Review of Emissions Test Reports for Emissions Factors Development for Flares and Certain Refinery Operations


m

m0*

Review of Emissions Test Reports for Emissions
Factors Development for Flares and Certain
Refinery Operations

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Review of Emissions Test Reports for Emissions Factors Development for Flares and Certain

Refinery Operations

Contract No. EP-D-11-084
Work Assignment No. 3-06

U.S. Environmental Protection Agency
Office of Air Quality Planning and Standards

Sector Policies and Programs Division
Research Triangle Park, North Carolina 27711

December 2016

in

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Disclaimer

This report has been reviewed by the Sector Policies and Programs Division of the Office of Air
Quality Planning and Standards, Office of Air and Radiation, EPA, and approved for publication.
Mention of trade names or commercial products is not intended to constitute endorsement or
recommendation for use.

iv

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Table of Contents

Page

Section 1 Summary	1

Section 2 Background	4

2.1	Overview of Emissions Test Data Review	6

2.2	Overview of Emissions Factor Analysis and Development	7

Section 3 Emissions Factor Development from Test Data Collected Under the 2011

Refinery ICR	8

3.1	Catalytic Reforming Units - CO	8

3.2	Catalytic Reforming Units - THC	9

3.3	Fluid Catalytic Cracking Units - HCN	11

3.3.1	Coke Burn Rate Basis	11

3.3.2	Feed Rate Basis	14

3.4	Sulfur Recovery Units - CO	16

3.4.1	Heat Rate Basis	16

3.4.2	Sulfur Production Rate Basis	20

3.5	Sulfur Recovery Units - NOx	24

3.5.1	Heat Rate Basis	24

3.5.2	Sulfur Production Rate Basis	28

3.6	Sulfur Recovery Units - THC	32

3.6.1	Heat Rate Basis	32

3.6.2	Sulfur Production Rate basis	34

3.7	Hydrogen PI ants - C O	36

3.8	Hydrogen PI ants - N Ox	37

3.9	Hydrogen Plants - THC	39

Section 4 Discussion of Revisions to SO2 Emissions Factors in AP-42 Section 8.13,

Sulfur Recovery	41

Section 5 Emissions Factor Development for Industrial Flares	43

5.1	Flares-CO	43

5.2	Flares-VOC	49

Section 6 References	55

Appendix A Emissions Test Report Data Fields Include In Test Data Summary Files
Appendix B EPA's "Test Quality Rating Tool" Template (ICR Template)

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Appendix C Flare Emissions Factor Development - Preferred CO2 Wavelength

List of Tables

Table S-l. Summary of New and Revised Emissions Factors Developed	2

Table 1. Emissions Sources and Pollutants with Emissions Test Report Data Reviewed a	5

Table 2. Flare Pollutants and Emissions Test Report Data Reviewed a	5

Table 3. Analysis of Emissions Test Reports for CO from CRUs	9

Table 4. Overview of the Emissions Factor for THC from CRUs	10

Table 5. Analysis of Emissions Test Reports for THC from CRUs	10

Table 6. Overview of the Emissions Factor for HCN from FCCUs (Coke Burn Rate

Basis)	12

Table 7. Analysis of Emissions Test Reports for HCN from FCCUs (Coke Burn Rate

Basis)	13

Table 8. Overview of the Emissions Factor for HCN from FCCUs (Feed Rate Basis)	15

Table 9. Analysis of Emissions Test Reports for HCN from FCCUs (Feed Rate Basis)	15

Table 10. Overview of the Emissions Factor for CO from SRUs (Heat Rate Basis)	17

Table 11. Analysis of Emissions Test Reports for CO from SRUs (Heat Rate Basis)	17

Table 12. Overview of the Emissions Factor for CO from SRUs (Sulfur Production Rate

Basis)	21

Table 13. Analysis of Emissions Test Reports for CO from SRUs (Sulfur Production

Rate Basis) 	21

Table 14. Overview of the Emissions Factor for NOx from SRUs (Heat Rate Basis)	25

Table 15. Analysis of Emissions Test Reports for NOx from SRUs (Heat Rate Basis)	25

Table 16. Overview of the Emissions Factor for NOx from SRUs (Sulfur Production

Rate Basis)	29

Table 17. Analysis of Emissions Test Reports for NOx from SRUs (Sulfur Production

Rate Basis) 	29

Table 18. Overview of the Emissions Factor for THC from SRUs (Heat Rate Basis)	33

Table 19. Analysis of Emissions Test Reports for THC from SRUs (Heat Rate Basis) 	33

Table 20. Overview of the Emissions Factor for THC from SRUs (Sulfur Production

Rate Basis)	35

Table 21. Analysis of Emissions Test Reports for THC from SRUs (Sulfur Production

Rate Basis) 	35

Table 22. Analysis of Emissions Test Reports for CO from H2 Plants	37

vi

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Table 23. Overview of the Emissions Factor for NOx from Hydrogen Plants	38

Table 24. Analysis of Emissions Test Reports for NOx from Hydrogen Plants	38

Table 25. Analysis of Emissions Test Reports for THC from Hydrogen Plants	40

Table 26. Overview of the Emissions Factor for CO from Flares	48

Table 27. Analysis of Emissions Test Reports for CO from Flares	48

Table 28. Overview of the Emissions Factor for VOC from Flares	54

Table 29. Analysis of Emissions Test Reports for VOC from Flares	54

vii

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Section 1
Summary

The purpose of this report is to document the review and analysis of test reports and
assess the use of test report data for developing emissions factors for flares and certain refinery
operations. These emissions factors are finalized as an update to the Compilation of Air
Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources, AP-42 (EPA, 1995).

On May 1, 2013, Air Alliance Houston, Community In-Power and Development
Association, Inc. (CIDA), Louisiana Bucket Brigade, and Texas Environmental Justice
Advocacy Services (TEJAS), (collectively, "Plaintiffs") filed a lawsuit against the U.S.
Environmental Protection Agency (EPA) alleging that the EPA had failed to review and, if
necessary, revise emissions factors at least once every three years as required in Section 130 of
the Clean Air Act (CAA). Air Alliance Houston, et al. v. McCarthy. No. 1:13-cv-00621-KBJ
(D.D.C.). In the complaint, the Plaintiffs sought to compel the EPA to expeditiously complete a
review of the volatile organic compounds (VOC) emissions factors for industrial flares
("flares"), liquid storage tanks ("tanks"), and wastewater collection, treatment and storage
systems ("wastewater treatment systems"), and, if necessary, revise these factors. EPA entered
into a consent decree with the Plaintiffs to settle the lawsuit. Under the terms of the consent
decree, by August 19, 2014, EPA was to review and either propose revisions to the VOC
emission factors for flares, tanks and wastewater treatment systems under CAA section 130, or
propose a determination under CAA section 130 that revision of these emission factors was not
necessary. By April 20, 2015 (originally December 19, 2014), EPA will issue final revisions to
the VOC emission factors for flares, tanks and wastewater treatment systems, or issue a final
determination that revision of these emission factors for flares is not necessary. EPA will post
each proposed revision or determination (or combination thereof), and each final revision or
determination (or combination thereof), on its AP-42 website by the dates indicated above.

As part of its efforts to comply with the consent decree, EPA reviewed emissions test
data submitted by refineries for the 2011 Petroleum Refinery Information Collection Request
(2011 Refinery ICR) and test data collected during the development of parameters for properly
designed and operated flares and developed new emissions factors, as shown in Table S-l.

The EPA proposed emissions factors and updates to AP-42 sections 5.1, 8.13, and 13.5
on August 20, 2014 and requested public comments on the emissions factors. The public
comment period ended on December 19, 2014. EPA received a total of 59 comment letters and
has developed a separate response to comments document (EPA, 2015b).

The EPA is finalizing these emissions factors in AP-42 sections 5.1 Petroleum Refining,
8.13 Sulfur Recovery, and 13.5 Industrial Flares.

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Table S-l. Summary of New and Revised Emissions Factors Developed



Kmissions lost d;it;i used







Emissions I nil
iiiul I'olliiliint

No. of test
reports

\o. or
units''

lest methods

AP-42 Kniissions
Tiiclor

Representji-
ti\eness

Catalytic
Reforming Unit
(CRU), Total
Hydrocarbon
(THC)

8

8

EPA Method 25A

2.4 x 10"4 lb THC
(as propane)/bbl
feed

Poorly

Fluid Catalytic
Cracking Unit
(FCCU), Hydrogen
Cyanide (HCN)

11

11

EPA Other Test
Method-029; EPA

Method 320;
modified CTM-
033

4.3 x 10"4 lb
HCN/lb coke burn

Moderately



10

10

EPA Other Test
Method-029; EPA

Method 320;
modified CTM-
033

7.0 x 10"3 lb
HCN/bbl feed

Moderately

Sulfur Recovery
Unit (SRU),

25

24

EPA Method 10;
SCAQMD 100.1

0.71 lb CO/mmBtu

Moderately

Carbon Monoxide
(CO)

23

23

EPA Method 10

1.3 lb CO/ton
sulfur

Moderately

Sulfur Recovery
Unit, Oxides of

25

26

EPA Method 7E

0.101b
NOx/mmBtu

Moderately

Nitrogen (NOx)

24

26

EPA Method 7E

0.22 lb NOx/ton
sulfur

Moderately

SRU, THC

9

10

EPA Method 25A

1.4 x 10-3 lb THC
(as propane)/
mmBtu

Poorly



7

7

EPA Method 25A

0.040 lb THC (as
propane)/ ton
sulfur

Poorly

Hydrogen Plant
NOx

7

7

EPA Method 7E

0.081 lb
NOx/mmBtu

Poorly

Flare CO

7 b

10 b

Extractive
PFTIRc

0.31 lb CO/mmBtu

Poorly

2

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Flare Volatile

7

10

Extractive

0.571b

Poorly

Organic





PFTIR;c

VOC/mmBtu



Compounds





DIAL d





(VOC)











a Number of units used during emissions factor development process. This number includes outliers.
b Includes original flare test report used to create previous emissions factor.
c PFTIR is passive Fourier Transform Infrared.

dDIAL is Differential infrared absorption LIDAR (light detection and ranging).

3

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Section 2
Background

In April 2011, EPA sent an ICR under CAA section 114 authority to facilities in the
Petroleum Refining industry (EPA, 2011) ("2011 Refinery ICR"). The 2011 Refinery ICR
consisted of four components, and two of these components requested emissions testing data
from refineries. Component 1 of the 2011 Refinery ICR requested all refineries to submit reports
for emissions tests that had been conducted since 2005. Component 4 of the 2011 Refinery ICR
requested that certain refineries conduct testing for specific pollutants at specific emissions
sources in accordance with an EPA-approved protocol and submit the test reports to EPA.
Emissions testing reports were collected for catalytic reforming units (CRUs), fluid catalytic
cracking units (FCCUs), sulfur recovery units (SRUs), and hydrogen plants, along with several
other emissions sources. Testing was conducted for a number of pollutants, including carbon
monoxide (CO), hydrogen cyanide (HCN), oxides of nitrogen (NOx), and total hydrocarbons
(THC). Emissions testing reports were analyzed for multiple emissions sources and pollutants,
as shown in Table 1, for the purpose of updating or developing new emissions factors in AP-42.
In general, this project focused on the pollutants required under section 130 of the CAA (CO,
NOx, and VOC1), and those emissions units and pollutants for which there are no current AP-42
emissions factors (EPA 1995). For hazardous air pollutants (HAPs), we focused on HCN from
catalytic cracking units because that emissions unit is often the largest emissions source at the
refinery and HCN is a risk driver for the petroleum refinery source category (EPA 2014).

Test data for the operating parameters and emissions from flares at petroleum refineries
and chemical plants are available as a result of various enforcement actions related to flare
performance issues. The EPA collected additional flare data during development of an analysis
of proper flare operating conditions (EPA 2012). We were able to obtain data from a DIAL
study in the Houston area in which the emissions from several flares were isolated. We also used
the original flare report from which the previous set of flare emissions factors were created.

Flare data are available for CO and VOC, as shown in Table 2.

This report documents the review and analysis of the available source test reports from
the 2011 Refinery ICR for the emissions sources/pollutants identified in Table 1 and from flare
studies for the pollutants identified in Table 2.

The background files for the AP-42 sections being revised contain the information
discussed in this document, including the data summary worksheets, the emissions factor
creation worksheets, the Individual Test Rating (ITR) score sheets, and test reports that were
reviewed but not used in the calculation of the emissions factor. A link to the background files
can be found under the section's heading on the AP-42 website

(http://www.epa.gov/ttn/chief/ap42/index.html, see sections 5.1 Petroleum Refining, 8.13 Sulfur
Recovery, and 13.5 Industrial Flares). The test reports that were used in the development of the

1 We also focused on THC as a surrogate for VOC.

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emissions factors are listed as references in the AP-42 sections being revised. These references
can be accessed by clicking the reference's name in the AP-42 section.

Table 1. Emissions Sources and Pollutants with Emissions Test Report Data Reviewed a

Totiil

niiin her of

No. C omponent

No. Component

emissions

1 omissions test

4 emissions test

lest

Emissions source

I'olllllillll

reports

(Catalytic Reforming Units (CRUs)

THC

15 b

Fluid Catalytic Cracking Units
(FCCUs)

HCN

23c

Sulfur Recovery Units (SRUs)

NOx

THC

Hydrogen Plants

NOx

THC

Total emissions test reports reviewed

197

a This table provides the total number of test reports (and not necessarily the number of emissions units).
Each test report may have test data for 1 or more emissions unit(s), and in some instances, an emissions
unit may have more than 1 test report.

b One test that was part of the 2011 ICR was inadvertently left out of the analysis at proposal and added
in for the final analysis.

c Two of the tests were conducted after the 2011 ICR. We obtained these data as a result of comments on
the proposed emissions factor.

Table 2. Flare Pollutants and Emissions Test Report Data Reviewed a

Emissions source

I'olliitiinl

No. emissions test reports

llares

7 b

VOC

Total emissions test reports reviewed

8 b

a This table provides the total number of test reports (and not necessarily the number
of emissions units). Each test report may have test data for 1 or more emissions
unit(s).

b Includes original flare test used to create the previous emissions factor.

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2.1 Overview of Emissions Test Data Review

The facility and emissions information for each test report was compiled in a test data
summary worksheet called "Test_Data_Sum_(pollutant)_(emissionssource)". The data fields
included in the Test Data Summary file are provided in Appendix A. The Test Data Summary
file includes the field "QA Notes" in column DA that summarizes what data are available in the
test report and any potential issues with the data. The field "Looked at for EF?" identifies which
emissions factor the test report was reviewed for and the field "Used for EF?" identifies whether
the test report was included in emissions factor development.

To develop an emissions factor, two basic test data requirements need to be included in
the report: (1) pounds per hour (lb/hr) emissions rate, or enough data to calculate the lb/hr
emissions rate, and (2) process hourly production or process rate (process activity/hr), e.g., feed
rate in barrels per hour (bbl/hr), coke burn rate in lb/hr, or production rate in tons per hour
(ton/hr) or standard cubic feet per hour (scf/hr). Each test report was reviewed to confirm
whether the critical fields were available, and the calculations in the test report were reviewed for
accuracy.

For each emissions test report used in developing the emissions factor (i.e., "Yes"
response for field "Use in EF?"), an individual test rating (ITR) score was given to the test report
by completing the "Test Quality Rating Tool" tab in the EPA's WebFIRE Template and Test
Quality Rating Tool (including instructions) spreadsheet (available on the ERT website at:
http://www.epa.gov/ttnchiel/ert/). The "Test Quality Rating Tool" template for the ITR is
provided in Appendix B. The ITR is a quantitative measure of the quality of the data contained
within a test report. The ITR score may range from 0 to 100 and gives a general indication of the
level and quality of documentation available in the test report and the level of conformance with
the test method requirements. The "Test Quality Rating Tool" includes a series of questions
related to "Supporting Documentation Provided" (columns A and B) and related to "Regulatory
Agency Review" (columns G and H). Generally, the "Supporting Documentation Provided"
columns are an indication of the completeness of the test report while the Regulatory Agency
Review" columns provide an indication of whether the test was conducted according to the
requirements of the test method. Columns A and B of the template worksheet were completed in
this analysis. Columns G and H, which are specific to State/Local agency reviewers, were not
completed.

Because only the "Supporting Documentation Provided" portion of the worksheet was
completed, ITR scores for the test reports in the analysis range from approximately 4 to 72. For
the "Supporting Documentation Provided" portion, the ITR includes 8 general questions, 8
questions for manual test methods, and 10 questions for instrumental test methods. Examples of
the general questions include whether the testing firm described deviations from the test method
or provided a statement that deviations were not required; whether a full description of the
process and unit tested was provided; and whether an assessment of the validity,
representativeness, achievement of data quality objectives and usability of the data was provided.
For manual test methods, examples of questions include whether the Method 1 sample point
evaluation was included in the test report; whether cyclonic flow checks were included in the
report; and whether a complete laboratory report and flow diagram of sample analysis was

6

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included. For instrumental test methods, example questions include whether a complete
description of the sampling system was provided; whether the response time tests were provided;
whether the calibration error tests were included; and whether the drift tests were included. The
ITR scores for the test reports reviewed are provided in a spreadsheet called "Webfire-
template_(pollutant)_(emissionssource)".

2.2 Overview of Emissions Factor Analysis and Development

The emissions factor development approach followed EP A's Recommended Procedures
for Development of Emissions Factors and Use of the WebFIRE Database (EPA, 2013). The
emissions factor analysis for each emissions factor is provided in the spreadsheet

"EFCreation (pollutant)_(emissionssource).xlsm". The recommended procedures in the 2013

guidelines were followed implicitly, including the handling of below detection limit (BDL) test
data, assigning an ITR score for those test reports that are used in the emissions factor analysis,
recommended statistical procedures for determining whether data sets are part of the same data
population, statistical procedures for determining whether any data points are outliers (i.e.,
outlier checks), and determining whether data for a particular emissions unit should be included
in the emissions factor. This last step, determining whether to include data from each unit,
involves comparison of the Factor Quality Index (FQI) for different emissions units. The FQI is
an indicator of the emissions factor's ability to estimate emissions for the entire national
population, and it is related to both the ITR score and the number of units in the data set. Once
the statistical procedures are complete, the data set is ranked by ITR score (high to low), and a
FQI is developed for each unit in the candidate set. The FQI should decrease with each
emissions unit. When the FQI increases, only average test values above the point where the FQI
increases are considered in factor development.

EPA's Emissions Factor Creation spreadsheet combines the emissions data from multiple
test reports conducted on a single emissions unit, so that each emissions unit is equally weighted
with other units. Because the EPA's recommended emissions factor development procedures are
based on the premise that more test data values are preferred over fewer test data values, the
scope of this project was limited to data sets containing test averages from at least 3 different
emissions units. Additionally, there are times when it is necessary to subcategorize the
emissions factor data from particular units because the emissions are dissimilar. The
recommended emissions factor development procedures include a statistical procedure for
determining whether emissions data are from the same data population, to indicate whether
emissions data should be subcategorized based on a characteristic of the emissions unit (e.g.,
type of APCD). This analysis requires 3 or more emissions units from each potential
subcategory.

Some of the data from instrumental test methods (e.g. Method 7E, Method 10, etc.)
included test run averages reported as a negative value. The 2013 recommended procedures for
emissions factor development do not specify how this data should be handled. Because the
procedures are silent and it is not possible for emissions rates to be negative, this data has been
excluded from emissions factor development in this project.

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Section 3

Emissions Factor Development from Test Data Collected Under the

2011 Refinery ICR

EPA has reviewed emissions test data submitted by refineries for the 2011 Refinery ICR.
The emissions data review and the emissions factor development for each emissions unit and
pollutant are described below.

3.1 Catalytic Reforming Units - CO

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for CO from catalytic reforming units (CRU). Each of the available test reports was
reviewed, analyzed, and summarized, and for those test reports included in the emissions factor
analysis, given an ITR score.

Based on the emissions test report review and analysis, 2 emissions test reports for 2
emissions units had useable data and were included in the development of an emissions factor;
these units had reformer charge rate data as the available production data. These useable
emissions test reports are provided in Table 3. In addition, another 2 emissions test reports for 2
emissions units had useable data, with coke burn rate data as the available production data.

