.7E-3 0.0E+0 5.0E-3 5.56E-3 86.2 4

SO4= 1.5E-2 1.0E-2 3.9E-3 4.8E-3 1.0E-2 0.0E+0 1.4E-3 8.34E-3 60.2 4

NH4+ 5.1E-3 2.6E-3 0.0E+0 0.0E+0 3.8E-3 0.0E+0 8.5E-4 1.94E-3 127.1 4

…



and emission factor uncertainties are calculated on other worksheets, following ASME PTC 19.1 (Figure 5-10).

Figure 5-9. Example of PM2.5 mass emission rate and emission factor calculations (‘emrate’ worksheet, metals_oxides_PM spreadsheet).

2

3

4

5

6

7

8

9

10

11

12

13

14

15

49

50

51

52

53

54

55

B C D E F G H I J K L M N O P Q

g/hr lb/hr lb/MMBtu (elements only, does not include contribution of oxide)

dry stack flow (dscmh) 112,034 111,074 109,304 108,356

Average-> 110,192

Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4Char-Run 1Char-Run 2Char-Run 3Char-Run 4 Flag Average RSD (%)

Ag ND ND ND ND ND ND ND ND ND ND ND ND ND n/a

Al 2.21E-1 1.14E+0 ND ND ND ND 4.88E-04 2.52E-03 ND ND < 1.51E-03 95.6

As ND ND ND ND ND ND ND ND ND ND ND ND ND n/a

Au ND ND ND ND ND ND ND ND ND ND ND ND ND n/a

Ba ND ND ND ND ND ND ND ND ND ND ND ND ND n/a

Br 3.24E-3 3.92E-3 ND ND ND ND 7.15E-06 8.65E-06 ND ND < 7.90E-06 13.4

Ca 4.16E-1 1.75E+0 8.61E-2 6.34E-2 9.17E-04 3.86E-03 1.90E-04 1.40E-04 1.28E-03 137.8

…

PM2.5 mass 2.23E+1 3.94E+1 ND ND 3.23E+0 4.92E-02 8.69E-02 ND 7.12E-03 < 4.77E-02 83.6

Cl- ND ND 3.03E-1 ND ND ND ND ND 6.68E-04 ND ND < 6.68E-04 n/a

NO3- 1.13E+0 1.00E+0 3.45E-1 ND ND 2.48E-03 2.21E-03 7.61E-04 ND < 1.82E-03 50.9

SO4= 1.64E+0 1.12E+0 4.22E-1 5.17E-1 3.62E-03 2.47E-03 9.30E-04 1.14E-03 2.04E-03 61.5

NH4+ 5.77E-1 2.91E-1 ND ND ND ND 1.27E-03 6.43E-04 ND ND < 9.57E-04 46.5

…

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3

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49

50

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52

53

54

55

T U V W X Y Z AA AB AC AD

lb/MMBtu (elements only, does not include contribution of oxide)

heat input (MMBtu/hr) 299.4 293.4 288.6 283.8 291.3 6.68 1.6

SUM of Species/PM2.5 = 2.451 1.307 NA 4.998 2.918

Char-Run 1 Char-Run 2 Char-Run 3 Char-Run 4 Flag Average stdev RSD (%) Count

Ag silver ND ND ND ND ND n/a n/a 0

Al aluminum 1.63E-06 8.60E-06 ND ND < 5.11E-06 4.9E-6 96 2

As arsenic ND ND ND ND ND n/a n/a 0

Au gold ND ND ND ND ND n/a n/a 0

Ba barium ND ND ND ND ND n/a n/a 0

Br bromine 2.39E-08 2.95E-08 ND ND < 2.67E-08 4.0E-9 15 2

Ca calcium 3.06E-06 1.32E-05 6.58E-07 4.93E-07 4.34E-06 6.0E-6 138 4

…

PM2.5 mass 1.64E-04 2.96E-04 ND 2.51E-05 < 1.619E-04 1.4E-4 84 3

Cl- ND 2.28E-06 ND ND < 2.28E-06 n/a n/a 1

NO3- 8.30E-06 7.54E-06 2.64E-06 ND < 6.16E-06 3.1E-6 50 3

SO4= 1.21E-05 8.41E-06 3.22E-06 4.02E-06 6.93E-06 4.1E-6 59 4

NH4+ 4.25E-06 2.19E-06 ND ND < 3.22E-06 1.5E-6 45 2

…



Figure 5-10. Example calculations of concentration and emission factor uncertainties (metals_oxides_PM spreadsheet).

