r/EPA
United States In.di^aat&jvironmental Research EPA-600/7-79-029c
Environmental Protection Laboratory % February 19/»
Agency Research Tr-angle Park NC 27711
Emissions Assessment
of Conventional
Stationary Combustion
Systems;
Volume II.
Internal Combustion
Sources
Interagency
Energy/Environment
R&D Program Report
-------
-------
EPA-600/7-79-029c
February 1979
Emissions Assessment of
Conventional Stationary
Combustion Systems;
Volume II. Internal
Combustion Sources
by
C.C. Shih, J.W. Hamersma, D.G. Ackerman,
R.G. Beimer, M.L. Kraft, and M.M. Yamada
TRW, Inc.
One Space Park
Redondo Beach, California 90278
Contract No. 68-02-2197
Program Element No. EHE624A
EPA Project Officer: Ronald A. Venezia
Industrial Environmental Research Laboratory
Office of Energy, Minerals, and Industry
Research Triangle Park, NC 27711
Prepared for
U.S. ENVIRONMENTAL PROTECTION AGENCY
Office of Research and Development
Washington, DC 20460
-------
ABSTRACT
Emissions from gas- and oil-fueled gas turbines and reciprocating engines
for electricity generation and industrial applications are assessed in this
report. The assessment method involved a critical examination of existing
emissions data, followed by the conduct of a measurement program to fill data
gaps based on a phased sampling and analysis strategy.
In the first phase of the measurement program, one gas-fueled gas turbine,
five distillate-oil fueled gas turbines, and five diesel engines were selected
for testing. Evaluation of test results led to the recommendation for addi-
tional tests to determine SCL and organic emissions from diesel engines which
were subsequently conducted at three of the diesel engine sites previously
tested.
The results of the emissions assessment indicate that internal combustion
sources contribute significantly to the national emissions burden. NO ,
A
hydrocarbon and CO emissions from internal combustion sources account for
approximately 20 percent, 9 percent, and 1 percent of the emissions of these
pollutants from all stationary sources. The source severity factor, defined
as the ratio of the calculated maximum ground level concentration of the
pollutant species to the level at which a potential environmental hazard
exists, was used to identify pollutants of environmental concern.
iii
-------
CONTENTS
Page
Abstract ii
1. Summary and Conclusions 1
1.1 Internal Combustion Source Description 1
1.2 The Existing Emissions Data Base . 3
1.3 The Source Measurement Program . 3
1.3.1 Level I Field Testing 4
1.3.2 Modified Level I Laboratory Analysis 4
1.3.3 Level II Field Testing 7
1.3.4 Level II Laboratory Analysis 7
1.3.5 Results 8
1.4 Conclusions 11
2. Introduction 14
3. Source Description . 17
3.1 Process Characteristics ........... . 17
3.2 Industry Profile 19
3.3 Population Characteristics 25
4. Emissions ........ 30
4.1 Evaluation of Existing Emissions Data ..... . . 30
4.1.1 Criteria for Evaluating the Adequacy of Emissions
Data 30
4.1.2 Existing Emissions Data for Gas Turbines ....... 31
4.1.3 Existing Emissions Data for Reciprocating Engines . . 49
4.2 Emissions Data Acquisition ..... 58
4.2.1 Selection of Test Facilities 58
4.2.2 Field Testing ....... 59
4.2.3 Laboratory Analysis Procedures 63
-------
CONTENTS (Continued)
PagjL
4.2.4 Level II Analysis 84
4.2.5 Test Results 88
4.3 Analysis of Test and Data Evaluation Results 116
4.3.1 Emissions of Criteria Pollutants 116
4.3.2 Emissions of SO,, Particulate Sulfate, and Fine
Particulates 125
4.3.3 Emissions of Trace Elements 128
4.3.4 Emissions of Organics and Polycyclic Organic Matter . . 136