These useable test reports are also provided in Table 3. A complete list of the available test
report information is provided in worksheet "Test_Data_Sum_CO_CRU_2015April.xlsm". For
more detail on the analysis and QA conducted, see the field "QA Notes" for each test report.
The emissions data (lb CO/hr) in these test reports are based on measurements taken with EPA
Method 10 (M10) and EPA M320, and the test reports included production rate data for the CRU
in either bbl/hr feed rate or lb/hr coke burn rate.

Certain test reports were excluded from the emissions factor analysis because production
rate data are not available.

Overall, 4 test reports have useable data. Two emissions test reports include data on a
reformer charge rate basis while the other 2 emissions test reports include data on a coke burn
rate basis. These production data bases are not in comparable units, and there is no way to
calculate the production rate data on the same basis, so these test reports could not be combined
for emissions factor development. Because the scope of this project is limited to data sets
containing test averages from at least 3 emissions units and because there are only 2 emissions
units with useable test reports in each of the different production rate categories, an emissions
factor was not developed for CRU CO.

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Table 3. Analysis of Emissions Test Reports for CO from CRUs

1 iuililv II)
No.

l iicililv mime

Kmissions
unit

APC 1)

Test
mot hod

A\ersi«»e lesl
result

Ilk

Production Data as Reformer Charge Rate, bbl/hr

MS3C0740

Chevron Refinery,
Pascagoula, Mississippi

EPN CH-

004

Chlorsorb

M10

4.5 x 10"6 lb
CO/bbl feed

OK2C0990

TPI Refining Company
Ardmore Petroleum
Refinery Ardmore,
Oklahoma

CRU400B

Venturi
Scrubber

M10

9.8 x 10 5 lb
CO/bbl feed

Production Data as Coke Burn Rate, lb/hr

OK2C0990

TPI Refining Company
Ardmore Petroleum
Refinery Ardmore,
Oklahoma

CRU400B

Venturi
Scrubber

M10

2.9 x 10"3 lb
CO/lb Coke
burn

TX3B1170

Exxonmobil Beaumont
Refinery, Beaumont,
Texas

PTR-4
Reactor
Regenerator
vent

Caustic
Scrubber

M10

2.5 x 10 3 lb
CO/lb Coke
burn

3.2 Catalytic Reforming Units - THC

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for THC from CRU units. Each of the available test reports was reviewed, analyzed, and
summarized, and for those test reports included in the emissions factor analysis, given an ITR
score. An overview of the emissions factor is provided in Table 4.

Based on the emissions test report review and analysis, 8 emissions test reports for 8
emissions units had useable data and were included in the development of the emissions factor.
These emissions tests reports are provided in Table 5. A complete list of the available test report
information is provided in worksheet "Test_Data_Sum_THC_CRU_2015April.xlsm". For more
detail on the analysis and QA conducted, see the field "QA Notes" for each test report. The ITR
scores for these 8 test reports ranged from 23 to 46. The emissions data (lb THC, as propane/hr)
in these test reports are based on measurements taken with EPA Method 25A (M25A), and the
test reports included production rate data for the CRU in bbl/hr feed rate. In instances where
both M25A and EPA Method 18 (Ml 8) were conducted in the same test report, the THC data for
M25 A alone were extracted from the raw data in the test report appendices, so that the data from
all tests was measured on the same basis.

Certain test reports were excluded from the emissions factor analysis for the following
reasons: production rate data are not available, the test method was not compatible with THC
(i.e, Ml8 test reports were excluded because Ml8 measures specific compounds where M25A
counts total carbon) or the test method was not clearly identified.

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EPA's recommended emissions factor development procedures were followed for the
CRU THC data. All 8 emissions units were combined for the emissions factor development.
These 8 CRU are continuous regeneration units. The statistical analysis for determining outliers
in the data set was conducted, and no data were found to be outliers.

One of the last steps in developing an emissions factor is a comparison of the FQI for
different units. The FQI is an indicator of the emissions factor's ability to estimate emissions for
the entire national population, and it is related to both the ITR score and the number of units in
the data set. Once the statistical procedures are complete, the data set is ranked by ITR score
(high to low), and a FQI is developed for each unit in the candidate set. The FQI should
decrease with each emissions unit that is added to the emissions factor pool. When the FQI
increases, only average test values above the point where the FQI increases should be considered
in the factor development. In the development of the emissions factor for THC from CRUs, the
FQI evaluation excluded one unit from the data set (this unit has the lowest ITR score).

The emissions factor is based on the emissions test data for 7 units and is characterized as
Poorly Representative. The emissions factor analysis for CRU THC is provided in worksheet
"EF Creation_THC_CRU_2015 April .xlsm".

Table 4. Overview of the Emissions Factor for THC from CRUs

Emissions test d it lit used

l est met hods

AP-42 Emissions
Tjiclor

kepresenl;iln eness

No. of lost
reports

\o. or
units

8 ab

EPA Method 25A

2.4 x 10"4 lb THC (as
propane)/bbl feed

Poorly

a One CRU was excluded from the data set based on the FQI evaluation.

b The final data set for the emissions factor is based on 7 CRUs. All of the CRUs on which the CRU THC
emissions factor is based are continuous regeneration units. The control devices in the data set include 5
CRUs with scrubbers and 2 CRUs with Chlorsorb.

Table 5. Analysis of Emissions Test Reports for THC from CRUs

1 iicilitv II)
No.

l iicililv n:ime

Emissions
unit

A PC 1)

lest
method

A\er:i»e test
result. Ih
TIIC, sis
prop;ine/hhl
leeil

Ilk

IL2A0420

Marathon Ashland
Petroleum, in
Robinson IL.

16 Platformer

Scrubber

M25A

3.0 x 10"5

KY2A0490

Marathon Ashland
Petroleum, in
Catlettsburg KY

HPCCR

Packed bed
scrubber

M25A

8.8 x 10"6

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l iuililv II)
No.

liicililv 11:1111c

Emissions
unit

A PC 1)

Tost
mot hod

A\er:i«>e lesl
result, Ih
TIIC, 21s
propnne/hhl
feed

Ilk

KY2A0490

Marathon Ashland
Petroleum, in
Catlettsburg KY

LPCCR

Packed bed
scrubber

M25A

7.1 x 10"6

41

MS3C0740

Chevron Refinery, in
Pascagoula MS

CRU79

Chlorsorb

M25A

1.5 x 10"3

41

OK2C0990

TPI Refining
Company Ardmore
Petroleum Refinery
Ardmore OK

CRU400B

Venturi
Scrubber

M25A

1.4 x 10"5

37

TX2B1220

Motiva Enterprises, in
Port Arthur TX

CRU4

Packed bed
scrubber

M25A

1.6 x 10"6

43

TX3B1250

The Premcor Refining
Group, Inc., in Port
Arthur TX

CRU1344

Chlorsorb

M25A

9.0 x 10"5

33

TX3B1310

Valero Refining -
Texas, L.P., in Corpus
Christi TX

CRU

Scrubber

M25A

1.5 x 10"5

34

a This emissions unit was excluded from the data set based on the FQI evaluation.

3.3 Fluid Catalytic Cracking Units - HCN

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for HCN from FCCU units. Each of the available test reports was reviewed, analyzed,
and summarized, and for those test reports included in the emissions factor analysis, given an
ITR score.

3.3.1 Coke Burn Rate Basis

An overview of the emissions factor using a coke burn rate basis is provided in Table 6.

Based on the emissions test report review and analysis, 11 emissions test reports for 11
emissions units had useable data and were included in the development of the emissions factor.
These emissions tests reports are provided in Table 7. A complete list of the available test report
information is provided in worksheet "Test_Data_Sum_HCN_FCCU_2015April.xlsm". For
more detail on the analysis and QA conducted, see the field "QA Notes" for each test report.
The ITR scores for these 11 test reports ranged from 36 to 72. The emissions data (lb HCN/hr)
in these test reports are based on measurements taken with EPA Other Test Method-029 (OTM-
029), EPA Reference Method 320, and in some instances with EPA Conditional Test Method-
033 (CTM-033). Test data using CTM-033 were considered acceptable when the concentration
of sodium hydroxide (NaOH) was high (6.0 N NaOH) and the pH was maintained above 12 for

11

-------
the duration of the test. The test reports included production rate data for the FCCU in lb/hr of
coke burn rate.

Certain test reports were excluded from the emissions factor analysis for the following
reasons: production rate data for coke burn rate were not available or the test method was not
compatible with OTM-029 (i.e., CARB Method 426 test reports and some CTM-033 test reports
were excluded because the tests did not involve the use of the higher concentration NaOH
solution required in OTM-029). Methods that use lower strength caustic solutions are not likely
to measure the full HCN emissions.

EPA's recommended emissions factor development procedures were followed for the
HCN FCCU data. Complete burn and partial burn regenerators may emit different amounts of
HCN, but we are unsure of whether this is true or to what degree the emissions may vary.
Because there are 9 complete regeneration and only 2 partial regeneration units, we could not
perform the statistical analysis to determine whether these units should be subcategorized based
on the type of regenerator. As we are unsure if and to what degree the regenerator type affects
the HCN emissions, we decided to group all FCCUs together for emissions factor development.
Because 7 FCCUs are controlled with scrubbers and 4 FCCUs are controlled with electrostatic
precipitators (ESPs) and it is uncertain what effect each type of control device has on the HCN
emissions, a statistical analysis was performed to determine if these data belong to the same
population. The statistical analysis showed that all of the data belong to the same data set. Also,
while 3 of the FCCUs have CO boilers and 8 of the units do not have CO boilers, the purpose of
the CO boiler is to convert CO to CO2, not to control HCN. However, we performed a statistical
analysis for CO Boilers to determine whether these data belong to the same data set, and the
statistical analysis showed that all of the data belong to the same data set. Therefore, all 11
FCCUs were combined for the emissions factor development. The statistical analysis for
determining outliers in the data set was conducted, and no outliers were found. The emissions
factor is based on the emissions test data for the 11 units and is characterized as Moderately
Representative. The emissions factor analysis for FCCU HCN is provided in worksheet "EF
Creati onHCNF C CU_2 015 April_(Coke_Burn_Rate). xl sm".

Table 6. Overview of the Emissions Factor for HCN from FCCUs (Coke Burn Rate Basis)

Emissions tost to use

lost methods

AP-42 Emissions
I'jictor

RepiTsonliiliMMicss

No. of lesl
reports

No. of units

LPA OTM-lPy,
EPA Method 320;
modified CTM-033

4.3 vlU lb IICMb
coke burn

Modcialcl)

a The final data set for the emissions factor is based on 11 FCCUs. The FCCUs on which the FCCU HCN

emissions factor is based include 9 complete regeneration units and 2 partial regeneration units. There are
3 units with CO boilers, and 8 units with none. The control devices in the data set include 7 scrubbers
and 4 ESPs.

-------
Table 7. Analysis of Emissions Test Reports for HCN from FCCUs (Coke Burn Rate Basis)

l iu-ililv II) No.

Incililv 11:11110

Emissions
1111 it ''

A PC 1)

list
mot hod

A\ersi«e
lost result.
Ih IK \/lh
coke hum

Ilk

CA5AU19U

LwonNlobil Torrance

Refinery, in Torrance,
CA

ICC

LSP

LPA OTM-

029

1.8 x 10

65

HI5A0380

Chevron Product
Company, in Kapolei
HI

FCCU a

ESP

EPA M320/
M301

4.2 x 10"4

72

IL2A0420

Marathon Petroleum
Company Robinson
Refinery, in Robinson,
IL

FCCUb c

Scrubber

EPA OTM-

029

6.2 x 10"5

64

IN2A0440

BP Products, in
Whiting IN

FCCU500 a

ESP

EPA M320

9.5 x 10"6

57

LA3C0560

Citgo Petroleum
Corporation, Lake
Charles Manufacturing
Complex, Lake
Charles, LA

FCCU317 a

Scrubber

EPA OTM-

029

1.2 x 10"3

60

LA3C0610

Marathon Petroleum
Company, in Garyville
LA

Unit 30 a

Scrubber

EPA OTM-

029

2.8 x lO"4

45

MI2A0710

Marathon Petroleum
Company, Detroit
Refinery, in Detroit
MI

FCCU a

ESP

EPA CTM-

033

2.2 x 10"4

43

NJ1A0850

ConocoPhillips
Bayway Refinery, in
Linden NJ

U4FCCUb

, C

Scrubber

EPA CTM-

033

6.3 x 10"5

36

NJ1A0860

Valero Refining
Company, in
Paulsboro, NJ

FCCU1a

Scrubber

Modified
EPA CTM-

033

2.2 x 10"4

61

TX3B1250

Valero Port Arthur
Refinery, in Port
Arthur, TX

FCCU1241

a

Scrubber

EPA OTM-

029

7.7 x 10"4

65

VI6A1530

Hovensa LLC, in
Christiansted, US
Virgin Islands

FCCU a

Scrubber

EPA OTM-

029

1.2 x 10"3

64

a These FCCUs with useable data are complete regeneration units.
b These FCCUs with useable data are partial regeneration units.
c These FCCUs have CO boilers.

13

-------
3.3.2 Feed Rate Basis

An overview of the emissions factor using a feed rate basis is provided in Table 8.

Based on the emissions test report review and analysis, 10 emissions test reports for 10
emissions units had useable data and were included in the development of the emissions factor.
These emissions tests reports are provided in Table 9. A complete list of the available test report
information is provided in worksheet "Test_Data_Sum_HCN_FCCU_2015April.xlsm". For
more detail on the analysis and QA conducted, see the field "QA Notes" for each test report.
The ITR scores for these 10 test reports ranged from 43 to 65. The emissions data (lb HCN/hr)
in these test reports are based on measurements taken with OTM-029, Method 320, and in some
instances with CTM-033. Test data using CTM-033 were considered acceptable when the
concentration of sodium hydroxide (NaOH) was high (6.0 N NaOH) and the pH was maintained
above 12 for the duration of the test. The test reports included production rate data for the FCCU
in bbl/hr feed rate.

Certain test reports were excluded from the emissions factor analysis for the following
reasons: production rate data were not available or the test method was not compatible with
OTM-029 (i.e., CARB Method 426 test reports and some CTM-033 test reports were excluded
because the tests did not involve the use of the higher concentration NaOH solution required in
OTM-029). Methods that use lower strength caustic solutions are not likely to measure the full
HCN emissions.

EPA's recommended emissions factor development procedures were followed for the
HCN FCCU data. Complete burn and partial burn regenerators may emit different amounts of
HCN, but we are unsure of whether this is true or to what degree the emissions may vary.
Because there are 9 complete regeneration units and only 1 partial regeneration unit, we could
not perform the statistical analysis to determine whether these units should be subcategorized
based on the type of regenerator. As we are unsure if and to what degree the regenerator type
affects the HCN emissions, we decided to group all FCCUs together for emissions factor
development. Because 7 FCCUs are controlled with scrubbers and 3 FCCUs are controlled with
ESPs and it is uncertain what effect each type of control device has on the HCN emissions, a
statistical analysis was performed to determine if these data belong to the same population. The
statistical analysis showed that all of the data belong to the same data set. Also, while 2 of the
FCCUs have CO boilers and 8 of the units do not have CO boilers, the purpose of the CO boiler
is to convert CO to CO2, not to control HCN. There is no data indicating that the CO boiler has a
significant impact on the HCN emissions. (Note: The statistical analysis for CO Boilers under
the coke burn rate emissions factor showed that all of the data belong to the same data set.)
Therefore, all 10 FCCUs were combined for the emissions factor development. The statistical
analysis for determining outliers in the data set was conducted, and no outliers were found. The
emissions factor is based on the emissions test data for the 10 units and is characterized as
Moderately Representative. The emissions factor analysis for FCCU HCN is provided in
worksheet "EF Creation_HCN_FCCU_2015April_(Feed_Rate).xlsm".

-------
Table 8. Overview of the Emissions Factor for HCN from FCCUs (Feed Rate Basis)

Emissions tost d:it;i to use

lost methods

AIM2 Emissions
Tjictor

Represent:ili\eness

No. of lesl
reports

No. of units

10

10 a

EPA OTM-029;
CTM-033

7.0 x 10"3 lb HCN/bbl
feed

Moderately

a The final data set for the emissions factor is based on 10 FCCUs. The FCCUs on which the FCCU HCN
emissions factor is based include 9 FCCUs with complete regeneration and 1 FCCU with partial
regeneration. The control devices in the data set include 7 FCCU with scrubbers and 3 with ESPs.

Table 9. Analysis of Emissions Test Reports for HCN from FCCUs (Feed Rate Basis)

1 iicilitv II) No.

l-iicililv 11:11110

Emissions
unit

AI'CI)

list
mot hod

A\ersi«e
lost result

,1b
IK N/hhl
looil

Ilk

CA5AU19U

LwonNlobil Torrance

Refinery, in Torrance,
CA

ICC

LSP

LPA OTM-

029

3.1 \ 1U

t>5

IL2A0420

Marathon Petroleum
Company Robinson
Refinery, in Robinson,
IL

FCCUb c

Scrubber

EPA OTM-

029

1.0 x 10"3

64

IN2A0440

BP Products, in
Whiting IN

FCCU500 a

ESP

EPA M320

1.4 x 10"4

57

LA3C0560

Citgo Petroleum
Corporation, Lake
Charles Manufacturing
Complex, Lake
Charles, LA

FCCU317 a

Scrubber

EPA OTM-

029

1.5 x 10"2

60

LA3C0610

Marathon Petroleum
Company, in Garyville
LA

Unit 30 a

Scrubber

EPA OTM-

029

3.8 x 10"3

45

MI2A0710

Marathon Petroleum
Company, Detroit
Refinery, in Detroit
MI

FCCU a

ESP

EPA CTM-

033

2.9 x 10"3

43

NJ1A0820

Hess Corporation, Port
Reading Refinery, in
Port Reading, NJ

FCCU-
PT1-A a

Scrubber

EPA CTM-

033

4.7 x 10"3

57

NJ1A0860

Valero Refining
Company, in
Paulsboro, NJ

FCCU1a

Scrubber

EPA CTM-

033

3.8 x 10"3

61

15

-------
1 iicilitv II) No.

l-iicililv 11:11110

Emissions
unit

AI'C'I)

Test
mot hod

Amtsirc
lost result

,1b
IK'N/hhl
leed

Ilk

TX3B1250

Valero Port Arthur
Refinery, in Port
Arthur, TX

FCCU1241

Scrubber

EPA OTM-

029

1.4 x 10"2

VI6A1530

Hovensa LLC, in
Christiansted, US
Virgin Islands

FCCU a

Scrubber

EPA OTM-

029

2.2 x 10"2

a These FCCUs are complete regeneration units.
b This FCCU is a partial regeneration unit.
c These FCCUs have CO boilers.

3.4 Sulfur Recovery Units - CO

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for CO from SRU units. Each of the available test reports was reviewed, analyzed, and
summarized, and for those test reports included in the emissions factor analysis, given an ITR
score.

3.4.1 Heat Rate Basis

An overview of the emissions factor using a heat rate basis is provided in Table 10.

Based on the emissions test report review and analysis, 25 emissions test reports for 24
emissions units had useable data and were included in the development of the emissions factor.
Several test reports provide emissions test data for SRU that share a common stack. When
emissions testing is conducted on more than one SRU that share a common stack, the emissions
units are counted as one "unit"; the total emissions rate is divided by the total production rate of
all SRU venting to the stack when developing the units' average test results.

The emissions test reports used in the factor analysis are provided in Table 11. A
complete list of the available test report information is provided in worksheet
"Test_Data_Sum_CO_SRU_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The ITR scores for these 25 test reports
ranged from 35 to 56. The emissions data (lb CO/hr) in these test reports are based on
measurements taken with EPA Method 10 (M10), and the test reports included heat rate data for
the SRU in mmBtu/hr.

Certain test reports were excluded from the emissions factor analysis because heat rate
data are not available or the concentration data for the test run average in the test report is a
negative value.

-------
EPA's recommended emissions factor development procedures were followed for the
SRU CO data. The SRUs in the data set include 15 SRU that are Claus units with SCOT tail gas
treatment units, 2 SRUs that are Claus units with Beavon tail gas treatment units, 1 SRU that is a
Claus unit with Sulften tail gas treatment units, 1 SRU that is a Claus unit with a Resulf tail gas
treatment unit, and 5 SRUs that are Claus units. All 24 of the SRUs have either an incinerator or
a thermal oxidizer as the control device. Both incinerators and thermal oxidizers work on the
same principles of combustion, and these terms are often used interchangeably by field staff. As
such, there is no reason to believe that these control devices would have differing levels of CO
emissions. Therefore, all of these units were combined for emissions factor development. The
statistical analysis for determining outliers in the data set was conducted, and no data values
were found to outliers.