Other supporting data in the appendices typically includes:

Pre-, post- and in-run velocity traverses used for determining stack gas flow and PM2.5 mass emission rates;

Stack gas O2 and CO2 measurements, either via portable analyzer, instrumental methods or plant process data;

Measurement equipment calibrations, in particular the dilution sampler venturi and bypass blower calibrations;

Process operating data such as temperatures, fuel flow rates, fuel heating values, etc. used for calculating fuel heat input rate and PM2.5 emission factors;

Fuel analyses, if included in test scope and used in emission factor calculations.

Table I-1A. Uncertainty Calculations for Flue Gas Concentrations - NDs = Zero for Speciation Profile Calcs..

PARAMETER

Reported

Concentration

Number of

Runs

Sampling

Bias (1)

Analytical

Bias

Total Bias

(3)

Total

Precision

Total

Uncertainty

(5)

95%

Confidence

Upper

Bound (8)

(mg/dscm) (%) (%) (%) (%) (%) (mg/dscm)

Elements by XRF

Ag 0.00E+00 4 0 (2) 0.00 0.0 (4) n/a n/a n/a

Al 3.07E-03 4 0 (2) 1.67 1.7 (4) 160 255 8.85E-3

As 0.00E+00 4 0 (2) 0.00 0.0 (4) n/a n/a n/a

Au 0.00E+00 4 0 (2) 0.00 0.0 (4) n/a n/a n/a

Ba 0.00E+00 4 0 (2) 0.00 0.0 (4) n/a n/a n/a

Br 1.61E-05 4 0 (2) 9.48 9.5 (4) 117 186 3.82E-5

Ca 5.21E-03 4 0 (2) 0.47 0.5 (4) 138 219 1.37E-2

…

PM2.5 Mass 1.46E-01 4 0 (6) 3.85 3.9 (4) 113 179 3.40E-1

Cl- 6.82E-04 4 0 (2) 65.92 65.9 (4) 200 325 2.35E-3

Nitrate (NO3-) 5.56E-03 4 0 (2) 18.70 18.7 (4) 86 138 1.13E-2

SO4= 8.34E-03 4 0 (2) 9.52 9.5 (4) 60 96 1.43E-2

NH4+ 1.94E-03 4 0 (2) 26.87 26.9 (4) 127 204 4.90E-3

…

(1) Based on typical sampling train instrument errors; or if zero, 5% sampling bias included in analytical bias.

(2) Based RSD of test runs uncertainty.

(3) Calculated using sampling and analytical biases and from Concentration Equation using Partial Derivatives

and Taylor Series *

(4) Relative standard deviation of test runs

(5) From ASME PTC 19.1 Eq 2.26. Two tailed 95% Confidence.

(6) Estimated Analytical Balance Accuracy

(7) Footnote removed

(8) From ASME PTC 19.1 Eq 2.29B. Single Tailed 95% Confidence.

(9) Based on calibration standard

(10) Based on surrogate standard recovery criteria

* American Society of Mechanical Engineers Performance Test Code 19.1-1985 Reaffirmed 1990

**SUM of Species does not include Cl, PM2.5 mass, Mg, Na, & S

4

5

6

7

8

9

10

11

12

13

14

15

49

50

51

52

53

54

55

74

75

76

77

78

79

80

81

82

83

84

A B C D E F G H I J K L M N O P

Table I-2. Uncertainty Calculations for Emission Factors.

Reported

Emission

Factor

Number of

Runs

Flue Gas

Concentration

Measurement (1) Flue Gas Flowrate (2) Heat Rate (MMBtu/hr)

Total Bias

(7)

Total

Precision

(7)

Total

Uncertainty (8)

95%

Confidence

Upper Bound

(9)

PARAMETER Bias Precision Bias Precision Bias (3) Precision (4) Bias (5) Precision (6)

(lb/MMBtu) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (%) (lb/MMBtu)