4.3.5 Summary of Status of Emissions Data Base 139
5. Total Emissions 141
5.1 Current and Future Fuel Consumption 141
5.2 Current Nationwide Emissions 146
5.3 Future Nationwide Emissions 149
6. References 154
Appendix A 158
Appendix B 170
Appendix C 175
Appendix D 130
Metric Conversion Factors and Prefixes 226
-------
TABLES
Number Page
1 Summary of Results of Emissions Assessment for Gas Fueled
Internal Combustion Sources 9
2 Summary of Results of Emissions Assessment for Oil Fueled
Internal Combustion Sources 10
3 Principal Applications and Major Manufacturers of Utility
and Industrial Gas Turbines 20
4 Principal Applications and Major Manufacturers of Utility
and Industrial Internal Combustion Reciprocating Engines . . 21
5 Current and Projected Gas Turbine Installed Capacity for
Utility and Industrial Applications 23
6 Current and Projected Reciprocating Engine Installed Capacity
for Utility and Industrial Applications 24
7 Partial Listing of Turbine Installations with Water or Steam
Injection for NO Control 28
/\
8 Existing Emissions Data for Industrial Gas-Fueled Gas
Turbines Under Base Load Conditions . 34
9 Existing Emissions Data for Industrial Distillate Oil-Fueled
Gas Turbines Under Base Load Conditions 35
10 Postulated Operating Cycle for Electric Utility Gas
Turbines 38
11 Existing Emissions Data for Electricity Generation Gas-Fueled
Gas Turbines Under Base Load Conditions ........... 38
12 Existing Emissions Data for Electricity Generation Distillate
Oil-Fueled Gas Turbines Under Base Load Conditions 40
13 Existing Trace Element Emissions Data for Electricity
Generation Distillate Oil Turbines Under Base Load
Conditions 43
14 ASTM-D-2880-76-Trace Metal Limits for Gas Turbine
Fuels 44
15 Maximum Trace Metal Emissions Based on ASTM-D-2880-76 Gas
Turbine Fuel Limits ..................... 44
16 POM Emissions Data for an Electricity Generation Distillate
Oil-Fueled Gas Turbine Operating at 70 Percent Load ..... 45
17 Emission Factors and Mean Source Severities of Air Emissions
from Gas-Fueled Gas Turbines 47
vii
-------
TABLES (Continued)
Number Pa9e.
18 Emission Factors and Mean Source Severities of Air Emissions
from Distillate Oil-Fueled Gas Turbines 48
19 Existing Emissions Data for Electricity Generation/Industrial
Gas-Fueled Stationary Reciprocating Engines Under Base Load
Conditions 51
20 Existing Emissions Data for Electricity Generation/Industrial
Diesel-Fueled Stationary Reciprocating Engines Under Base
Load Conditions 54
21 Emission Factors and Mean Source Severities of Air Emissions
from Reciprocating Gas Engines 56
22 Emission Factors and Mean Source Severities of Air Emissions
from Reciprocating Distillate Oil Engines 57
23 Characteristics of Internal Combustion Sites Tested 60
24 Analytical SASS Train Detection Limits 71
25 Mass to Charge Values (m/e)s Monitored 81
26 Minimum List of ROM's Monitored 82
27 Level II Samples Analyzed for Internal Combustion Sites ... 85
28 Level II Organic Analysis Conditions 86
29 Operating Load and Fuel Feed Rates of Internal Combustion
Sources Tested 89
30 Particulate and SO Emissions from Internal Combustion
Sources Tested 90
31 Summary of Results from Specific Inorganic Analyses 92
32 Level II Controlled Condensation Train Analytical Results . . 93
33 Volatile and Nonvolatile Organic Emissions from Internal
Combustion Systems 94
34 Results of GC-TCO Analysis for C7-C,, Hydrocarbons in Level I
Samples ( .'° 96
35 Gravimetric Results for Internal Combustion Sites 101
36 Classes of Compounds Identified in Infrared Spectra of Sample