As previously discussed, one of the last steps in developing an emissions factor is a
comparison of the FQI for different units. In the development of the emissions factor for CO
from SRUs, the FQI evaluation excluded two units from the data set (these two units have the
lowest ITR scores).

The emissions factor is based on the emissions test data for 24 units and is characterized
as Moderately Representative. The emissions factor analysis for SRU CO is provided in
spreadsheet "EF Creation_CO_SRU_2015April_(Heat_Rate).xlsm".

Table 10. Overview of the Emissions Factor for CO from SRUs (Heat Rate Basis)

Emissions test d;it:i lo use

Test methods

AP-42 Kmissions
Tjiclor

Represent ill neness

No. of losl
reports

No. of units

LIW Method 1U

U.71 lb CO mmBlu

Modcialcl)

a Two SRUs were excluded from the data set based on the FQI evaluation.

b The final data set for the emissions factor is based on 22 SRUs. The SRUs on which the SRU CO

emissions factor is based include 13 SRUs with SCOT tail gas treatment units, 2 SRUs with Beavon tail
gas treatment units, 1 SRU with Sulften tail gas treatment unit, 1 SRU with Resulf tail gas treatment unit,
and 5 SRUs that are Claus units. The control devices in the data set include 22 SRUs with incinerators or
thermal oxidizers.

Table 11. Analysis of Emissions Test Reports for CO from SRUs (Heat Rate Basis)

1¦acilitv II)
No.

I ncililv iiiime

Emissions unit

AI'C'I)

Test
method

A\ern»e test
results. Ih
CO/mm lit ii

Ilk

CA5A0120

BP West Coast
Products, Carson,
California

TGU1 e

Incinerator

SCAQMD
100.1

0.37

CA5A0120

BP West Coast
Products, Carson,
California

TGU2 e

Incinerator

SCAQMD
100.1

1.4

-------
1 iicililv II)
No.

I ncililv iiitmc

Emissions unit

AI'C'I)

Test
modioli

A\crsi{»o test
results, Ih
CO/m in lit ii

Ilk

CA5AU19U

ExxonMobil
Torrance Refinery,
Torrance, California

SRI 2 91'4

Incinu'iiloi'

S( AQMI)

100.1

1.6

46

DE1A0360
(2006)f

Valero Delaware
City Refinery, The
Premcor Refining
Group

SRU1 a

Thermal
oxidizer

M10

0.000836

4

DE1A0360
(2009)f

Valero Delaware
City Refinery, The
Premcor Refining
Group

SRU1 a

Thermal
oxidizer

M10

0.0022

56

DE1A0360
(2006)f

Valero Delaware
City Refinery, The
Premcor Refining
Group

SRU2 a

Thermal
oxidizer

M10

0.0023

4

DE1A0360
(2009)f

Valero Delaware
City Refinery, The
Premcor Refining
Group

SRU2 a

Thermal
oxidizer

M10

0.026

56

LA3C0610

Marathon
Petroleum
Company LLC,
Garyville,
Louisiana

SRU220b

Thermal
oxidizer

M10

0.048

50

LA3C0610

Marathon
Petroleum
Company LLC,
Garyville,
Louisiana

SRU234b

Thermal
oxidizer

M10

0.093

50

LA3C0630

Motiva Enterprises,
Norco Refinery,
Norco, Louisiana

SRU S3 a

Incinerator

M10

0.013

48

LA3C0650

Valero Refining -
New Orleans, LLC.
St. Charles
Refinery, Norco,
Louisiana

SRU1600 a

Thermal
oxidizer

M10

0.083

45

LA3C0650

Valero Refining -
New Orleans, LLC.
St. Charles
Refinery, Norco,
Louisiana

SRU30 a

Thermal
oxidizer

M10

0.17

41

18

-------
1 iicililv II)
No.

I ncililv iiitmc

Emissions unit

AI'C'I)

Test
modioli

A\crsi{»o test
results, Ih
CO/m in lit ii

Ilk

OK2C0990

Total Petroleum,
Inc. Ardmore
Refinery -
Ardmore,
Oklahoma

SRU1 (500A)a

Incinerator

M10

0.023

43

TX3A1230

ConocoPhillips
Borger Petroleum
Refinery, Borger,
Texas

SRU43 a

Incinerator

M10

0.047

46

TX3B1110

BP Products North
America Inc., Texas
City, Texas

SRUa

Incinerator

M10

1.3

44

TX3B1131

Citgo Refining and
Chemicals
Company, Corpus
Christi, Texas

West Plant SRU

a

Incinerator

M10

0.19

52

TX3B1140

Valero Refining -
Texas, L P. East
Plant of Bill
Greehey Refinery,
Corpus Christi,
Texas

SRU2 a

Incinerator

M10

0.064

49

TX3B1220

Motiva Enterprises,
LLC, Port Arthur,
Texas

SRU2&3
combined a

Incinerator

M10

0.026

48

TX3B1240

ConocoPhillips
Company, Sweeny
Refinery, Old
Ocean, Texas

EPN 28.2

Incinerator

M10

0.0070

48

TX3B1250

Valero Port Arthur
Refinery, Port
Arthur, Texas

SRU543 a

Incinerator

M10

5.6

49

TX3B1250
(2009)

Valero Port Arthur
Refinery, Port
Arthur, Texas

SRU544 a

Incinerator

M10

0.75

49

TX3B1250
(2011)

Valero Port Arthur
Refinery, Port
Arthur, Texas

SRU544 a

Incinerator

M10

0.64

46

TX3B1250

Valero Port Arthur
Refinery, Port
Arthur, Texas

SRU545 a

Incinerator

M10

0.46

49

19

-------
1 iicililv II)
No.

I ncililv n;imc

Emissions iiiiit

AI'C'I)

Test
mot hod

A\crsi{»o test
results, Ih
CO/m m lit ii

Ilk

TX3B1250

Valero Port Arthur
Refinery, Port
Arthur, Texas

SRU546 a

Incinerator

M10

0.22

TX3B1310

Valero Refining,
Bill Greehey
Refinery - West
Plant, Corpus
Christi, Texas

SRU 1&2 Sulften

Incinerator

M10

2.8

TX3B1320

Valero Refining -
Texas, Houston
Refinery, Houston
Texas

Unit 46 SRU e

Incinerator

M10

0.30

TX3B1320

Valero Refining -
Texas, Houston
Refinery, Houston
Texas

Unit 39 SRU e

Incinerator

M10

0.12

a These SRUs are Claus units with SCOT tail gas treatment units.
b These SRUs are Claus units with Beavon tail gas treatment units.
c These SRUs are Claus units Sulften tail gas treatment units.
d These SRUs are Claus units with Resulf tail gas treatment units.
e These SRUs are Claus units.

f This emissions unit was excluded from the data set based on the FQI evaluation.

3.4.2 Sulfur Production Rate Basis

An overview of the emissions factor using a sulfur production basis is provided in
Table 12.

Based on the emissions test report review and analysis, 23 emissions test reports for 23
emissions units had useable data and were included in the development of the emissions factor.
Several test reports provide emissions test data for SRU that share a common stack. When
emissions testing is conducted on more than one SRU that share a common stack, the emissions
units are counted as one "unit"; the total emissions rate is divided by the total production rate of
all SRU venting to the stack when developing the units' average test results.

The emissions test reports used in the factor analysis are provided in Table 13. A
complete list of the available test report information is provided in worksheet
"Test_Data_Sum_CO_SRU_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The ITR scores for these 23 test reports
ranged from 38 to 53. The emissions data (lb CO/hr) in these test reports are based on
measurements taken with EPA Method 10 (M10), and the test reports included production rate
data for the SRU in ton/hr sulfur production.

-------
Certain test reports were excluded from the emissions factor analysis because production
rate data are not available, the concentration data for the test run average in the test report is a
negative value, or the SRU did not have controls consistent with the other units (e.g., 2 SRU had
no controls).

EPA's recommended emissions factor development procedures were followed for the
SRU CO data. The SRUs in the data set include 19 SRU that are Claus units with SCOT tail gas
treatment units, 2 SRUs that are Claus units with Beavon tail gas treatment units, 1 SRU that is a
Claus unit with Sulften tail gas treatment units, and 1 SRU that is a Claus unit with Resulf tail
gas treatment unit. All 23 SRUs have either an incinerator or a thermal oxidizer as the control
device. Both incinerators and thermal oxidizers work on the same principles of combustion, and
these terms are often used interchangeably by field staff. As such, there is no reason to believe
that these control devices would have differing levels of CO emissions. Therefore, all of these
units were combined for emissions factor development. The statistical analysis for determining
outliers in the data set was conducted, and no data were found to be outliers. The emissions
factor is based on the emissions test data for 23 units and is characterized as Moderately
Representative. The emissions factor analysis for SRU CO is provided in spreadsheet "EF
Creation_CO_SRU_2015April_(Sulf_Prod).xlsm".

Table 12. Overview of the Emissions Factor for CO from SRUs (Sulfur Production Rate
Basis)

Emissions test d;it:i lo use

Test methods

AP-42 Kmissions
Tjiclor

Represent ill neness

No. of losl
reports

No. of units

23 a

EPA Method 10

1.3 lb CO/ton sulfur

Moderately

a The final data set for the emissions factor is based on 23 SRUs. The SRUs on which the SRU CO
emissions factor is based include 19 SRUs with SCOT tail gas treatment units, 2 SRUs with Beavon tail
gas treatment units, 1 SRU with a Sulften tail gas treatment unit, and 1 SRU with a Resulf tail gas
treatment unit. The control devices in the data set include 23 SRUs with incinerators or thermal
oxidizers.

Table 13. Analysis of Emissions Test Reports for CO from SRUs (Sulfur Production Rate
Basis)

1 iicilily II)
No.

l iicililv n:ime

Emissions unit

AI'CI)

lest
method

A\ersi»e
test results.
Ih CO/ton
sul I'll r

Ilk

LA3C0610

Marathon Petroleum
Company LLC,
Garyville, Louisiana

SRU220b

Thermal
oxidizer

M10

0.10

LA3C0610

Marathon Petroleum
Company LLC,
Garyville, Louisiana

SRU234b

Thermal
oxidizer

M10

0.21

-------
1 iu-ilily II)
No.

l iicililv iiiime

Emissions unit

AI'C'I)

lost
method

A\eni«>e
lest results,
Ih CO/ton
sul I'u r

Ilk

LA3C0630

Motiva Enterprises,
Norco Refinery,
Norco, Louisiana

SRU S3 a

Incinerator

M10

0.053

48

LA3C0650

Valero Refining -
New Orleans, LLC.
St. Charles Refinery,
Norco, Louisiana

SRU1600 a

Thermal
oxidizer

M10

0.47

45

LA3C0650

Valero Refining -
New Orleans, LLC.
St. Charles Refinery,
Norco, Louisiana

SRU303

Thermal
oxidizer

M10

0.35

41

MS3C0740

ChevronTexaco
Pascagoula Refinery,
Pascagoula,
Mississippi

SRU2 (F-2745)

a

Thermal
Oxidizer

M10

0.24

47

MS3C0740

ChevronTexaco
Pascagoula Refinery,
Pascagoula,
Mississippi

SRU3 (F-2765)

a

Thermal
Oxidizer

M10

0.20

47

OK2C0990

Total Petroleum, Inc.
Ardmore Refinery,
Ardmore, Oklahoma

SRUl (500A)a

Incinerator

M10

0.038

43

OK2C0990

Total Petroleum, Inc.
Ardmore Refinery -
Ardmore, Oklahoma

SRU2 (560A)a

Incinerator

M10

0.0061

44

TX3A1190

Delek Refining, LTD.
Tyler Refinery, Tyler,
Texas

SRU1/SRU2
TGI2a

Incinerator

M10

0.36

38

TX3A1230

ConocoPhillips
Borger Petroleum
Refinery, Borger,
Texas

SRU43a

Incinerator

M10

0.38

46

TX3A1300 e

Valero McKee
Refinery, Sunray,
Texas

EPN V-16 [Unit
830] a

Incinerator

M10

8.2

51

TX3A1300 e

Valero McKee
Refinery, Sunray,
Texas

EPN V-16 [Unit
830] a

Incinerator

M10

7.1

51

TX3A1300

Valero McKee
Refinery, Sunray,
Texas

EPN V-5 [Unit
820] a

Incinerator

M10

0.065

51

22

-------
1 iu-ilily II)
No.

l itcililx iiiime

Emissions unit

AI'C'I)

lost
method

A\eni«>e
lest results,
Ih CO/ton
sul I'u r

Ilk

TX3B1090

Total Petrochemicals
USA, Inc., Port
Arthur, Texas

SRU1&23

Thermal
Oxidizer

M10

2.0

46

TX3B1110

BP Products North
America Inc., Texas
City, Texas

SRUa

Incinerator

M10

1.7

44

TX3B1140

Valero Refining -
Texas, L P. East
Plant of Bill Greehey
Refinery, Corpus
Christi, Texas

SRU2a

Incinerator

M10

0.061

49

TX3B1220

Motiva Enterprises,
LLC, Port Arthur,
Texas

SRU2&3
combineda

Incinerator

M10

0.032

48

TX3B1240

ConocoPhillips
Company, Sweeny
Refinery, Old Ocean,
Texas

EPN 28.2 d

Incinerator

M10

0.057

48

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU543 a

Incinerator

M10

7.7

49

TX3B1250
(2009 test)

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU544a

Incinerator

M10

1.4

49

TX3B1250
(2011 test)

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU544a

Incinerator

M10

5.3

46

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU545a

Incinerator

M10

0.42

49

TX3B1310

Valero Refining, Bill
Greehey Refinery -
West Plant, Corpus
Christi, Texas

SRUl&2Sulften

C

Incinerator

M10

2.6

38

TX3B1310

Valero Refining, Bill
Greehey Refinery -
West Plant, Corpus
Christi, Texas

SRU3a

Incinerator

M10

1.3

53

23

-------

A\eni«>e

lest results.

1 iH-ililY II)

lost

Ih CO/ton

No.

l iicililv iiiime

Emissions unit

AI'C'I)

method

sul I'u r

Ilk

a These SRUs are Claus units with SCOT tail gas treatment units.
b These SRUs are Claus units with Beavon tail gas treatment units.
c These SRUs are Claus units with Sulfiten tail gas treatment units.
d These SRUs are Claus units with Resulf tail gas treatment units.

e Data is for same unit from same test report. Separate sets of test runs occurred on multiple days and
were reported separately.

3.5 Sulfur Recovery Units - NOx

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for NOx from SRU units. Each of the available test reports was reviewed, analyzed, and
summarized, and for those test reports included in the emissions factor analysis, given an ITR
score.

3.5.1 Heat Rate Basis

An overview of the emissions factor using a heat rate basis is provided in Table 14.

Based on the emissions test report review and analysis, 25 emissions test reports for 26
emissions units had useable data and were included in the development of the emissions factor.
Two test reports provide emissions test data for SRU that share a common stack. When
emissions testing is conducted on more than one SRU that share a common stack, the emissions
units are counted as one "unit"; the total emissions rate is divided by the total production rate of
all SRU venting to the stack when developing the units' average test results. The majority of the
testing was conducted since 2005, although one test report is from 1996.

The emissions test reports used in the factor analysis are provided in Table 15. A
complete list of the available test report information is provided in worksheet
"Test_Data_Sum_NOx_SRU_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The ITR scores for these 25 test reports
ranged from 30 to 56. The emissions data (lb NOx/hr) in these test reports are based on
measurements taken with EPA Method 7E (M7E), and the test reports included heat rate data for
the SRU in mmBtu/hr.

Certain test reports were excluded from the emissions factor analysis because heat rate
data are not available.

EPA's recommended emissions factor development procedures were followed for the
SRU NOx data. The SRUs in the data set include 20 SRU that are Claus units with SCOT tail
gas treatment units, 2 SRUs that are Claus units with Beavon tail gas treatment units, 1 SRU that
is a Claus unit with Resulf tail gas treatment unit, 1 SRU that is a Claus unit with Sulften tail gas
treatment unit, and 2 SRUs that are Claus units. All 26 SRU units have either an incinerator or a

-------
thermal oxidizer as the control device. Both incinerators and thermal oxidizers work on the same
principles of combustion, and these terms are often used interchangeably by field staff. As such,
there is no reason to believe that these control devices would have differing levels of NOx
emissions. Therefore, all of these units were combined for emissions factor development. The
statistical analysis for determining outliers in the data set was conducted, and no data values
were found to be outliers. The emissions factor was based on the emissions test data for 26 units
and is characterized as Moderately Representative. The emissions factor analysis for SRU NOx
is provided in spreadsheet "EF Creation_NOx_SRU_2015April_(Heat_Rate).xlsm".

Table 14. Overview of the Emissions Factor for NOx from SRUs (Heat Rate Basis)

Emissions lesl il;il:i lo use

l osl hum hods

AP-42 I'.iiiissions
l";ie(or

Kepreseiiliili\eness

No. of (cs(
reports

No. ol' miils

26 a

EPA Method 7E

0.10 lb NOx/mmBtu

Moderately

a The final data set for the emissions factor is based on 26 SRUs. The SRUs on which the SRU NOx
emissions factor is based include 20 SRUs with SCOT tail gas treatment units, 2 SRUs with Beavon tail
gas treatment units, 1 SRU with a Resulf tail gas treatment unit, 1 SRU with a Sulften tail gas treatment
unit, and 2 SRUs that are Claus units. The control devices in the data set include 26 SRUs with
incinerators or thermal oxidizers.

Table 15. Analysis of Emissions Test Reports for NOx from SRUs (Heat Rate Basis)

I-iicilily II)
No.

l-'iicililv ii:iinc

Emissions unit

AI'C'I)

Tesl
met hod

A\er:i»e lesl

results, Ih
N()\/iii in lilu

Ilk

DE1A0360
(2006)

Valero Delaware City
Refinery, The
Premcor Refining
Group

2 8-SRU 1 a

Thermal
Oxidizer

M7E

0.0029

DE1A0360
(2009)

Valero Delaware City
Refinery, The
Premcor Refining
Group

2 8-SRU 1 a

Thermal
Oxidizer

M7E

0.23

DE1A0360
(2006)

Valero Delaware City
Refinery, The
Premcor Refining
Group

28-SRU2 a

Thermal
Oxidizer

M7E

0.030

DE1A0360
(2009)

Valero Delaware City
Refinery, The
Premcor Refining
Group

28-SRU2 a

Thermal
Oxidizer

M7E

0.072

LA3C0610

Marathon Petroleum
Company LLC,
Garyville, Louisiana

SRU220b

Thermal
Oxidizer

M7E

0.14

-------
I-iicilily II)
No.

l-'iicililv name

Emissions unit

AI'C'I)

Tesl
mot hod

A\erase tesl

results, Ih
N()\/iii in I5l u

Ilk

LA3C0610

Marathon Petroleum
Company LLC,
Garyville, Louisiana

SRU234b

Thermal
Oxidizer

M7E

0.10

50

LA3C0630

Norco Refinery,
Motiva Enterprises, in
Norco, Louisiana

SRU S3a

Incinerator

M7E

0.14

48

LA3C0640

Meraux Refinery,
Murphy Oil USA,
Meraux, Louisiana

SRU2a

Thermal
Oxidizer

M7E

0.077

40

LA3C06503

Valero Refining -
New Orleans, LLC,
St. Charles Refinery,
Norco, Louisiana

SRU 1600 a

Thermal
Oxidizer

M7E

0.15

50

LA3C0650

Valero Refining -
New Orleans, LLC,
St. Charles Refinery,
Norco, Louisiana

SRU30 a

Thermal
Oxidizer

M7E

0.063

46

MT4A0770

CHS, Inc. Laurel
Refinery, Laurel,
Montana

Zone D SRUa

Thermal
Oxidizer

M7E

0.029

42

OK2C0990

Total Petroleum, Inc.
Ardmore Refinery -
Ardmore, Oklahoma

SRU1 (500A)a

Incinerator

M7E

0.078

49

TX3A1230

ConocoPhillips
Borger Petroleum
Refinery, Borger,
Hutchinson County,
Texas

SRU34 a

Incinerator

M7E

0.13

50

TX3A1230

ConocoPhillips
Borger Petroleum
Refinery, Borger,
Hutchinson County,
Texas

SRU43a

Incinerator

M7E

0.015

50

TX3B1110

BP Products North
America Inc., Texas
City, Texas

SRU a

Incinerator

M7E

0.16

48

TX3B1131

Laurel Refinery,
Laurel, Montana.