Elements by XRF

Ag ND 0 0.0 n/a 10 1.5 10 2.3 14.1 n/a n/a n/a

Al < 5.11E-06 2 1.7 95.9 10 1.5 10 2.3 14.2 95.9 862.0 2.7E-5

As ND 0 0.0 n/a 10 1.5 10 2.3 14.1 n/a n/a n/a

Au ND 0 0.0 n/a 10 1.5 10 2.3 14.1 n/a n/a n/a

Ba ND 0 0.0 n/a 10 1.5 10 2.3 14.1 n/a n/a n/a

Br < 2.67E-08 2 9.5 14.0 10 1.5 10 2.3 17.0 14.3 129.3 4.4E-8

Ca 4.34E-06 4 0.5 137.7 10 1.5 10 2.3 14.1 137.8 219.7 1.1E-5

…

PM2.5 mass < 1.62E-04 3 3.9 83.5 10 1.5 10 2.3 14.7 83.6 208.1 3.9E-4

Cl- < 2.28E-06 1 65.9 n/a 10 1.5 10 2.3 67.4 n/a n/a n/a

NO3- < 6.16E-06 3 18.7 50.2 10 1.5 10 2.3 23.4 50.3 127.1 1.2E-5

SO4= 6.93E-06 4 9.5 60.2 10 1.5 10 2.3 17.0 60.2 97.4 1.2E-5

NH4+ < 3.22E-06 2 26.9 45.9 10 1.5 10 2.3 30.4 46.0 414.6 9.9E-6

…

(1) Taken from calculated values obtained in Table I-1.

(2) From EPA QA Handbook, Volume III

(3) Estimated Bias

(4) Relative standard deviation of heat rates for all test runs.

(5) Estimated Accuracy of flowmeter

(6) Relative standard deviation of fuel flowrates for all runs during the program

(7) Calculated using sampling and analytical biases and from Concentration Equation, mass flow calculation, emission factor calculation, Partial Derivatives and Taylor Series *

(8) From ASME PTC 19.1 Eq 2.26. Two tailed 95% Confidence. t=4.3 *

(9) From ASME PTC 19.1 Eq 2.29B. t=2.92*

* American Society of Mechanical Engineers Performance Test Code 19.1-1985 Reaffirmed 1990

**SUM of Species does not include Cl, PM2.5 mass, Mg, Na, & S



The electronic (in pdf) versions of the appendices have been bookmarked to facilitate navigation through the documents. In addition to table of contents bookmarks, a set of bookmarks to facilitate PM2.5 data review (‘PM Data Trail’) also has been added to aid the reviewer.


ENVIRON

Appendix A

Nomenclature Cross-Reference


ENVIRON

Table A1: Nomenclature Cross-Reference

Spreadsheet Nomenclature Formulas Nomenclature

Ambient T ( C ) ***

Ambient T (K) Tamb

Ambient P (in Hg)

Ambient P (torr) **** Pbar

Motor T ( C )

Motor T (K) Tm

Venturi T ( C ) *

Venturi T ( K ) Tsv

Venturi dP (inch H2O) dPsv

Motor dP (inch H2O) dPbb

Stack Static P (inch H2O) Ps

Avg. corrected probe flow from DAS (lpm)

Actual Probe Flow (lpm) Qsv

Avg. probe flow (slpm)

Av. Corrected Motor flow from DAS (lpm)

Actual Motor Flow (lpm) Qbb

Avg. Motor flow (slpm) Qbbs

Dilution ratio (wet) DRf

Dilution Ratio + 1 (wet) DFf

Ambient RH (%) RHamb

Ambient T (C)

Water Vapor Saturation P at Ambient T (mm Hg) Psat,w,amb

Ambient Water Vapor P (mm Hg) Pw,amb

Ambient Water Vapor (vol fraction) Bw,amb

Stack Water Vapor (vol fraction) Bws

Chamber Water Vapor (volume fraction) - calculated

Chamber RH (%) RHrtc

Chamber T ( C )

Water Vapor Saturation P at Chamber T (mm Hg) Psat,w,rtc

Chamber Water Vapor (volume fraction) - "measured" Bw,rtc

Chamber Water Vapor: calculated/measured - QA Check

Avg Probe Flow (dry slpm) Qsv,s

Avg Dilution Air Flow (dry slpm) Qda,s

Dilution Ratio (dry) DRd

Dilution Ratio + 1 (dry) DFd

Rotameter indicated flow rate, mL/min Qsr

Rotameter flow rate at standard T and P (smL/min) Qsrs

Total flow rate through sample media and bypass (smL/min) Qsmts


ENVIRON

Appendix B

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 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

1

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

2

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.

3

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

4

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

7

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

8

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-

9

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

10

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

11

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

12

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

13

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%

14

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

15

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

16

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