West Plant SRU

a

Incinerator

M7E

0.13

52

TX3B1140

Valero Refining -
Texas, L.P. East Plant
of Bill Greehey
Refinery, Corpus
Christi, Texas

SRU1 a

Incinerator

M7E

0.12

52

26

-------
I-iicilily II)
No.

l-'iicililv name

Emissions unit

AI'C'I)

Tesl
mot hod

A\erase tesl

results, Ih
N()\/iii in I5l u

Ilk

TX3B1140

Valero Refining -
Texas, L.P. East Plant
of Bill Greehey
Refinery, Corpus
Christi, Texas

SRU2 a

Incinerator

M7E

0.064

52

TX3B1220

Motiva Enterprises,
LLC, Port Arthur,
Texas

SRU2&3 a

Incinerator

M7E

0.11

52

TX3B1220

Motiva Enterprises,
LLC, Port Arthur,
Texas

SRU4 a

Incinerator

M7E

0.18

52

TX3B1240

ConocoPhillips
Company, Sweeny
Refinery, Old Ocean,
Texas

EPN 28.2 c

Incinerator

M7E

0.025

45

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU543 a

Incinerator

M7E

0.056

56

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU544 a

Incinerator

M7E

0.063

52

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU545 a

Incinerator

M7E

0.069

52

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU546 a

Incinerator

M7E

0.086

49

TX3B1310

Valero Refining, Bill
Greehey Refinery -
West Plant, Corpus
Christi, Texas

SRUl&2Sulften

d

Incinerator

M7E

0.099

44

TX3B1320

Valero Refining -
Texas, Houston
Refinery, Houston,
Texas

Unit 46 SRU
(EPN

46CB6301)e

Incinerator

M7E

0.25

48

TX3B1320

Valero Refining -
Texas, Houston
Refinery, Houston,
Texas

Unit 39 SRU
(EPN

39CB2001)e

Incinerator

M7E

0.11

48

27

-------

A\erase tesl

I-iicililv II)

Tesl

results, Ih

No.

Incililv inline

Emissions unit

AI'C'I)

mot hod

N()\/iii in I5l u

Ilk

a These SRUs are Claus units with SCOT tail gas treatment units.

b These SRUs are Claus units with Beavon tail gas treatment units

c These SRUs are Claus units with Resulf tail gas treatment units.

d These SRUs are Claus units Sulfiten tail gas treatment units.

e These SRUs are Claus units.

3.5.2 Sulfur Production Rate Basis

An overview of the emissions factor using a sulfur production basis is provided in
Table 16.

Based on the emissions test report review and analysis, 24 emissions test reports for 26
emissions units had useable data and were included in the development of the emissions factor.
Several test reports provide emissions test data for SRU that share a common stack. When
emissions testing is conducted on more than one SRU that share a common stack, the emissions
units are counted as one "unit"; the total emissions rate is divided by the total production rate of
all SRU venting to the stack when developing the units' average test results. The majority of the
testing was conducted since 2005, although one test report is from 1996.

The emissions test reports used in the factor analysis are provided in Table 17. A
complete list of the available test report information is provided in worksheet
"Test_Data_Sum_NOx_SRU_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The ITR scores for these 24 test reports
ranged from 41 to 56. The emissions data (lb NOx/hr) in these test reports are based on
measurements taken with EPA Method 7E (M7E), and the test reports included production rate
data for the SRU in ton/hr sulfur production.

Certain test reports were excluded from the emissions factor analysis because production
rate data are not available.

EPA's recommended emissions factor development procedures were followed for the
SRU NOx data. The SRUs in the data set include 22 SRU that are Claus units with SCOT tail
gas treatment units, 2 SRUs that are Claus units with Beavon tail gas treatment units,, 1 SRU that
is a Claus unit with a Sulften tail gas treatment unit, and 1 SRU that is a Claus unit with a Resulf
tail gas treatment unit. All 26 SRUs have either an incinerator or a thermal oxidizer as the
control device. Both incinerators and thermal oxidizers work on the same principles of
combustion, and these terms are often used interchangeably by field staff. As such, there is no
reason to believe that these control devices would have differing levels of NOx emissions.
Therefore, all of these units were combined for emissions factor development. The statistical
analysis for determining outliers in the data set was conducted, and no data were found to be
outliers. The emissions factor was based on the emissions test data for 26 units and is

-------
characterized as Moderately Representative. The emissions factor analysis for SRU NOx is
provided in spreadsheet "EF Creation_NOx_SRU_2015April_(Sulf_Rate).xlsm".

Table 16. Overview of the Emissions Factor for NOx from SRUs (Sulfur Production Rate
Basis)

Emissions lost d;it;i to use

l osl hum hods

AP-42 1'missions
l-'iicloi'

Ko|)ivsciiliili\oncss

N». of lost
reports

No. of iiiiiIs

26 a

EPA Method 7E

2.2 x 101 lb
NOx/ton sulfur

Moderately

a The final data set for the emissions factor is based on 26 SRUs. The SRUs on which the SRU NOx
emissions factor is based include 22 SRUs with SCOT tail gas treatment units, 2 SRUs with Beavon tail
gas treatment units, 1 SRU with a Sulften tail gas treatment unit, and 1 SRU with a Resulf tail gas
treatment unit. The control devices in the data set include 26 SRUs with incinerators or thermal
oxidizers.

Table 17. Analysis of Emissions Test Reports for NOx from SRUs (Sulfur Production Rate
Basis)

l-~ II)
No.

l-iicililv 11:11110

Emissions unit

AI'C'I)

lost
mot hod

A\orsi«»o

tost
results, lb
N()\/ton
sul I'u r

Ilk

LA3C0610

Marathon Petroleum
Company LLC,
Garyville, Louisiana

SRU220b

Thermal
Oxidizer

M7E

0.32

LA3C0610

Marathon Petroleum
Company LLC,
Garyville, Louisiana

SRU234b

Thermal
Oxidizer

M7E

0.24

LA3C0630

Motiva Enterprises,
Norco Refinery,
Norco, Louisiana.

SRU S3 a

Incinerator

M7E

0.54

LA3C06503

Valero Refining - New
Orleans, LLC, St.
Charles Refinery,
Norco, Louisiana

SRU 1600 a

Thermal
Oxidizer

M7E

0.87

LA3C0650

Valero Refining - New
Orleans, LLC, St.
Charles Refinery,
Norco, Louisiana

SRU30 a

Thermal
Oxidizer

M7E

0.13

MS3C0740

ChevronTexaco
Pascagoula Refinery,
Pascagoula,
Mississippi

SRU2 (F-2745)

Thermal
Oxidizer

M7E

0.23

-------
1"ncilitv II)
No.

l-iicililv 11:11110

Emissions unit

AI'C'I)

lost
mot hod

A\ersi«»e

losl
results, Ih
\()\/lOll
sul I'u r

Ilk

MS3C0740

ChevronTexaco
Pascagoula Refinery,
Pascagoula,
Mississippi

SRU3 (F-2765)

a

Thermal
Oxidizer

M7E

0.13

47

OK2C0990

Total Petroleum, Inc.
Ardmore Refinery -
Ardmore, Oklahoma

SRUl (500A)a

Incinerator

M7E

0.13

49

OK2C0990

Total Petroleum, Inc.
Ardmore Refinery -
Ardmore, Oklahoma

SRU2 (560A)a

Incinerator

M7E

0.30

48

TX3A1190

Delek Refining, LTD.
Tyler Refinery, Tyler,
Texas

SRU1/SRU2
TGI2

Incinerator

M7E

0.27

38

TX3A1230

ConocoPhillips Borger
Petroleum Refinery,
Borger, Hutchinson
County, Texas

SRU34 a

Incinerator

M7E

0.32

50

TX3A1230

ConocoPhillips Borger
Petroleum Refinery,
Borger, Hutchinson
County, Texas

SRU43 a

Incinerator

M7E

0.12

50

TX3A1300

Valero McKee
Refinery, Sunray,
Texas

EPN V-5 [Unit
820] a

Incinerator

M7E

0.27

54

TX3A1300

e

Valero McKee
Refinery, Sunray,
Texas

EPN V-16 [Unit
830] a

Incinerator

M7E

0.21

54

TX3A1300

e

Valero McKee
Refinery, Sunray,
Texas

EPN V-16 [Unit
830] a

Incinerator

M7E

0.17

54

TX3B1090

Total Petrochemicals
USA, Inc., Port
Arthur, Texas

SRU1&2 a

Incinerator

M7E

0.21

49

TX3B1110

BP Products North
America Inc., Texas
City, Texas

SRU a

Incinerator

M7E

0.21

48

TX3B1140

Valero Refining -
Texas, L.P. East Plant
of Bill Greehey
Refinery, Corpus
Christi, Texas

SRUl a

Incinerator

M7E

0.25

52

30

-------
1"ncilitv II)
No.

l-iicililv mime

Emissions unit

AI'C'I)

lost
mot hod

A\orsi«»o

losl
rosiills, Ih
\()\/tOll
sul I'u r

Ilk

TX3B1140

Valero Refining -
Texas, L.P. East Plant
of Bill Greehey
Refinery, Corpus
Christi, Texas

SRU2 a

Incinerator

M7E

0.062

TX3B1220

Motiva Enterprises,
LLC, Port Arthur,
Texas

SRU2&3 a

Incinerator

M7E

0.13

TX3B1220

Motiva Enterprises,
LLC, Port Arthur,
Texas

SRU4 a

Incinerator

M7E

0.14

TX3B1240

ConocoPhillips
Company, Sweeny
Refinery, Old Ocean,
Texas

EPN 28.2 c

Incinerator

M7E

0.20

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU543 a

Incinerator

M7E

0.085

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU544 a

Incinerator

M7E

0.12

TX3B1250

Valero Port Arthur
Refinery, Port Arthur,
Texas

SRU545 a

Incinerator

M7E

0.086

TX3B1310

Valero Refining, Bill
Greehey Refinery -
West Plant, Corpus
Christi, Texas

SRUl&2Sulften

Incinerator

M7E

0.093

TX3B1310

Valero Refining, Bill
Greehey Refinery -
West Plant, Corpus
Christi, Texas

SRU3 a

Incinerator

M7E

0.22

a These SRUs are Claus units with SCOT tail gas treatment units.
b These SRUs are Claus units with Beavon tail gas treatment units.
c This SRU is a Claus unit with a Resulf tail gas treatment unit.
d These SRUs are Claus units Sulfiten tail gas treatment units.

e Data is for same unit from same test report. Separate sets of test runs occurred on multiple days and
were reported separately.

-------
3.6 Sulfur Recovery Units - THC

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for THC from SRU units. Each of the available test reports was reviewed, analyzed, and
summarized, and for those test reports included in the emissions factor analysis, given an ITR
score.

3.6.1 Heat Rate Basis

An overview of the emissions factor using a heat rate basis is provided in Table 18.

Based on the emissions test report review and analysis, 9 emissions test reports for 10
emissions units had useable data and were included in the development of the emissions factor.
The majority of the testing was conducted since 2005, although one test report is from 1996.

The emissions test reports used in the factor analysis are provided in Table 19. A
complete list of the available test report information is provided in worksheet
"Test_Data_Sum_THC_SRU_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The ITR scores for these 9 test reports
ranged from 4 to 44. The emissions data (lb THC [as propane]/hr) in these test reports are based
on measurements taken with EPA Method 25A (M25A), and the test reports included heat rate
data for the SRU in mmBtu/hr.

Certain test reports were excluded from the emissions factor analysis because heat rate
data are not available, the concentration data for the test run average in the test report is a
negative or zero value, or the test method was not compatible with THC measurements taken
with M25A (i.e., M18 test reports and SCAQMD M25.3 test reports were excluded because
these methods measure specific compounds where M25A counts total carbon).

EPA's recommended emissions factor development procedures were followed for the
SRU THC data. EPA examined any population differences related to the process types and
control devices. There are 8 SRUs that are Claus units with SCOT tail gas treatment units, and
there are 2 SRUs that are Claus Units. While we are unsure whether the process type may affect
emissions levels, each of the SRUs has combustion controls in place, and as such, the THC
emissions from these units are expected to be similar. All ten of the SRU units have either an
incinerator or a thermal oxidizer as the control device. Both incinerators and thermal oxidizers
work on the same principles of combustion, and these terms are often used interchangeably by
field staff. As such, there is no reason to believe that these control devices would have differing
levels of THC emissions. Therefore, all of these units were combined for emissions factor
development.

The statistical analysis for determining outliers in the data set was conducted, and one
data value was found to be an outlier and was removed from the analysis. The emissions test
that was an outlier had the highest average test result in the data set. The outlier test conducted
on the remaining data set showed no additional outliers.

-------
One of the last steps in developing an emissions factor is a comparison of the FQI for
different units. In the development of the emissions factor for THC from SRUs, the FQI
evaluation excluded two units from the data set (these two units have the lowest ITR scores), so
the emissions factor is based on the emissions test data for 7 units and is characterized as Poorly
Representative. The emissions factor analysis for SRU THC is provided in spreadsheet "EF
Creation_THC_SRU_2015 April_(Heat_Rate).xlsm".

Table 18. Overview of the Emissions Factor for THC from SRUs (Heat Rate Basis)

Emissions test d;it:i lo use

Test methods

AP-42 Kmissions
Tjiclor

Represent ill neness

No. of losl
reports

No. of units

LIW Method 25A

1.4 \ In Ib TllC

[as propane]/mmBtu

Poorl)

a One SRU was shown to be an outlier for the data set and was removed from the emissions factor
analysis.

b Two SRUs were excluded from the data set based on the FQI evaluation.

c The final data set for the emissions factor is based on 7 SRUs. The SRUs on which the SRU THC
emissions factor is based include 5 SRUs with SCOT tail gas treatment units and 2 SRUs with Claus
units. The control devices in the data set include 7 SRUs with incinerators or thermal oxidizers.

Table 19. Analysis of Emissions Test Reports for THC from SRUs (Heat Rate Basis)

1¦acilitv II)
No.

l iicililv iiiime

Kmissions
unit

AI'C'I)

lest
method

A\ern»e lest
results. Ih 1 IK
|:is

prop;ine|/mm lilu

Ilk

1)11 \ I

Vak'ro Del aw a iv Cil\

Refinery, in Delaware
City DE

:s-sri i

Thermal

Oxidizer

m:5a

2.<> \ in

DE1A0360

Valero Delaware City
Refinery, in Delaware
City DE

28-SRU2 a

Thermal
Oxidizer

M25A

4.6 x 10"4

LA3C0650

Valero Refining -
New Orleans, LLC in
St. Charles Refinery
in Norco, LA

SRU 1600 a

Thermal
Oxidizer

M25A

1.1 x 10"3

OK2C0990

Total Petroleum, Inc.
Ardmore Refinery, in
Ardmore, Oklahoma

SRU500A a

Incinerator

M25A

1.1 x 10"3

TX3B1110

BP Products North
America Inc. in Texas
City, TX

SRU a

Incinerator

M25A

1.4 x 101

TX3B1220

Motiva Enterprises,
LLC in Port Arthur,
TX

SRU4 a

Incinerator

M25A

1.6 x 10"3

-------
1 iicililv II)
No.

l iicililv iiiime

Emissions
unit

AI'C'I)

Tesl
method

A\crsi«»c lost
results. Ih 1 IK
|;is

|)rop;iiieJ/m m litu

Ilk

1X313 i:5u

Valero Port Arthur
Refinery in Port
Arthur, TX

SRU544 a

Incinerator

M25A

8.9 x 10"4

TX3B1320

Valero Refining,
Houston Refinery, in
Houston TX

SRU39 b

Incinerator

M25A

7.4 x 10"4

TX3B1320

Valero Refining,
Houston Refinery, in
Houston TX

SRU46 b

Incinerator

M25A

3.0 x 10"3

WA5A1410

Shell Puget Sound
Refining Company, in
Anacortes WA

SRU4 a

Incinerator

M25A

1.1 x 10"3

a These SRUs are Claus units with SCOT tail gas treatment units.
b These SRUs are Claus units.

c These emissions units were shown to be outliers for the data set and were removed from the emissions
factor analysis.

d This emissions unit was excluded from the data set based on the FQI evaluation.

3.6.2 Sulfur Production Rate basis

An overview of the emissions factor using a sulfur production basis is provided in Table

20.

Based on the emissions test report review and analysis, 7 emissions test reports for 7
emissions units had useable data and were included in the development of the emissions factor.
One test report provides emissions test data for SRU that share a common stack. When
emissions testing is conducted on more than one SRU that share a common stack, the emissions
units are counted as one "unit"; the total emissions rate is divided by the total production rate of
all SRU venting to the stack when developing the units' average test results. The majority of the
testing was conducted since 2005, although one test report is from 1996.

The emissions test reports used in the factor analysis are provided in Table 21. A
complete list of the available test report information is provided in worksheet
"Test_Data_Sum_THC_SRU_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The ITR scores for these 7 test reports
ranged from 33 to 44. The emissions data (lb THC [as propane]/hr) in these test reports are
based on measurements taken with EPA Method 25A (M25A), and the test reports included
production rate data for the SRU in ton/hr sulfur production.

Certain test reports were excluded from the emissions factor analysis because production
rate data are not available or the concentration data for the test run average in the test report is a
negative or zero value.

-------
EPA's recommended emissions factor development procedures were followed for the
SRU THC data. All 7 SRU units are Claus units with SCOT tail gas treatment units, and all 7
SRUs have either an incinerator or a thermal oxidizer as the control device. Both incinerators
and thermal oxidizers work on the same principles of combustion, and these terms are often used
interchangeably by field staff. As such, there is no reason to believe that these control devices
would have differing levels of THC emissions. Therefore, all of these units were combined for
emissions factor development. The statistical analysis for determining outliers in the data set
was conducted, and no data were found to be outliers. The emissions factor is based on the
emissions test data for 7 units and is characterized as Poorly Representative. The emissions
factor analysis for SRU THC is provided in spreadsheet "EF
Creation_THC_SRU_2015 April_(Sulf_Prod).xlsm".

Table 20. Overview of the Emissions Factor for THC from SRUs (Sulfur Production Rate
Basis)

Emissions test d;it:i lo use

No. of losl
reports

No. of units

Test methods

AP-42 Kmissions
Tjiclor

Represent <11 neness

7 a

EPA Method 25A

4.0 x 10"2 lb THC
[as propane]/ton
sulfur

Poorly

a The final data set for the emissions factor is based on 7 SRUs. The SRUs on which the SRU THC
emissions factor is based include 7 SRUs with SCOT tail gas treatment units. The control devices in the
data set include 7 SRUs with incinerators or thermal oxidizers.

Table 21. Analysis of Emissions Test Reports for THC from SRUs (Sulfur Production Rate
Basis)

l iu-ilitv II)
No.

liicililv 11:1111c

Emissions
unit

AI'CI)

lest
met hod

A\ersi«e test
results. Ih
1 IK his
prop;ine|/ton
sul I'll r

Ilk

LA3C0650

Valero Refining - New
Orleans, LLC at St.
Charles Refinery in
Norco, LA

SRU 1600

Thermal
Oxidizer

M25A

5.9 x 10"3

OK2C0990

Total Petroleum, Inc.
Ardmore Refinery -
Ardmore, Oklahoma

SRU500A

Incinerator

M25A

1.9 x 10"3

TX3B1090

Total Petrochemicals
USA, Inc. in Port
Arthur, TX

SRU1&2

Incinerator

M25A

8.2 x 10"2

TX3B1110

BP Products North
America Inc. in Texas
City, TX

SRU

Incinerator

M25A

1.8 x 101

-------
lacililv II)
No.

liicililv 11:11110

Emissions
unit

AI'C'I)

Test
method

A\crage lesl
results, Ih
1 IK |as
propaiiel/loii
sul I'u r

Ilk

TX3B1220

Motiva Enterprises,
LLC in Port Arthur,
TX

SRU4

Incinerator

M25A

1.2 x 10"3

TX3B1250

Valero Port Arthur
Refinery in Port
Arthur, TX

SRU544

Incinerator

M25A

7.4 x 10"3

WA5A1410

Shell Puget Sound
Refining Company, in
Anacortes WA

SRU4

Incinerator

M25A

7.4 x 10"5

3.7 Hydrogen Plants - CO

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for CO from Hydrogen Plants. Each of the available test reports was reviewed, analyzed,
and summarized, and for those test reports included in the emissions factor analysis, given an
ITR score.

Based on the emissions test report review and analysis, 3 emissions test reports for 3
emissions units had useable data and were available for inclusion in development of an emissions
factor. The emissions units for which emissions data are available include 2 condensate stripper
vents (prior to returning water to the site feed water system) and 1 reformer furnace. The
production data for these emissions units are not on the same basis. Hydrogen production data in
scf/hr is available for 1 of the condensate stripper vents, and production data in the form of
Methane Feed Rate in scf/hr are available for the other condensate stripper vent. For the
reformer furnace, heat input rate is available as the process activity rate. Because these
production data are not in comparable units and there is no way to calculate the production rate
data on the same basis, these test reports could not be combined for emissions factor
development. These useable emissions test reports are provided in Table 22. A complete list of
the available test report information is provided in worksheet

"Test_Data_Sum_CO_H2P_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The emissions data (lb CO/hr) in these
test reports are based on measurements taken with EPA Method 10 (M10).

Because the scope of this project is limited to data sets containing test averages from at
least 3 emissions units and there are 2 emissions units with useable test reports for the

-------
condensate stripper vent and 1 reformer furnace with useable test data, but none of these units
have production rate data on the same basis, an emissions factor was not developed for CO for
Hydrogen Plants.

Table 22. Analysis of Emissions Test Reports for CO from H2 Plants

II) No.

l :icililv iiiiine

Km issions
unit

AI'C'I)

Test
method

A\or:i«>o lost
rosulls

Ilk

Condensate stripper vent

AR3D0110

Lion Oil Company in El
Dorado, AR

Condensate
stripper vent
(prior to
boiler water
feed system)

None

M10

0.48 lb
CO/MMscf H2
Production

NJ1A0850

ConocoPhillips Company
Bayway Refinery,
ConocoPhillips Company
in Linden, NJ

Condensate
stripper vent
(prior to
boiler water
feed system)

None

M10

0.0011 lb
CO/scf methane
process feed

Reformer

C04A0340

Suncor Energy, Commerce
City Refinery, Commerce
City, Colorado

Plant 1
Hydrogen
Furnace stack

None

M10

0.00077 lb
CO/MMBtu

3.8 Hydrogen Plants - NOx

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for NOx from Hydrogen Plant units. Each of the available test reports was reviewed,
analyzed, and summarized, and for those test reports included in the emissions factor analysis,
given an ITR score. An overview of the emissions factor is provided in Table 23.

Based on the emissions test report review and analysis, 7 emissions test reports for 7
emissions units had useable data and were included in the development of the emissions factor.
The emissions test reports used in the factor analysis are provided in Table 24. A complete list
of the available test report information is provided in worksheet

"Test_Data_Sum_NOx_H2P_2015April.xlsm". For more detail on the analysis and QA
conducted, see the field "QA Notes" for each test report. The ITR scores for these 7 test reports
ranged from 23 to 52. The emissions data (lb NOx/hr) in these test reports are based on
measurements taken with EPA Method 7E (M7E), and the test reports included activity rate data
for the Hydrogen Plant in MMBtu/hr heat input.

Certain test reports were excluded from the emissions factor analysis because heat input
data are not available or the emissions unit did not have controls consistent with the other units
(e.g., 1 emissions units had ultra-low NOx burners, and 1 emissions unit had selective catalytic
reductions controls).

-------
EPA's recommended emissions factor development procedures were followed for the
Hydrogen Plant NOx data. None of the 7 units have controls for NOx, and all were combined
for emissions factor development. The statistical analysis for determining outliers in the data set
was conducted, and no data were found to be outliers.

One of the last steps in developing an emissions factor is a comparison of the Factor
Quality Index (FQI) for different units. The FQI is an indicator of the emissions factor's ability
to estimate emissions for the entire national population, and it is related to both the ITR score
and the number of units in the data set. Once the statistical procedures are complete, the data set
is ranked by ITR score (high to low), and a FQI is developed for each unit in the candidate set.
The FQI should decrease with each emissions unit. When the FQI increases, only average test
values above the point where the FQI increases should be considered in the factor development.
In the development of the emissions factor for NOx from Hydrogen Plants, the FQI evaluation
excluded one unit from the data set, so the emissions factor is based on the emissions test data
for 6 units and is characterized as Poorly Representative. The emissions factor analysis for NOx
from Hydrogen Plants is provided in spreadsheet "EF Creation_NOx_H2P_2015April.xlsm".

Table 23. Overview of the Emissions Factor for NOx from Hydrogen Plants

Emissions lost il:it;i to use

No. of test
reports

No. of units

li st met hods

AIM2 Kmissions
Tjiclor

Represent ill iM'iicss

7 a

EPA Method 7E

8.1 x 10"2 lb
NOx/mmBtu

Poorly

a One Hydrogen Plant was excluded from the data set based on the FQI evaluation.
b The 6 Hydrogen Plants on which the Hydrogen Plant NOx emissions factor is based are all uncontrolled
for NOx.

Table 24. Analysis of Emissions Test Reports for NOx from Hydrogen Plants

l;ieilil\ II)
No.

l';icili(\ iiiime

Kmissions iiiiil

\P< 1)

lest
method

A\er;iiie lest

results. Ih
N()\/m m lilu

itk

AL^DnnJMi

(2007 test)a

lluiiL Refining.

Tuscaloosa, Alabama

Reformers A, L>,
and C

None

M"L

o.o lo

AL3D0020
(2010 test)

Hunt Refining,
Tuscaloosa, Alabama

No. 2 Hydrogen
Plant Reformer -
indirect heaters

None

M7E

0.016

IL2A0430

ConocoPhillips Company,
Wood River Refinery
Hydrogen Plant in
Roxana, Illinois

Hydrogen Plant 1

None

M7E

0.041

MT4A0790

ExxonMobil Billings
Refinery, Billings,
Montana

F-551 Hydrogen
Plant Process
Heater/Furnace

None

M7E

0.17

-------
l-'iicilil> II)
\o.

l';icili(\ iiiimo

I'lmissions unit

\P( 1)

losl
imMliod

A\er;iiie (csl

IVSIlllS. II)

N()\/m m lilu

itk

OH2A0910

BP Husky Refining LLC,
Toledo, OH

Hydrogen Furnace

None

M7E

0.090

MT4A0800
(2008 test)

Montana Refining
Company, Great Falls,
Montana

Hydrogen Plant
Reformer Heater
H1810

None

M7E

0.11

C04A0340

Suncor Energy Inc.
Commerce City Refinery,
Commerce City, Colorado

H-2101

None

M7E

0.052

a This facility was excluded from the data set during the emissions factor analysis.

3.9 Hydrogen Plants - THC

The available emissions test data from the 2011 Refinery ICR included multiple test
reports for THC from Hydrogen Plant units. Each of the available test reports was reviewed,
analyzed, and summarized, and for those test reports included in the emissions factor analysis,
given an ITR score.

Based on the emissions test report review and analysis, 3 emissions test reports for 3
emissions units had useable data and were available for inclusion in development of an emissions
factor. The emissions units for which emissions data are available include 2 condensate stripper
vents (prior to returning water to the site feed water system) and 1 reformer furnace. The
production data for these emissions units are not on the same basis. Hydrogen production data in
scf/hr is available for 1 of the condensate stripper vents, and production data in the form of
Methane Feed Rate in scf/hr are available for the other condensate striper vent. For the reformer
furnace, heat input rate is available as the process activity rate. Because these production data
are not in comparable units and there is no way to calculate the production rate data on the same
basis, these test reports could not be combined for emissions factor development. These useable
emissions test reports are provided in Table 25. A complete list of the available test report
information is provided in worksheet "Test_Data_Sum_THC_H2Plants_2015April.xlsm". For
more detail on the analysis and QA conducted, see the field "QA Notes" for each test report.
The emissions data (lb THC [as propane]/hr) in these test reports are based on measurements
taken with EPA Method 25A (M25A).

Certain test reports were excluded from the emissions factor analysis for the following
reasons: production rate data were not available or the test method was not compatible with THC
measurements taken with M25A (i.e., M18 test reports, SCAQMD M25.3, or BAAQMD Method
ST-32 test reports were excluded because these methods measure specific compounds where
M25A counts total carbon).

Because the scope of this project is limited to data sets containing test averages from at
least 3 emissions units and because there are 2 emissions units with useable test reports for the
condensate stripper vent and 1 reformer furnace with useable test data, but none of these units

-------
have production rate data on the same basis, an emissions factor was not developed for THC
from Hydrogen Plants.

Table 25. Analysis of Emissions Test Reports for THC from Hydrogen Plants

II) No.

l iicililv Miiinc

Emissions
unit

AI'C'I)

Tesi
modioli

A\crji»o losl
results

Ilk

Condensate stripper vent

AR3D0110

Lion Oil Company, El
Dorado, AR

Condensate
stripper vent
(prior to
boiler water
feed system)

None

M25A

1.1 lb THC [as
propane]/MMscf
H2 product

13

NJ1A0850

ConocoPhillips Company
Bayway Refinery,
ConocoPhillips Company,
Linden, NJ

Condensate
stripper vent
(prior to
boiler water
feed system)

None

M25A

0.0035 lb THC
[as propane]/scf
methane process
feed

36

Reformer

AL3D0020

Hunt Refining in
Tuscaloosa, AL

Reformer

None

M25A

0.00046 lb
THC/MMBtu

15

40

-------
Section 4

Discussion of Revisions to SO2 Emissions Factors in AP-42
Section 8.13, Sulfur Recovery

In addition to adding new emissions factors for sulfur recovery plants, as described in
sections 3.4, 3.5, and 3.6 for CO, NOx, and THC, respectively, revisions were made to the SO2
emissions factors presented in the 1993 version of Table 8.13-1 in Section 8.13 of AP-42. The
previous emissions factors were based on assumed average sulfur recovery efficiencies instead of
on a statistical evaluation of measured emissions data. While this approach is technically sound,
the previous emissions factors did not appear to be consistent with current sulfur recovery plant
performance data because mid-range values were used rather than developing a more
statistically-based approach. The 1993 background document for AP-42 section 8.132 presents
test data for 16 sulfur recovery plants. Nine of the 16 plants had SO2 emissions of approximately
2 kg/Mg sulfur produced, but the smallest emissions factor in the 1993 version of Table 8.13-1
was 29 kg/Mg. The footnotes to Table 8.13-1 indicated that test data for 2-staged "controlled"
units showed 98.3 to 98.8 percent sulfur recovery and that 3-staged "controlled" units showed 95
to 99.9 percent sulfur recovery; using the mid-range value, the 2-staged controlled units have the
lowest emissions factor (29 kg/Mg versus 65 kg/Mg). From review of the background
document, it is unclear how these ranges were determined unless incineration was considered an
SO2 control (in which case all units tested had "controls"). The data presented in the background
document show that the highest average run data for a sulfur recovery plant with a tailgas
cleanup unit was 7.8 kg/Mg, so that the lowest "controlled" emissions factor in Table 8.13-1 is
roughly 4 times the highest emissions results from a Claus unit with tailgas cleanup. Thus, the
"controlled" emissions factors in Table 8.13-1 do not appear to be representative of the Claus
sulfur recovery plants with tail gas clean-up.

Due to the issues identified with the previous version of Table 8.13-1, revisions were
made to the table to more accurately present emissions factors for different types of sulfur
recovery plants based on specific source classification codes (SCCs), which include the expected
sulfur recovery efficiencies for those sulfur recovery plants. Revisions were also made for the
discussion of tailgas "controls" to more clearly distinguish between tailgas treatment units,
which enhance sulfur recovery efficiencies, and incineration, which merely converts reduced
sulfur compounds to SO2.

The revisions to the emissions factors in Table 8.13-1 are still based on a mass balance
approach assuming that all sulfur not recovered is emitted as SO2. The emissions factors in
Table 8.13-1 are applicable to sulfur recovery plants that are followed by a thermal oxidizer,
incinerator, or other oxidative control system in which hydrogen sulfide or other reduced sulfur
compounds in the tailgas can be converted to SO2 prior to atmospheric release. Revisions were
made to the Title of Table 8.13-1 to clarify this applicability. The new title for Table 8.13-1 is

2 The 1993 background document for sulfur recovery is entitled "Background Report, AP-42 Section 5.18, Sulfur
Recovery." With the publication of the Fifth Edition of AP-42, the Chapter and Section number for Sulfur Recovery
changed to 8.13.

41

-------
"S02 EMISSION FACTORS FOR CLAUS SULFUR RECOVERY PLANTS WITH
OXIDATIVE CONTROL SYSTEMS "

Additionally, Table 8.13-1 did not previously provide applicable SCCs for the sulfur
recovery plants described in the table, and the footnote showing the calculation of the emissions
factor was incorrectly presented. Therefore, the new version of Section 8.13 has been updated to
specify applicable SCCs and to correct the footnote equations in Table 8.13-1.

42

-------
Section 5

Emissions Factor Development for Industrial Flares

EPA has reviewed the emissions test data in recent flare studies. Several of these test
reports are based on studies that resulted from various enforcement actions related to flare
performance issues. The EPA collected additional flare data during development of an analysis
of proper flare operating conditions (EPA 2012). We obtained data from a DIAL study in the
Houston area in which the emissions from several flares were isolated. We also used the original
flare report from which the previous set of flare emissions factors was created. The emissions
data review and the emissions factor development for each pollutant are described below.

The available emissions test data included multiple test reports for CO from flares.
[Additional discussion of these test reports is included in EPA's Review of Available Documents
Report (EPA, 2015a).] Each of the available test reports was reviewed, analyzed, and
summarized, and given an ITR score. An overview of the emissions factor is provided in Table

Based on the emissions test report review and analysis, 6 emissions test reports for 8
flares had useable data and were included in the development of the emissions factor. The flares
tested include 7 steam-assisted flares and one air-assisted flare. The test data are based on the
measurement principle of passive Fourier Transform infrared (PFTIR). The emissions data for
flares consisted of 1-minute CO concentration-pathlength (ppm-m) data for approximately 10 to
15 test runs for each flare. Each test run was approximately 15 to 20 minutes in duration. Data
was reviewed on a run average basis. We used the averages of the data provided by the facility
when they were available and calculated the averages from the minute data when the averages
were not provided.

The mass emissions of CO were calculated using a carbon balance, where the overall
equation is as follows:

5.1 Flares - CO

26.

C inlet x-I—^1

[C02]

Where:

Eco

emissions rate of carbon monoxide (lbs/hr).

C_inlet= mass flow of carbon in the flare vent gas sent to the flare (lb/hr).

[CO]

PFTIR measured CO concentration (ppm-m).

[CO2] = PFTIR measured CO2 concentration (ppm-m).

-------
CE

28

12

Measured flare combustion efficiency3,
molecular weight of carbon monoxide (lb/lb-mole),
molecular weight of carbon (lb/lb-mole).

Cinlet was determined based on the standard flow rate of the vent gas and the carbon
constituents of the vent gas. C inlet was calculated as follows:

C_inlet = Qfg x ^ x ^ (MFX x CMNx )

MVC

Where:
C_inlet=

Qfg =

12

MVC =
MFX =
CMNx =

12

mass flow of carbon in the flare vent gas sent to the flare (lb/hr).

volumetric flow rate of flare vent gas (standard cubic feet per hour;
scf/hr).

molecular weight of carbon (lb/lb-mole).

molar volume correction factor (scf/lb-mole) = 385.5 scf/lb-mole at 68 °F
and 1 atmosphere pressure.

mole fraction of compound "x" in the flare vent gas (mole compound per
mole vent gas)4.

carbon mole number of compound "x" in the flare vent gas (mole carbon
atoms per mole compound), e.g., CMN for ethane (C2H6) is 2; CMN for
propane (C3H8) is 3.

molecular weight of carbon (lb/lb-mole).

When performing the calculations, C inlet was initially used to calculate an apparent
pathlength exhaust gas flow rate based on the CO2 pathlength concentration and combustion
efficiency as follow:

3	We used the weighted combustion efficiency in the calculations. If the raw data only provided one CE instead of
providing both a weighted and unweighted CE, we assumed that the provided CE was the weighted CE. We note
that in the calculation of the weighted combustion efficiency, two test reports inadvertently weighted acetylene
incorrectly. Acetylene has two carbon atoms, but the calculation indicated that there are three. We analyzed what
effect this has on the data, and we determined that this error resulted in a change in the CE of less than a tenth of a
percent on average.

4	Generally the mole percent is provided in the spreadsheets. In the spreadsheet calculation, the mole percent is
divided by 100 to get the mole fraction.

44

-------
Q

Where:

Qexhaust
( 111 I CI =

MVC =
12

CE =
106

[C02] =

exhaust

MVC CExlO
= C inlet x	x -

12

[C02]

exhaust gas flow rate in flare exhaust-pathlength (scf/hr-m).

mass flow of carbon in the flare vent gas sent to the flare (lb/hr)5.

molar volume correction factor (scf/lb-mole) = 385.5 scf/lb-mole at 68 °F
and 1 atmosphere pressure.

molecular weight of carbon, lb/lb-mol.

measured flare combustion efficiency.

parts in one-million parts.

PFTIR measured CO2 concentration (ppm-m)6.

The apparent pathlength exhaust gas flow rate was then used to calculate a mass flow rate
of each pollutant. For CO, the mass flow rate is calculated from the pathlength exhaust gas flow
rate as follows:

Eco =Q

[CO] 28

exhaust X ^ X MyC

Where:

Eco =

Qexhaust —

[CO] =

106

emissions rate of carbon monoxide (lbs/hr).

exhaust gas flow rate in flare exhaust-pathlength (scf/hr-m).

PFTIR measured CO concentration (ppm-m).

parts in one-million parts7.

5	Conservation of Mass dictates that mass can neither be created nor destroyed. As such, the mass flow inlet of
carbon is equal to the emission rate of carbon.

6	In the spreadsheet calculations, the term total carbon (in ppm-m) represents the [CO2] divided by the CE.
Combustion efficiency is the amount of initial carbon that becomes carbon dioxide. The total carbon term back
calculates the available carbon in the system in ppm-m. Dividing the total carbon term by one million inserts
volumetric concentration into the equation, i.e. standard cubic feet of carbon per standard cubic feet of exhaust gas.

7	By dividing the PFTIR measurement by one million, we have inserted volumetric concentration into the equation,
i.e. standard cubic feet of CO per standard cubic feet of exhaust gas.

45

-------
28 = molecular weight of carbon monoxide, lb/lb-mol.

MVC = molar volume correction factor (scf/lb-mole) = 385.5 scf/lb-mole at 68 °F
and 1 atmosphere pressure.

Substituting the equation for Qexhaust in the above equations, the 106 and MVC conversion
factors cancel out, yielding the overall equation. We divided the mass emissions rate by the vent
gas heat rate (obtained using information provided by the facility on vent gas flow rate and vent
gas net heating value) to arrive at the CO emissions rate in lb/MMBtu.

Because the flare testing was conducted to identify conditions where flare performance
deteriorates, there were many test runs conducted at operating conditions that resulted in poor
flare combustion efficiencies. These operating conditions are not representative of normal flare
performance, and including all of these test runs would skew the data in a way that is
unrepresentative of normal operating conditions. Properly operated flares achieve at least 98
percent destruction efficiency in the flare plume. The EPA has set out requirements for flare
operation in the General Provisions of 40 CFR Parts 60 and 638. Flares that meet the
requirements of the General Provisions are assumed to achieve 98% destruction efficiency. As
such, we eliminated any runs where the flare vent gas net heating values were below 300 Btu/scf,
and we ensured that the flare tip velocity was below the maximum allowed by the General
Provisions. For the PFTIR study data, the run average data were reviewed to determine if the
combustion efficiency was less than 96.5 percent (considered to be equivalent to a destruction
efficiency of 98 percent) (EPA, 2012). Any data that did not meet this combustion efficiency
was excluded from the analysis. Any run with an average reported CO2 value of 0 was also
removed from the data set because the calculation for CO emissions is dependent on knowing the
concentration of CO2. All remaining average run data for a given flare were used to calculate an
average emissions value (in CO mass per heat input of vent gas) for the flare.

Some test reports included multiple values for CO2 measurements. These measurements
represent the CO2 values determined by the PFTIR operator at up to three different wavelengths
(765, lk, and 2k). The preferred wavelength is determined by the spectroscopist at the time of
testing. We obtained the preferred CO2 wavelength for each study (see Appendix C), and the
CO2 pathlength concentration for that wavelength was used in the calculation of the emissions
factor. If only one CO2 band was available in the raw data, we assumed that it was the band
identified by the spectroscopist as the appropriate band for that test.

The emissions test reports used in the factor analysis are provided in Table 27. The
available data from each test report included in the emissions factor analysis is provided in
worksheet "Flare Calculation.xlsx". The ITR scores for these 7 test reports ranged from 38 to

8 We note that the proposed Refinery NESHAP rulemaking and the EPA Peer Review Study (EPA 2012) have
indicated that certain flares need to monitor additional parameters in order to ensure 98% destruction efficiency.
However, it is still the EPA's position that a properly operated flare will achieve 98% destruction efficiency. The
comments received on this rulemaking are still under consideration. Additionally, this factor applies to flares
outside of the refining industry. We have not determined at this time that it is necessary for other sectors to monitor
additional operating parameters in order to ensure 98% destruction efficiency. As such, we believe that it is
appropriate to base the emissions factor on the requirements of the General Provisions.

-------
52. The emissions data (ppm-m CO) in these test reports are based on measurements taken with
passive FTIR, and the activity rate data in the test reports included flare vent gas flow rates and
compositions, from which C inlet (lb C/hr) and the net heat input (MMBtu/hr) to the flare could
be calculated.

EPA's recommended emissions factor development procedures include guidelines for the
inclusion of previous emissions data when existing emissions factors are revised. The existing
data should be included alongside the new data prior to running any statistical tests. The ITR
score for the existing data is based on the letter-rating of the data. There was an existing AP-42
emissions factor for CO emissions from flares (see AP-42 section 13.5), and so the emissions
factor analysis included the existing CO emissions data. Per the EPA's recommended emissions
factor development procedures, since the previous factor was B-rated, an ITR score of 80 was
assigned to the existing data. Per the factor development procedures, the existing factor was
divided into individual source tests. The existing CO emissions factor was based on data from
two different sources, an air-assisted flare and a steam-assisted flare. We calculated the factor
for each of these flare using the original data. This calculation is also included in worksheet
"Flare Calculation.xlsx". Additionally, to be consistent with the conventions used for the PFTIR
data, we limited the data to times when the flares were meeting the requirements of the General
Provisions and 96.5 percent combustion efficiency. We note that these tests were also conducted
with many runs purposely at deteriorating conditions and including all of these test runs would
skew the data in a way that is unrepresentative of normal operating conditions

EPA's recommended emissions factor development procedures were followed for the
flare CO data. Potential subcategories were considered for the flare emissions data based on the
type of flare. With respect to flare type, because there are 7 steam-assisted flares and only 1 air-
assisted flare and the statistical analysis for determining whether the data are part of the same
population requires at least 3 emissions units in each category, the statistical analysis for
subcategorization could not be performed. However, since the current AP-42 emissions factors
are based on emissions from both air-assisted and steam-assisted flares, it is appropriate to
combine the emissions from both types of flares for this analysis as well. All 8 units from flare
test reports under the current analysis were combined for emissions factor development, along
with the existing flare emissions data in AP-42. The statistical analysis for determining outliers
in the data set was conducted, and no data were shown to be an outlier. The emissions factor is
based on 10 flares and is characterized as Poorly Representative. The spreadsheet "EF
Creation_CO_flare_2015 April .xlsm" provides the analysis for the emissions factor for CO
emissions from flares.

-------
Table 26. Overview of the Emissions Factor for CO from Flares

Emissions lost cl;it;i to use







No. of test
reports

No. of iiiiits

li st met hods

AIM2 Kmissions
Tjiclor

Represent;ili\eness

7

10 a

(Measurement
technique is
Passive FTIR)

0.31 lb CO/MMBtu

Poorly

a The flare CO emissions factor is based on 8 steam-assisted flares and 2 air-assisted flares.

Table 27. Analysis of Emissions Test Reports for CO from Flares

l-';ieilit> II)
No.

l-';ieilit\ iiiiine

I'linissioiis unit

lest
method

A\er;itie test

results. Ih
CO/MM Bin

iik

FHR

FHRAU

Flint Hills Resources Port
Arthur, LLC in Port Arthur, TX

Flare AU
(steam-assisted)

PFTIR

0.12

38

FHR

FHRLOU

Flint Hills Resources Port
Arthur, LLC in Port Arthur, TX

Flare LOU
(steam-assisted)

PFTIR

0.13

38

MI2A0710

MPCDET

Marathon Petroleum Company,
LLC, Detroit, MI

Flare CP
(steam-assisted)

PFTIR

0.78

51

TX3B1210

MPCTX

Marathon Petroleum Company,
LLC, Texas Refining Division
in Texas City, TX

Flare Main
(steam-assisted)

PFTIR

0.30

51

INEOS

INEOS

INEOS ABS Corporation in
Addyston, OH

Flare P001
(steam-assisted)

PFTIR

0.55

38

TX3B1260

SHELL

Shell Deer Park Refinery in
Deer Park, TX

Flare EP
(steam-assisted)

PFTIR

0.37

41

NA

TCEQ testing conducted at John
Zink facility

Flare
(steam-assisted)

PFTIR

0.41

52

NA

TCEQ testing conducted at John
Zink facility

Flare
(air-assisted)

PFTIR

0.43

52

NA

Existing AP-42 CO emissions
factor steam flare

Flare
(steam-assisted)

Extractive
sampling

0.040

80

NA

Existing AP-42 CO emissions
factor air flare

Flare
(air-assisted)

Extractive
sampling

0.012

80

48

-------
5.2 Flares - VOC

The available emissions test data included multiple test reports for VOC related data from
flares. [Additional discussion of these test reports is included in EPA's Review of Available
Documents Report (EPA, 2015a).] Each of the available test reports was reviewed, analyzed, and
summarized, and for those test reports that are to be included in the emissions factor analysis,
given an ITR score. An overview of the emissions factor is provided in Table 28.

Based on the emissions test report review and analysis, 7 emissions test reports for 10
flares had useable data and were included in the development of the emissions factor. The flares
tested include 9 steam-assisted flares and one air-assisted flare. The PFTIR emissions data for
flares consisted of 1-minute THC and individual hydrocarbon concentration-pathlength (ppm-m)
data for approximately 10 to 15 test runs for each flare. Each test run was approximately 15 to
20 minutes in duration. The DIAL data for flares consisted of multiple scans directly measuring
the mass emissions of C3+ hydrocarbons. As the mass emissions of "C3+ hydrocarbons" was
directly reported in the DIAL study, only the heat input to the flare had to be calculated. Data on
vent gas composition and flow rate were available to perform this calculation.

The overall calculation of the mass emissions of VOC from the PFTIR tests were
calculated as follows. Any measurement data for methane and ethane were excluded from the
VOC calculation:

Z[HCx] xMW,

HCx

Evnr = C inlet x— xCE

[C02]x12

Where:

Evoc = emissions rate of volatile organic compounds (lbs/hr).

C inlet = mass flow of carbon in the flare vent gas sent to the flare (lb/hr).

[HCx] = PFTIR measured hydrocarbon constituent "x" concentration (other than
methane or ethane) (ppm-m).

MWhcx = molecular weight of hydrocarbon constituent "x" (lb/lb-mole).

[CO2] = PFTIR measured CO2 concentration (ppm-m).

12 = molecular weight of carbon (lb/lb-mole).

CE = Measured flare combustion efficiency9.

9 We used the weighted combustion efficiency in the calculations. If the raw data only provided one CE instead of
providing both a weighted and unweighted CE, we assumed that the provided CE was the weighted CE. We note
that in the calculation of the weighted combustion efficiency, two test reports inadvertently weighted acetylene
incorrectly. Acetylene has two carbon atoms, but the calculation indicated that there are three. We analyzed what

-------
Cinlet was determined based on the standard flow rate of the vent gas and the carbon
constituents of the vent gas. C inlet was calculated as follows:

C inlet = Qfe x x £ (MFx x CMNx )

MVC

x=l

Where:
C_inlet=

Qfg =

12

MVC =
MFX =
CMNx =

12

mass flow of carbon in the flare vent gas sent to the flare (lb/hr).

volumetric flow rate of flare vent gas (standard cubic feet per hour;
scf/hr).

molecular weight of carbon (lb/lb-mole).

molar volume correction factor (scf/lb-mole) = 385.5 scf/lb-mole at 68 °F
and 1 atmosphere pressure.

mole fraction of compound "x" in the flare vent gas (mole compound per
mole vent gas)10.

carbon mole number of compound "x" in the flare vent gas (mole carbon
atoms per mole compound), e.g., CMN for ethane (C2H6) is 2; CMN for
propane (C3H8) is 3.

molecular weight of carbon (lb/lb-mole).

As described in Section 5.1 of this report, the calculation of pollutant mass emissions
were calculated by first determining an apparent pathlength exhaust gas flow rate and then the
pollutant mass emissions rate. The apparent pathlength exhaust gas flow rate was calculated as
follow:

Q

MVC CExlO6
= C inlet x	x	

exhaust "	12 [C02]

Where:

Qexhaust = exhaust gas flow rate in flare exhaust-pathlength (scf/hr-m).
C inlet = mass flow of carbon in the flare vent gas sent to the flare (lb/hr)11.

effect this has on the data, and we determined that this error resulted in a change in the CE of less than a tenth of a
percent on average.

10 Generally the mole percent is provided in the spreadsheets. In the spreadsheet calculation, the mole percent is
divided by 100 to get the mole fraction.

50

-------
MVC = molar volume correction factor (scf/lb-mole) = 385.5 scf/lb-mole at 68 °F
and 1 atmosphere pressure.

12 = molecular weight of carbon, lb/lb-mol.

CE = measured flare combustion efficiency.

106 = parts in one-million parts.

[CO2] = PFTIR measured CO2 concentration (ppm-m)12

The apparent pathlength exhaust gas flow rate was then used to calculate a mass flow rate
of each hydrocarbon pollutant as follows:

E =0 jHCx] MW„CX

HCx	exhaust 10^ Tvt"VC

Where:

Ehcx =	emissions rate of hydrocarbon "x" (lbs/hr).

Qexhaust =	exhaust gas flow rate in flare exhaust-pathlength (scf/hr-m).

[HCx] =	PFTIR measured concentration for hydrocarbon "x" (ppm-m).

106 =	parts in one-million parts13.

MWhcx =	molecular weight of hydrocarbon "x", lb/lb-mol.

MVC =	molar volume correction factor (scf/lb-mole) = 385.5 scf/lb-mole at 68 °F
and 1 atmosphere pressure.

The mass emissions of each of the VOC hydrocarbons was then summed to calculate the
total VOC emissions. Substituting the equation for Qexhaust in the above equations, the 106 and
MVC conversion factors cancel out, and the summation yields the overall equation. We divided
the mass emissions rate by the vent gas heat rate (obtained using information provided by the

11	Conservation of Mass dictates that mass can neither be created nor destroyed. As such, the mass flow inlet of
carbon is equal to the emission rate of carbon.

12	In the spreadsheet calculations, the term total carbon (in ppm-m) represents the [CO2] divided by the CE.
Combustion efficiency is the amount of initial carbon that becomes carbon dioxide. The total carbon term back
calculates the available carbon in the system in ppm-m. Dividing the total carbon term by one million inserts
volumetric concentration into the equation, i.e. standard cubic feet of carbon per standard cubic feet of exhaust gas.

13	By dividing the PFTIR measurement by one million, we have inserted volumetric concentration into the equation,
i.e. standard cubic feet of HCX per standard cubic feet of exhaust gas.

51

-------
facility on vent gas flow rate and vent gas net heating value) to arrive at the VOC emissions rate
in lb/MMBtu.

Because the flare testing was conducted to identify conditions where flare performance
deteriorates, there were many test runs conducted at operating conditions that resulted in poor
flare combustion efficiencies. These operating conditions are not representative of normal flare
performance, and including all of these test runs would skew the data in a way that is
unrepresentative of normal operating conditions. Properly operated flares achieve at least 98
percent destruction efficiency in the flare plume. The EPA has set out requirements for flare
operation in the General Provisions of 40 CFR Parts 60 and 6314 Flares that meet the
requirements of the General Provisions are assumed to achieve 98% destruction efficiency. As
such, we eliminated any runs where the flare vent gas net heating values were below 300 Btu/scf,
and we ensured that the flare tip velocity was below the maximum allowed by the General
Provisions. For the PFTIR study data, the run average data were reviewed to determine if the
combustion efficiency was less than 96.5 percent (considered to be equivalent to a destruction
efficiency of 98 percent) (EPA, 2012). Any data that did not meet this combustion efficiency
was excluded from the analysis. Any run with an average reported CO2 value of 0 was also
removed from the data set because the calculation for CO emissions is dependent on knowing the
concentration of CO2. All remaining average run data for a given flare were used to calculate an
average emissions value (in CO mass per heat input of vent gas) for the flare.

For the DIAL study included in the emissions factor development, the emissions from
three flares are represented. Flare 6 was isolated, but the ULC and temporary flare emissions
were contained in the same measurement scans. We treated these two flares as one flare system
and divided the total emissions by the combined heat rate of the two flares. Additionally, the
DIAL report indicated that on the third day of testing, the flare system did not meet the minimum
destruction efficiency of 98%. Based on a review of the data, the ULC flare was achieving a
much lower destruction efficiency than the temporary flare. While this was the case on all three
days, it was only on the third day that the combined destruction efficiency of the system was

14 We note that the proposed Refinery NESHAP rulemaking and the EPA Peer Review Study (EPA 2012) have
indicated that certain flares need to monitor additional parameters in order to ensure 98% destruction efficiency.
However, it is still the EPA's position that a properly operated flare will achieve 98% destruction efficiency. The
comments received on this rulemaking are still under consideration. Additionally, this factor applies to flares
outside of the refining industry. We have not determined at this time that it is necessary for other sectors to monitor
additional operating parameters in order to ensure 98% destruction efficiency. As such, we believe that it is
appropriate to base the emissions factor on the requirements of the General Provisions.

-------
below 98%. We believe that this was caused by poor operation of the ULC flare, possibly over-
steaming, and as such, we have not included the third day of data in the analysis.

During the DIAL study, process data was recorded once an hour. DIAL scans were not
taken on a regular time interval. In order to match up the process data to the DIAL data we used
the following convention: if the DIAL scan was recorded in the first twenty minutes of an hour,
we used the process data for that hour; if the DIAL scan was recorded in the last twenty minutes
of an hour, we used the process data for the next hour; and if the DIAL scan was recorded in the
middle twenty minutes of an hour, we averaged the process data for that hour and the next hour.

The TCEQ report contained data for both extractive and PFTIR testing. We were able to
locate the data for the extractive testing in the appendices, and we combined this with process
data that we had already obtained with the PFTIR results. Because the extractive and PFTIR
testing was performed simultaneously, we averaged the results of the tests per flare. This is
consistent with how we handle multiple tests for one source in our emissions factor development
procedures. Overall, we found that the extractive testing and PFTIR testing agreed fairly well.

The emissions test reports used in the factor analysis are provided in Table 29. The
available data from each test report included in the emissions factor analysis is provided in
worksheet "Flare Calculation.xlsx". The ITR scores for these 7 test reports ranged from 38 to
52. The emissions data (ppm-m or lb/hr) in these test reports were based on measurements taken
with passive FTIR, extractive sampling and DIAL, and the activity rate data in the test reports
which included flare vent gas flow rates and compositions, from which C inlet (lb C/hr) and the
net heat input (MMBtu/hr) to the flare could be calculated.

In the existing AP-42 section for Industrial Flares, there is an emissions factor for THC
(measured as methane equivalent), but there was no previous emissions factor for VOC. Even
though THC is often used as a surrogate for VOC, the measurement methods for the two
compounds vary. In this case, the measurements for THC and VOC are not directly comparable.
As such, there is no existing emissions factor from AP-42 included in this emissions factor
analysis.

EPA's recommended emissions factor development procedures were followed for the
flare VOC data. Potential subcategories were considered for the flare emissions data based on
the type of flare. With respect to flare type, because there are 9 steam-assisted flares and only 1
air-assisted flare and the statistical analysis for determining whether the data are part of the same
population requires at least 3 emissions units in each category, the statistical analysis for
subcategorization could not be performed. However, since the current AP-42 emissions factors
are based on emissions from both air-assisted and steam-assisted flares, it is appropriate to
combine the emissions from both types of flares for this analysis as well. All 10 units from flare
test reports under the current analysis were combined for emissions factor development. The
statistical analysis for determining outliers in the data set was conducted, and no data were
shown to be outliers. The emissions factor is based on the emissions test data for 10 units and is
characterized as Poorly Representative. The spreadsheet "EF

Creation_VOC_flare_2015April.xlsm." provides the analysis for the emissions factor for VOC
emissions from flares.

-------
Table 28. Overview of the Emissions Factor for VOC from Flares

Emissions test d;it:i lo use







No. of losl
reports

No. of units

Test methods

Proposed AIM2
Kmissions Inclor

Represent <11 neness

7

10 a

(Measurement
technique is
Passive FTIR,
extractive sampling
and DIAL)

0.66 lb
VOC/MMBtu

Poorly

a The flare VOC emissions factor is based on 9 steam-assisted flares and 1 air-assisted flare.

Table 29. Analysis of Emissions Test Reports for VOC from Flares

l-'iicilil> II)
No.

l';icili(\ iiiiine

I'lmissioiis iiiiit

Test
met hod

A\er;i*ie test
results. Ih

YOC/MMIilu

1 IK

Illk

F11RAL

Flint Hills Resources Port
Arthur, LLC in Port Arthur, TX

Flare AL
(steam-assisted)

PFTIR

0.50

38

FHR

FHRLOU

Flint Hills Resources Port
Arthur, LLC in Port Arthur, TX

Flare LOU
(steam-assisted)

PFTIR

0.72

38

MI2A0710

MPCDET

Marathon Petroleum Company,
LLC, Detroit, MI

Flare CP
(steam-assisted)

PFTIR

1.60

51

TX3B1210

MPCTX

Marathon Petroleum Company,
LLC, Texas Refining Division in
Texas City, TX

Flare Main
(steam-assisted)

PFTIR

0.47

51

INEOS

INEOS

INEOS ABS Corporation in
Addyston, OH

Flare P001
(steam-assisted)

PFTIR

1.20

38

TX3B1260

SHELL

Shell Deer Park Refinery in Deer
Park, TX

Flare EP
(steam-assisted)

PFTIR

0.34

41

NA

TCEQ testing conducted at lohn
Zink facility

Flare
(steam-assisted)

PFTIR,
extractive

0.64

52

NA

TCEQ testing conducted at lohn
Zink facility

Flare
(air-assisted)

PFTIR,
extractive

0.54

52

TX3B1110

BP

Texas City, TX

Flare No. 6
(steam-assisted)

DIAL

0.25

40

TX3B1110

BP

Texas City, TX

ULC flare and
temporary flare
(steam-assisted)

DIAL

0.29

40

54

-------
Section 6
References

Air Alliance Houston, et al. v. McCarthy, No. l:13-cv-00621-KBJ (D.D.C.).

EPA (U.S. Environmental Protection Agency). 1995. Compilation of Air Pollutant Emission
Factors, Volume 1: Stationary Point and Area Sources, AP-42, Fifth Edition, U.S.
Environmental Protection Agency, Office of Air Quality Planning and Standards. January
1995. Available at: http://www.epa.gov/ttn/chief/ap42/index.html

EPA (U.S. Environmental Protection Agency). 2011. Information Collection Request for
Petroleum Refinery Sector New Source Performance Standards (NSPS) and National
Emissions Standards for Hazardous Air Pollutants (NESHAP) Risk and Technology
Review. April 2011.

EPA (U.S. Environmental Protection Agency). 2012. Parameters for Properly Designed and
Operated Flares. Prepared for U.S. Environmental Protection Agency, Office of Air Quality
Planning and Standards, Research Triangle Park, NC. April 2012. Available at:
http://www.epa.gov/airtoxics/flare/2012flaretechreport.pdf

EPA (U.S. Environmental Protection Agency). 2013. Recommended Procedures for

Development of Emissions Factors and Use of the WebFIRE Database. U. S. Environmental
Protection Agency, Office of Air Quality Planning and Standards. August 2013 (Draft
Final). Available at: http://www.epa.gov/ttn/chief/efpac/procedures/index.html

EPA (U.S. Environmental Protection Agency). 2013a. Worksheet
"EFCreation	(pollutant)_(emissionssource).xlsm".

EPA (U.S. Environmental Protection Agency). 2013b. Worksheet "Webfire-
template_(pollutant)_(emissionssource)_(facilityID)_(unitID)".

EPA (U.S. Environmental Protection Agency). 2014. Draft Residual Risk Analysis for the
Petroleum Refinery Source Sector. U.S. Environmental Protection Agency, Office of Air
Quality Planning and Standards. May 2014. (Draft). Available at:
http://www.regulations.gov/#!documentDetail:D=EPA-HO-OAR-2010-0682-Q225

EPA (U.S. Environmental Protection Agency). 2015a. EPA Review of Available Documents and
Rationale in Support of Final Emissions Factors and Negative Determinations for Flares,
Tanks, and Wastewater Treatment Systems. U.S. Environmental Protection Agency, Office
of Air Quality Planning and Standards. April 2015. Available at:
http://www.epa.gov/ttn/chief/consentdecree/final report review.pdf

55

-------
EPA (U.S. Environmental Protection Agency). 2015b. Background Information for Final
Emissions Factors Development for Flares and Certain Refinery Operations and Final
Determination for No Changes to VOC Emissions Factors for Tanks and Wastewater
Treatment Systems: Summary of Public Comments and Responses. U.S. Environmental
Protection Agency, Office of Air Quality Planning and Standards. April 2015. Available at:
http://www.epa.gov/ttn/chief/consentdecree/index consent decree.html

RTI (RTI International). 2011. Emission Estimation Protocol for Petroleum Refineries.

Version 2.1.1, Final ICR Version Corrected. Prepared for U.S. Environmental Protection
Agency, Office of Air Quality Planning and Standards, Research Triangle Park, NC. May
2011. Docket Item No. EPA-HQ-OAR-2010-0682-0060. Most current version also
available at http://www.epa.gov/ttn/chief/efpac/protocol/.

56

-------
Appendix A

EMISSIONS TEST REPORT DATA FIELDS INCLUDED IN TEST

DATA SUMMARY FILES

-------
Appendix A. Data Fields in the Test Data Summary Files

Table column

I'ield name

A

Test Report filename

B

Facility ID Number

C

Unit ID Number

D

APCD ID(s)

E

Combustion controls used to reduce air pollution (from combustion sources)

F

General Description

G

Code for Process Unit Type

H

Test Report ID

I

Test Date (mm/dd/yyyy)

J

Pollutant Name

K

Pollutant CAS No.

L

Pollutant Class

M

Test Method

N

Run 1 Hourly Production Rate (value)

0

Run 2 Hourly Production Rate (value)

P

Run 3 Hourly Production Rate (value)

Q

Average Hourly Production Rate (value)

R

Hourly Production Rate (units)

S

Production comment

T

Run 1 Hourly Production Rate (value)

U

Run 2 Hourly Production Rate (value)

V

Run 3 Hourly Production Rate (value)

w

Average Hourly Production Rate (value)

X

Hourly Production Rate (units)

Y

Production comment

Z

Run 1 Airflow Rate Outlet (acfm)

AA

Run 1 Airflow Rate Outlet (scfm)

AB

Run 1 Airflow Rate Outlet (dscfm)

AC

Run 1 Gas Moisture Outlet (%)

AD

Run 1 Gas Temp Outlet (F)

AE

Run 1 Gas Pressure Outlet (in. Hg)

AF

Run 1 Gas Oxygen Outlet (%)

AG

Run 1 Gas C02 Outlet (%)

AH

Run 2 Airflow Rate Outlet (acfm)

AI

Run 2 Airflow Rate Outlet (scfm)

AJ

Run 2 Airflow Rate Outlet (dscfm)

AK

Run 2 Gas Moisture Outlet (%)

AL

Run 2 Gas Temp Outlet (F)

AM

Run 2 Gas Pressure Outlet (in. Hg)

AN

Run 2 Gas Oxygen Outlet (%)

-------
Tsihlc col ii in 11

l-lcld nsiiiic

AO

Run 2 Gas C02 Outlet (%)

AP

Run 3 Airflow Rate Outlet (acfm)

AQ

Run 3 Airflow Rate Outlet (scfm)

AR

Run 3 Airflow Rate Outlet (dscfm)

AS

Run 3 Gas Moisture Outlet (%)

AT

Run 3 Gas Temp Outlet (F)

AU

Run 3 Gas Pressure Outlet (in. Hg)

AV

Run 3 Gas Oxygen Outlet (%)

AW

Run 3 Gas C02 Outlet (%)

AX

Average Airflow Rate Outlet (acfm)

AY

Average Airflow Rate Outlet (scfm)

AZ

Average Airflow Rate Outlet (dscfm)

BA

Average Gas Moisture Outlet (%)

BB

Average Gas Temp Outlet (F)

BC

Average Gas Pressure Outlet (in. Hg)

BD

Average Gas Oxygen Outlet (%)

BE

Average Gas C02 Outlet (%)

BF

Run 1 Outlet concentration

BG

Run 1 Outlet concentration units

BH

Run 1 Outlet Detect Flag

BI

Run 1 Outlet (lb/hr)

BJ

Run 2 Outlet concentration

BK

Run 2 Outlet concentration units

BL

Run 2 Outlet Detect Flag

BM

Run 2 Outlet (lb/hr)

BN

Run 3 Outlet concentration

BO

Run 3 Outlet concentration units

BP

Run 3 Outlet Detect Flag

BQ

Run 3 Outlet (lb/hr)

BR

Average Outlet concentration

BS

Average Outlet concentration units

BT

Count Outlet Non-Detect Runs

BU

Average Outlet (lb/hr)

BV

Sampling comments

BW

Analytical comments

BX

QA Comments

BY

Other comments

DA

QA Notes

DB

RTI Reviewer initials

DC

Looked at for EF?

DD

Test Rpt Quality for EF use

DE

[PROD RATE 1 basis]

-------
Tsihlc col ii in 11

l-lcld nsiiiic

DF

[PROD RATE 2 basis]

DG

FINAL [PROD RATE 1 basis] Used in EF?

DH

FINAL [PROD RATE 2 basis] Used in EF?

DI

PROPOSED Used in EF?

DJ

see

DK

NEI POLLUTANT CODE

DL

PROCESS DESCRIPTION

DN

CONTROL CODE1

DO

CONTROL CODE2

DP

MDL

DQ

FACTOR

DR

UNIT

DS

MEASURE

DT

MATERIAL

DU

ACTION

DV

FLAG

DW

TEST REPORT RATING

DX

REF ID

DY

REFERENCE TEXT

DZ

No. pages

-------
Appendix B

EPA'S "TEST QUALITY RATING TOOL" TEMPLATE

(ITR TEMPLATE)

August 2013

-------
Name of Facility where the test was performed

Name of Company performing stationary source tesi

SCC of tested unit or units

Name of assessor and name of employer-

Name of regulatory assessor and regulatory agency name.

Emissions Factor Development Quality Indicator Value Rating 0

Supporting Documentation Provided

Regulatory Agency Review

Justification

General

As described in ASTM D7036-12 Standard Practice for
Competence of Air Emission Testing Bodies, does the testing
firm meet the criteria as an AETB or is the person in charge of
the field team a Ql for the type of testing conducted? A
certificate from an independent organization (e.g., Stack
Testing Accreditation Council (STAC), California Air
Resources Board (CARB), National Environmental Laboratory
Accreditation Program (NELAP)) or self declaration provides
documentation of competence as an AETB.

As described in ASTM D7036-12 Standard Practice for
Competence of Air Emission Testing Bodies, does the testing
firm meet the criteria as an AETB or is the person in charge of
the field team a Ql for the type of testing conducted? A
certificate from an independent organization (e.g., STAC,
CARB, NELAP) or self declaration provides documentation of
competence as an AETB.

Was a representative of the regulatory agency on site during
the test?

Is a description and drawing of test location provided?

Is a description and drawing of test location provided?

Has a description of deviations from published test methods
been provided, or is there a statement that deviations were not
required to obtain data representative of typical facility
operation?

Is there documentation that the source or the test company
sought and obtained approval for deviations from the
published test method prior to conducting the test or that the
tester's assertion that deviations were not required to obtain
data representative of operations that are typical for the
facility?

Were all test method deviations acceptable?

Is a full description of the process and the unit being tested
(including installed controls) provided?

Is a full description of the process and the unit being tested
(including installed controls) provided?

Has a detailed discussion of source operating conditions, air
pollution control device operations and the representativeness
of measurements made during the test been provided?

Has a detailed discussion of source operating conditions, air
pollution control device operations and the representativeness
of measurements made during the test been provided?

Were the operating parameters for the tested process unit and
associated controls described and reported?

Is there documentation that the required process monitors
have been calibrated and that the calibration is acceptable?

Was the process capacity documented?

Was the process operating within an appropriate range for the
1 test program objectives?

Were process data concurrent with testing?

1 Were data included in the report for all parameters for which
limits will be set?

Is there an assessment of the validity, representativeness,
achievement of DQO's and usability of the data?

Did the report discuss the representativeness of the facility
operations, control device operation, and the measurements of
the target pollutants, and were any changes from published
test methods or process and control device monitoring
_ protocols identified?	

Have field notes addressing issues that may influence data
quality been provided?	

Were all sampling issues handled such that data quality was
not adversely affected?	

Manual Test Methods

Have the following been included in the report:

Dry gas meter (DGM) calibrations, pitot tube and nozzle
inspections?

Was the DGM pre-test calibration within the criteria specified
by the test method?

Was the DGM post-test calibration within the criteria specified
by the test method?	

Were thermocouple calibrations within method criteria?

Was the pitot tube inspection acceptable?

Mil Were nozzle inspections acceptable?

1 Were flow meter calibrations acceptable?

Was the Method 1 sample point evaluation included in the
report?	

Were the appropriate number and location of sampling points
used?

Were the cyclonic flow checks included in the report?

Did the cyclonic flow evaluation show the presence of an
acceptable average gas flow angle?	

Were the raw sampling data and test sheets included in the
report?

Were all data required by the method recorded?

Were required leak checks performed and did the checks meet
method requirements?	

Was the required minimum sample volume collected?

Did probe, filter, and impinger exit temperatures meet method
j criteria (as applicable)?

AppB_WF_ITR_POL_UNIT_Fac_template.xlsx
Test Quality Rating Tool

-------


A

B

G

H

N

40



¦flH

Did isokinetic sampling rates meet method criteria?





41





Was the sampling time at each point greater than 2 minutes
and the same for each point?





42

Did the report include a description and flow diagram of the
recovery procedures?



Was the recovery process consistent with the method?





43





Were all required blanks collected in the field?





44





Where performed, were blank corrections handled per method
requirements?





45





Were sample volumes clearly marked on the jar or measured
and recorded?





46

Was the laboratory certified/accredited to perform these
analyses?



Was the laboratory certified/accredited to perform these
analyses?





47

Did the report include a complete laboratory report and flow
diagram of sample analysis?



Did the laboratory note the sample volume upon receipt?





48





If sample loss occurred, was the compensation method used
documented and approved for the method?





49





Were the physical characteristics of the samples (e.g., color,
volume, integrity, pH, temperature) recorded and consistent
with the method?





50





Were sample hold times within method requirements?





51





Does the laboratory report document the analytical procedures
and techniques?





52





Were all laboratory QA requirements documented?





53





Were analytical standards required by the method
documented?





54



lllM

Were required laboratory duplicates within acceptable limits?





55





Were required spike recoveries within method requirements?





56



I1I1B

Were method-specified analytical blanks analyzed?





57



If problems occurred during analysis, is there sufficient

umentation to conclude that the problems did not adversely
affect the sample results?





58





Was the analytical detection limit specified in the test report?





59





Is the reported detection limit adequate for the purposes of the
test proqram?





60

Were the chain-of-custody forms included in the report?



Do the chain-of-custody forms indicate acceptable
management of collected samples between collection and
analysis?





61

Instrumental Test Methods



62

Have the following been included in the report:

I	

63

Did the report include a complete description of the
instrumental method sampling system?



Was a complete description of the sampling system provided?





64

Did the report include calibration gas certifications?



Were calibration standards used prior to the end of the
expiration date?





66

Did report include interference tests?



Did interference checks meet method requirements?





67

Were the response time tests included in the report?



Was a response time test performed?





68

Were the calibration error tests included in the report?



Did calibration error tests meet method requirements?





69

Did the report include drift tests?



Were drift tests performed after each run and did they meet
method requirements?





70

Did the report include system bias tests?



Did system bias checks meet method requirements?





71

Were the converter efficiency tests included in the report?



Was the NOX converter test acceptable?





72

Did the report include stratification checks?



Was a stratification assessment performed?





73

Did the report include the raw data for the instrumental
method?



Was the duration of each sample run within method criteria?





74



Ml

Was an appropriate traverse performed during sample
collection, or was the probe placed at an appropriate center
point ("if allowed by the method)?





75





Were sample times at each point uniform and did they meet
the method requirements?





76





Were sample lines heated sufficiently to prevent potential
adverse data quality issues?





77





Was all data required by the method recorded?





88

89

90

91

92

93

Total
Manual Test 0
Instrumental Test 0

AppB_WF_ITR_POL_UNIT_Fac_template.xlsx
Test Quality Rating Tool

-------
Appendix C

FLARE EMISSIONS FACTOR DEVELOPMENT -
PREFERRED CO2 WAVELENGTH

-------
Garwood, Gerri

From:

Sent:

To:

Cc:

Subject:
Attachments:

Cathe Kalisz 

Monday, March 16, 2015 3:30 PM
Garwood, Gerri

Scott Evans (sevans@cleanair.com); Gary Mueller
PFTIR Testing - C02 Bands

Copy of Subset of Flare Master Data 150307_C02 region used.xlsx

Gerri,

Per your request, attached is a file from Clean Air Engineering listing the selected C02 bands from PFTIR tests.
Cathe

Cathe Kalisz, P.E.

Policy Advisor

Regulatory and Scientific Affairs
American Petroleum Institute
1220 L Street NW
Washington, DC 20005
PH: (202) 682-8318
FAX: (202) 682-8270
kaliszc(5)api.org

API

-------
Run Code

C02 Used

M P C_D ET_C P_A_ 1 _ 1

2K

M P C_D ET_C P_A_ 1 _2

2K

M P C_D ET_C P_A_2_ 1

2K

M P C_D ET_C P_A_2_2

2K

M P C_D ET_C P_A_3_ 1

2K

M P C_D ET_C P_A_3_2

2K

M P C_D ET_C P_A_4_ 1

2K

M P C_D ET_C P_A_4_2

2K

M P C_D ET_C P_A_5_ 1

2K

M P C_D ET_C P_A_6_2

2K

M P C_D ET_C P_A_7_ 1

2K

M P C_D ET_C P_A_8_ 1

2K

M P C_D ET_C P_A_8_3

2K

M P C_D ET_C P_A_9_ 1

2K

M P C_D ET_C P_A_9_3

2K

MPC_DET_CP_B_1_1

2K

M P C_D ET_C P_B_2_ 1

2K

M P C_D ET_C P_B_2_2

2K

M P C_D ET_C P_B_3_ 1

2K

M P C_D ET_C P_B_3_2

2K

MPC_DET_CP_B_4_1

2K

M P C_D ET_C P_B_4_2

2K

M P C_D ET_C P_B_6_ 1

2K

M P C_D ET_C P_B_6_2

2K

M P C_D ET_C P_B_8_ 1

2K

M P C_D ET_C P_B_8_2

2K

MPC_DET_CP_C_1_1

2K

M P C_D ET_C P_C_ 1 _2

2K

M P C_D ET_C P_C_2_ 1

2K

M P C_D ET_C P_C_2_2

2K

M P C_D ET_C P_C_3_ 1

2K

M P C_D ET_C P_C_3_2

2K

MPC_DET_CP_C_4_1

2K

M P C_D ET_C P_C_4_2

2K

M P C_D ET_C P_C_5_ 1

2K

M P C_D ET_C P_C_5_2

2K

M P C_D ET_C P_D_2_ 1

2K

M P C_D ET_C P_D_3_ 1

2K

MPC_DET_CP_D_4_1

2K

-------
M P C_D ET_C P_D_5_ 1	2K

M P C_D ET_C P_D_6_ 1	2K

M P C_D ET_C P_D_7_ 1	2K

M P C_D ET_C P_D_8_ 1	2K

M P C_D ET_C P_D_9_ 1	2K

MPC_DET_CP_D_10_1	2K

MPC_DET_CP_E_1_1	2K

M P C_D ET_C P_E_2_ 1	2K

M P C_D ET_C P_E_3_ 1	2K

M P C_D ET_C P_E_5_ 1	2K

M P C_D ET_C P_E_6_ 1	2K

M P C_D ET_C P_E_7_ 1	2K
MPC DET CP LTS 1 1 2K

MPC

DET

CP

LTS

4

1

2K

MPC

DET

CP

LTS

5

1

2K

MPC

DET

CP

LTS

7

1

2K

MPC

DET

CP

LTS

8

1

2K

MPC_TXC_MAIN_A19_1_1 765
MPC_TXC_MAIN_A19_2_1 765
MPC_TXC_MAIN_A19_3_1 765
MPC_TXC_MAIN_A19_4_1 765
MPC_TXC_MAIN_A19_7_1 765

MPC_TXC_MAIN_A11	1	1 765

MPC_TXC_MAIN_A11	2	1 765

MPC_TXC_MAIN_A11_2_2 765

MPC_TXC_MAIN_A11	3	1 765

MPC_TXC_MAIN_A11_3_2 765
MPC_TXC_MAIN_A11_4_1 765

MPC_TXC_MAIN_A11	5	1 765

MPC_TXC_MAIN_A11	6	1 765

MPC_TXC_MAIN_A11	7	1 765

MPC_TXC_MAIN_A11	8	1 765

MPC_TXC_MAIN_A11	9	1 765

MPC_TXC_MAIN_A1 1_10_" 765
MPC_TXC_MAIN_A11_11_' 765
MPC_TXC_MAIN_A11_11J 765
MPC_TXC_MAIN_A11_12_'765
MPC_TXC_MAIN_A11_13_" 765
MPC_TXC_MAIN_A1765
MPC TXC MAIN B 1 1 765

-------
MPC_

_TXC_

MAIN_

B_

_1_

2

765

MPC_

_TXC_

MAIN_

B_

2_

.1

765

MPC_

_TXC_

MAIN_

B_

2_

2

765

MPC_

_TXC_

MAIN_

B_

_3_

.1

765

MPC_

_TXC_

MAIN_

B_

_3_

2

765

MPC_

_TXC_

MAIN_

B_

_4_

.1

765

MPC_

_TXC_

MAIN_

B_

_4_

2

765

MPC_

_TXC_

MAIN_

B_

_4_

3

765

MPC_

_TXC_

MAIN_

B_

_5_

.1

765

MPC_

_TXC_

MAIN_

B_

_5_

2

765

MPC_

_TXC_

MAIN_

B_

_6_

.1

765

MPC_

_TXC_

MAIN_

B_

_6_

2

765

MPC_

_TXC_

MAIN_

B_

1 _

.1

765

MPC_

_TXC_

MAIN_

B_

1 _

2

765

MPC_

_TXC_

MAIN_

B_

_8_

.1

765

MPC_

_TXC_

MAIN_

B_

_8_

2

765

MPC_

_TXC_

MAIN_

B_

_9_

.1

765

MPC_

_TXC_

MAIN_

B_

_9_

2

765

MPC_

_TXC_

MAIN_

B_

_10_1

765

MPC_

_TXC_

MAIN_

B

_10_2

765

MPC_

_TXC_

MAIN_

C

_1_

.1

765

MPC_

_TXC_

MAIN_

C

_1_

2

765

MPC_

_TXC_

MAIN_

C

_2_

.1

765

MPC_

_TXC_

MAIN_

C

_2_

3

765

MPC_

_TXC_

MAIN_

C

_3_

.1

765

MPC_

_TXC_

MAIN_

_C

_3_

2

765

MPC_

_TXC_

MAIN_

D_

_1_

.1

765

MPC_

_TXC_

MAIN_

D_

_1_

2

765

MPC_

_TXC_

MAIN_

D_

_1_

3

765

MPC_

_TXC_

MAIN_

D_

_2_

.1

765

MPC_

_TXC_

MAIN_

D_

_2_

2

765

MPC_

_TXC_

MAIN_

D_

_2_

3

765

MPC_

_TXC_

MAIN_

D_

_3_

.1

765

MPC_

_TXC_

MAIN_

D_

_3_

2

765

MPC_

_TXC_

MAIN_

D_

_3_

3

765

MPC_

_TXC_

MAIN_

D_

_4_

.1

765

MPC_

_TXC_

MAIN_

D_

_4_

2

765

MPC_

_TXC_

MAIN_

D_

_4_

3

765

MPC_

_TXC_

MAIN_

D_

_5_

.1

765

MPC_

_TXC_

MAIN_

D_

_6_

.1

765

-------
MPC_TXC_MAIN_D_7_2 765
M P C_TXC_M AI N_D_8_ 1 765
MPC_TXC_MAIN_D_10_1 765
MPC_TXC_MAIN_D_10_2 765
MPC_TXC_M Al N_E_1 _1 765
MPC_TXC_M Al N_E_1 _3 765
M P C_TXC_M AI N_E_2_ 1 765
M P C_TXC_M AI N_E_2_3 765
MPC_TXC_MAIN_E_3_1 765
MPC_TXC_MAIN_E_3_3 765
MPC_TXC_MAIN_E_4_1 765
MPC_TXC_MAIN_E_4_3 765
MPC_TXC_MAIN_E_5_1 765
MPC_TXC_MAIN_E_5_2 765
SHELL_DP_EPF_A_2.0_1 765
SHELL_DP_EPF_A_3.0_1 765
SHELL_DP_EPF_A_4.0_1 765
SHELL_DP_EPF_A_5.0_1 765
SHELL_DP_EP F_A_5.0_2 765
SHELL_DP_EPF_A_1_1_60 765
SHELL_DP_EPF_A_1_1_55 765
SHELL_DP_EPF_A_1_1_10 765
SHELL_DP_EPF_A_1_1_12 765
SHELL_DP_EPF_B_1_2_10 765
SHELL_DP_EPF_B_51_1 765
SHELL_DP_EP F_B_51 _2 765
SHELL_DP_EP F_B_51 _3 765
SHELL_DP_EPF_B_61_1 765
SHELL_DP_EP F_B_61 _2 765
SHELL_DP_EPF_B_31_1 765
SHELL_DP_EP F_B_31 _2 765
SHELL_DP_EPF_B_51_HiF 765
SHELL_DP_EPF_B_51_HiF 765
SHELL_DP_EP F_B_61 _2 i 765
SHELL_DP_EPF_B_61_2ii 765
SHELL_DP_EPF_B_61_2iii 765
SHELL_DP_EPF_B_61 _2iv 765
SHELL_DP_EP F_B_61 _3 i 765
SHELL_DP_EPF_B_61_3ii 765
SHELL DP EPF B 61 3iii 765

-------
SHELL

DP

EPF

B

61

3iv

765

SHELL

DP

EPF

C

2.5

1

765

SHELL

DP

EPF

C

2.5

2

765

SHELL

DP

EPF

C

3.0

1

765

SHELL

DP

EPF

C

3.0

2

765

SHELL

DP

EPF

C

3.0

3

765

SHELL

DP

EPF

C

4.0

1

765

SHELL

DP

EPF

C

4.0

2

765

SHELL

DP

EPF

C

5.0

1

765

SHELL

DP

EPF

C

6.0

1

765

SHELL

DP

EPF

C

6.0

2

765

SHELL

DP

EPF

C

6.0

3

765

SHELL

DP

EPF

C

6.0

4

765

SHELL

DP

EPF

C

7.0

1

765

SHELL

DP

EPF

C

7.0

2

765

SHELL

DP

EPF

C

8.0

1

765

SHELL

DP

EPF

A

2.0

1 I

1765

SHELL

DP

EPF

A

3.0

1 I

1765

SHELL

DP

EPF

A

4.0

1 I

1765

SHELL

DP

EPF

A

5.0

1 I

1765

SHELL

DP

EPF

A

4.0

1 I

1765

SHELL

DP

EPF

A

5.0

1 I

1765

SHELL

DP

EPF

A

2.0

1 I

1765

SHELL

DP

EPF

A

3.0

1 I

1765

SHELL

DP

EPF

A

4.0

1 I

1765

SHELL

DP

EPF

A

5.0

1 I

1765

SHELL

DP

EPF

A

4.5

1 I

1765

FHR_AU_A_1.0_1	2K

FHR_AU_A_1.0_2	2K

FHR_AU_A_2.0_1	2K

FHR_AU_A_2.0_2	2K

FHR_AU_A_3.0_1	2K

FHR_AU_A_3.0_2	2K

FHR_AU_A_4.0_1	2K

FHR_AU_A_4.0_2	2K

FHR_AU_A_4.0_3	2K

FHR_AU_A_5.0_1	2K

FHR_AU_A_5.0_2	2K

FHR_AU_B_MIN_1	2K

FHR AU B MIN 2	2K

-------
FHR_AU_B_1.0_1	2K

FHR_AU_B_1.0_2	2K

FHR_AU_B_2.0_2	2K

FHR_AU_B_2.0_3	2K

FHR_AU_B_2.5_1	2K

FHR_AU_B_2.5_2	2K

FHR_AU_B_2.5_3	2K

FHR_AU_B_3.5_1	2K

FHR_AU_C_MIN_1	2K

FHR_AU_C_MIN_2	2K

FHR_AU_C_MIN_3	2K

FHR_AU_C_1.0_1	2K

FHR_AU_C_1.0_2	2K

FHR_AU_C_1.0_3	2K

FHR_AU_C_1.0_4	2K

FHR_AU_C_2.0_1	2K

FHR_AU_C_2.0_2	2K

FHR_AU_C_3.0_1	2K

FHR_AU_C_3.0_2	2K

FHR_AU_C_3.7_1	2K

FHR_AU_C_3.7_3	2K

FHR_AU_D_MIN_1	2K

FHR_AU_D_1,0_1	2K

FHR_AU_D_1,0_2	2K

FHR_AU_D_2.0_1	2K

FHR_AU_D_2.0_2	2K

FHR_AU_D_3.0_1	2K

FHR_AU_D_3.0_2	2K

FHR_AU_D_4.0_1	2K

FHR_AU_D_4.0_2	2K

FHR_AU_D_4.0_3	2K

FHR_AU_D_4.3_1	2K

FHR_L0U_A_MIN_1	2K

FHR_L0U_A_MIN_2	2K

FHR_L0U_A_MIN_3	2K

FHR_LOU_A_ 2.0_1	2K

FHR_LOU_A_ 2.0_2	2K

FHR_LOU_A_ 2.0_3	2K

FHR_LOU_A_ 3.0_1	2K

FHR LOU A 3.0 2	2K

-------
FHR_

LOU

_A_

4.0_

_1

2K

FHR_

LOU

_A_

4.0_

_2

2K

FHR_

LOU

_A_

5.0_

_1

2K

FHR_

LOU

_A_

5.0_

_2

2K

FHR_

LOU

_A_

6.0_

_1

2K

FHR_

LOU

_A_

6.0_

_2

2K

FHR_

LOU

_A_

i

LO
00

1

2K

FHR_

LOU

_A_

1

LO
00

2

2K

FHR_

LOU

_B_

MIN

_1

2K

FHR_

LOU

_B_

MIN

_2

2K

FHR_

LOU

_B_

1.0_

_1

2K

FHR_

LOU

_B_

1.0_

_2

2K

FHR_

LOU

_B_

2.0_

_1

2K

FHR_

LOU

_B_

2.0_

_2

2K

FHR_

LOU

_B_

3.0_

_1

2K

FHR_

LOU

_B_

3.0_

_2

2K

FHR_

LOU

_B_

4.0_

_1

2K

FHR_

LOU

_B_

4.0_

_2

2K

FHR_

LOU

_B_

5.0_

_1

2K

FHR_

LOU

_B_

5.0_

_2

2K

FHR_

LOU

_B_

5.7_

_1

2K

FHR_

LOU

_B_

5.7_

_2

2K

FHR_

LOU

_B_

6.4_

_1

2K

FHR_

LOU

B

6.4_

_2

2K

FHR_

LOU

C

MIN

_1

2K

FHR_

LOU

C

MIN.

_2

2K

FHR_

LOU

C

.10



2K

FHR_

LOU

C

.10

_2

2K

FHR_

LOU

C

.2.0.



2K

FHR_

LOU

C

.2.0.

_2

2K

FHR_

LOU

C

.3.0.



2K

FHR_

LOU

C

.3.0.

_2

2K

FHR_

LOU

C

.4.0.



2K

FHR_

LOU

C

.4.0.

_2

2K

FHR_

LOU

C

.5.0.



2K

FHR_

LOU

C

.5.0.

_2

2K

FHR_

LOU

C

.5.5.



2K

FHR_

LOU

C

5.5

_2

2K

TCEQ_STMA_

S1

5_1

765

TCEQ_STMA_

S1

6_1

765

-------
TCEQ_

_STMA_

S1

1 _

.1

765

TCEQ_

_STMA_

S1

_8_

.1

765

TCEQ_

_STMA_

S1

_9_

.1

765

TCEQ_

_STMA_

S2

_1_

.1

765

TCEQ_

_STMA_

S2

_1_

2

765

TCEQ_

_STMA_

S2

_1_

3

765

TCEQ_

_STMA_

S2

_2_

.1

765

TCEQ_

_STMA_

S2

_2_

2

765

TCEQ_

_STMA_

S2

_2_

3

765

TCEQ_

_STMA_

S2

_3_

.1

765

TCEQ_

_STMA_

S2

_3_

2

765

TCEQ_

_STMA_

S2

_3_

3

765

TCEQ_

_STMA_

S3

_1_

.1

765

TCEQ_

_STMA_

S3

_2_

2

765

TCEQ_

_STMA_

S3

_5_

.1

765

TCEQ_

_STMA_

S3

_5_

2

765

TCEQ_

_STMA_

S3

_6_

.1

765

TCEQ_

_STMA_

S3

1 _

.1

765

TCEQ_

_STMA_

S4

_1_

.1

765

TCEQ_

_STMA_

S4

_1_

2

765

TCEQ_

_STMA_

S4

_1_

3

765

TCEQ_

_STMA_

S4

_2_

.1

765

TCEQ_

_STMA_

S4

_2_

2

765

TCEQ_

_STMA_

S4

_2_

3

765

TCEQ_

_STMA_

S4

_3_

.1

765

TCEQ_

_STMA_

S4

_3_

2

765

TCEQ_

_STMA_

S4

_3_

3

765

TCEQ_

_STMA_

S4

_4_

.1

765

TCEQ_

_STMA_

S4

_5_

.1

765

TCEQ_

_STMA_

S4

_6_

.1

765

TCEQ_

_STMA_

S4

1 _

.1

765

TCEQ_

_STMA_

S4

_8_

.1

765

TCEQ_

_STMA_

S4

_9_

.1

765

TCEQ_

_STMA_

S4

_10_1

765

TCEQ_

_STMA_

S4

_11

IJ

765

TCEQ_

_STMA_

S5

_1_

.1

765

TCEQ_

_STMA_

S5

_1_

2

765

TCEQ_

_STMA_

S5

_1_

3

765

TCEQ_

_STMA_

S5

_2_

.1

765

TCEQ_

_STMA_

S5

_3_

.1

765

-------
TCEQ_

_STMA_

S5

_3_

_2

765

TCEQ_

_STMA_

S5

_3_

_3

765

TCEQ_

_STMA_

S5

_4_

_1

765

TCEQ_

_STMA_

S5

_4_

_2

765

TCEQ_

_STMA_

S5

_4_

_3

765

TCEQ_

_STMA_

S5

_5_

_1

765

TCEQ_

_STMA_

S5

_6_

_1

765

TCEQ_

_STMA_

S5

_6_

_2

765

TCEQ_

_STMA_

S5

_6_

_3

765

TCEQ_

_STMA_

S6

_1_

_1

765

TCEQ_

_STMA_

S6

_1_

_2

765

TCEQ_

_STMA_

S6

_1_

_3

765

TCEQ_

_STMA_

S6

_2_

_1

765

TCEQ_

_STMA_

S6

_2_

_2

765

TCEQ_

_STMA_

S6

_2_

_3

765

TCEQ_

_STMA_

S6

_3_

_1

765

TCEQ_

_STMA_

S6

_3_

_2

765

TCEQ_

_STMA_

S6

_3_

_3

765

TCEQ_

_STMA_

S6

_4_

_1

765

TCEQ_

_STMA_

S6

_4_

_2

765

TCEQ_

_STMA_

S6

_4_

_3

765

TCEQ_

_STMA_

S6

_5_

_1

765

TCEQ_

_STMA_

S6

_6_

_1

765

TCEQ_

_STMA_

S7

_1_

_1

765

TCEQ_

_STMA_

S7

_1_

_2

765

TCEQ_

_STMA_

S7

_2_

_1

765

TCEQ_

_STMA_

S7

_2_

_2

765

TCEQ_

_STMA_

S7

_2_

_3

765

TCEQ_

_STMA_

S7

_3_

_1

765

TCEQ_

_STMA_

S7

_3_

_2

765

TCEQ_

_STMA_

S7

_4_

_1

765

TCEQ_

_STMA_

S7

_5_

_1

765

TCEQ_

_STMA_

S7

_6_

_1

765

TCEQ_

_STMA_

S8

_1_

_1

765

TCEQ_

_STMA_

S8

_2_

_1

765

TCEQ_

_STMA_

S8

_3_

_1

765

TCEQ_

_STMA_

S8

_4_

_1

765

TCEQ_

_STMA_

S8

_5_

_1

765

TCEQ_

_STMA_

S9

_1_

_1

765

TCEQ_

_STMA_

S9

_2_

_1

765

-------
TCEQ_

_STMA_S9_3_1



765

TCEQ_

_STMA_S9_4_1



765

TCEQ_

_STMA_S9_5_1



765

TCEQ_

_STMA_S10_

_1_

.1

765

TCEQ_

_STMA_S10_

2_

.1

765

TCEQ_

_STMA_S10_

3_

.1

765

TCEQ_

_STMA_S10_

4_

.1

765

TCEQ_

_STMA_S11_

_1_

.1

765

TCEQ_

_STMA_S11_

2_

.1

765

TCEQ_

_STMA_S11_

3_

.1

765

TCEQ_

_STMA_S11_

4_

.1

765

TCEQ_

_STMA_S12_

_1_

.1

765

TCEQ_

_STMA_S12_

_1_

2

765

TCEQ_

_STMA_S12_

2_

.1

765

TCEQ_

_STMA_S12_

2_

2

765

TCEQ_

_STMA_S12_

3_

.1

765

TCEQ_

_STMA_S12_

3_

2

765

TCEQ_

_STMA_S12_

4_

.1

765

TCEQ_

_STMA_S13_

_1_

.1

765

TCEQ_

_STMA_S13_

2_

.1

765

TCEQ_

_STMA_S13_

3_

.1

765

TCEQ_

_STMA_S13_

4_

.1

765

TCEQ_

_STMA_S13_

4_

2

765

TCEQ_

_STMA_S13_

4_

3

765

TCEQ_

_STMA_S13_

5_

.1

765

TCEQ_

_STMA_S14_

_1_

.1

765

TCEQ_

_STMA_S14_

4_

.1

765

TCEQ_

_AIRA_A1_1_

_1



765

TCEQ_

_AIRA_A2_1_

_1



765

TCEQ_

_AIRA_A2_1_

_2



765

TCEQ_

_AIRA_A2_1_

_3



765

TCEQ_

_AIRA_A2_3_

_1



765

TCEQ_

_AIRA_A2_4_

_1



765

TCEQ_

_AIRA_A2_4_

_2



765

TCEQ_

_AIRA_A2_4_

_3



765

TCEQ_

_AIRA_A2_5_

_1



765

TCEQ_

_AIRA_A2_5_

_2



765

TCEQ_

_AIRA_A2_5_

_3



765

TCEQ_

_AIRA_A3_1_

_1



765

TCEQ_

_AIRA_A3_1_

_2



765

-------
TCEQ.

_AIRA_

_A3_

_1_

.3

765

TCEQ.

_AIRA_

_A3_

_2_

.1

765

TCEQ.

_AIRA_

_A3_

_2_

.2

765

TCEQ.

_AIRA_

_A3_

_2_

.3

765

TCEQ.

_AIRA_

_A3_

_3_

.1

765

TCEQ.

_AIRA_

_A3_

_4_

.1

765

TCEQ.

_AIRA_

_A3_

_4_

.2

765

TCEQ.

_AIRA_

_A3_

_4_

.3

765

TCEQ.

_AIRA_

_A3_

_5_

.1

765

TCEQ.

_AIRA_

_A3_

_6_

.1

765

TCEQ.

_AIRA_

_A3_

_6_

.2

765

TCEQ.

_AIRA_

_A3_

_6_

.3

765

TCEQ.

_AIRA_

_A4_

_1_

.1

765

TCEQ.

_AIRA_

_A4_

_1_

.2

765

TCEQ.

_AIRA_

_A4_

_1_

.3

765

TCEQ.

_AIRA_

_A4_

_2_

.1

765

TCEQ.

_AIRA_

_A4_

_3_

.1

765

TCEQ.

_AIRA_

_A4_

_3_

.2

765

TCEQ.

_AIRA_

_A4_

_3_

.3

765

TCEQ.

_AIRA_

_A4_

_4_

.1

765

TCEQ.

_AIRA_

_A4_

_4_

.2

765

TCEQ.

_AIRA_

_A4_

_4_

.3

765

TCEQ.

_AIRA_

_A4_

_5_

.1

765

TCEQ.

_AIRA_

_A4_

_5_

.2

765

TCEQ.

_AIRA_

_A4_

_5_

.3

765

TCEQ.

_AIRA_

_A4_

_6_

.1

765

TCEQ.

_AIRA_

_A5_

_1_

.1

765

TCEQ.

_AIRA_

_A5_

_1_

.2

765

TCEQ.

_AIRA_

_A5_

_1_

.3

765

TCEQ.

_AIRA_

_A5_

_2_

.1

765

TCEQ.

_AIRA_

_A5_

_3_

.1

765

TCEQ.

_AIRA_

_A5_

_3_

.2

765

TCEQ.

_AIRA_

_A5_

_3_

.3

765

TCEQ.

_AIRA_

_A5_

_4_

.1

765

TCEQ.

_AIRA_

_A5_

_5_

.1

765

TCEQ.

_AIRA_

_A5_

_5_

.2

765

TCEQ.

_AIRA_

_A5_

_5_

.3

765

TCEQ.

_AIRA_

_A6_

_1_

.1

765

TCEQ.

_AIRA_

_A6_

_1_

.2

765

TCEQ.

_AIRA_

_A6_

_1_

.3

765

-------
TCEQ_AIRA_A6_

_2_

.1

765

TCEQ_AIRA_A6_

_3_

.1

765

TCEQ_AIRA_A6_

_3_

2

765

TCEQ_AIRA_A6_

_3_

3

765

TCEQ_AIRA_A6_

_4_

.1

765

TCEQ_AIRA_A6_

_4_

2

765

TCEQ_AIRA_A6_

_4_

3

765

TCEQ_AIRA_A6_

_5_

.1

765

TCEQ_AIRA_A6_

_6_

.1

765

TCEQ_AIRA_A7_

_1_

.1

765

TCEQ_AIRA_A7_

_1_

2

765

TCEQ_AIRA_A7_

_2_

.1

765

TCEQ_AIRA_A7_

_2_

2

765

TCEQ_AIRA_A7_

_3_

.1

765

TCEQ_AIRA_A7_

_3_

2

765

TCEQ_AIRA_A7_

_4_

.1

765

TCEQ_AIRA_A7_

_5_

.1

765

INE0S_BD_1





1K

INE0S_BD_1 A





1K

INE0S_BD_1 B





1K

INE0S_BD_2





1K

INE0S_BD_3





1K

INE0S_BD_4





1K

INE0S_BD_5





1K

INE0S_BD_6





1K

INE0S_BD_7





1K

INE0S_BD_8





1K

INE0S_BD_9





1K

INEOS_BD_10





1K

INE0S_BD_11





1K

INE0S_BD_12





1K

INE0S_BD_13





1K

INE0S_BD_14





1K

INE0S_BD_15





1K

INE0S_BD_16





1K

INE0S_BD_17





1K

INE0S_BD_17A





1K

INEOS BD 18





1K

-------