Concentrates and LC Fractions 105
37 Classes of Compounds Identified in Infrared Spectra of LC
Fractions of Samples from Oil Turbines 106
38 LC/TCO/GRAV Summary for SASS Samples from Sites 306-313-2 . . IQS
39 Classes of Compounds Identified in Infrared Spectra of LC
Fractions of Samples from Distillate Oil Reciprocating
Engines 109
viii
-------
TABLES (Continued)
Number Page
40 Low Resolution Mass Spectroscopy Results for Diesel Engine
Sites Ill
41 POM Emissions from Diesel Engine Sites 309-313 ....... 112
42 Summary of Emission Factor Data for Particulate, SOX and
Total Organics from Internal Combustion Sources Tested ... 117
43 Comparison of Criteria Pollutant Emissions Factors for Gas
and Distillate Oil-Fueled Gas Turbines 119
44 Comparison of Criteria Pollutant Emission Factors for Gas
and Distillate Oil Engines 121
45 Mean Source Severity Factors for Criteria Pollutants .... 124
46 Summary of Emission Factor Data for Particulate Sulfate from
Internal Combustion Sources Tested 126
47 Summary of Emission Factor Data for Trace Elements from Elec-
tricity Generation Distillate Oil-Fueled Gas Turbines Tested. 129
48 Summary of Emission Factor Data for Trace Elements from
Electricity Generation Distillate Oil-Fueled Gas Turbines
Based on Combined Current Study and Existing Data 132
49 Mean Source Severity Factors for Trace Element Emissions
from Distillate Oil-Fueled Gas Turbines .... 132
50 Summary of Emission Factor Data for Trace Elements from
Electricity Generation Distillate Oil Engines Tested .... 134
51 Mean Source Severity Factors for Trace Element Emissions from
Distillate Oil Engines 136
52 Comparison of Trace Element Emission Factors for Distillate
Oil-Fueled Gas Turbines and Distillate Oil Engines 137
53 Summary of POM Emission Factor Data from Electricity
Generation Distillate Oil Engines Tested . 138
54 Mean Source Severity Factors for POM Emissions from
Electricity Generation Distillate Oil Engines ... 140
55 1978 and Projected 1985 Fuel Consumption for Electricity
Generation Internal Combustion Sources ..... 143
56 Projected 1985 Domestic Natural Gas and Crude Oil
Production 144
57 1978 and Projected 1985 Fuel Consumption for Industrial
Internal Combustion Sources ................. 145
58 Current Nationwide Emissions of Criteria Pollutants from
Electricity Generation and Industrial Internal Combustion
Sources .................. 147
-------
TABLES (Continued)
Number
59 Current Nationwide Emissions of Trace Elements from
Electricity Generation and Industrial Internal Combustion
Sources ..... 148
60 Current Nationwide Emissions of Polycyclic Organic Matter
from Electricity Generation and Industrial Internal
Combustion Sources ^
61 Projected 1985 Nationwide Emissions of Criteria Pollutants
from Electricity Generation and Industrial Internal
Combustion Sources 150
62 Projected 1985 Nationwide Emissions of Trace Elements from
Electricity Generation and Industrial Internal Combustion
Sources 151
63 Projected 1985 Nationwide Emissions of Polycyclic Organic
Matter from Electricity Generation and Industrial Internal
Combustion Sources 152
A-l Maximum Ratio of Extreme Ranking Observations 168
B-l Estimated Plume Rises for Internal Combustion Sources .... 173
C-l Elemental Composition and Higher Heating Value of Fuels . . . 178
D-l SASS Train Distribution for Specific Inorganics, Gas-Fueled
Gas Turbine (Site 110) T81
D-2 SSMS Data for Gas-Fueled Gas Turbine 182
D-3 SASS Train Distribution for Specific Inorganics, Distillate
Oil-Fueled Gas Turbine (Sites 111, 112) 184
D-4 SASS Train Distribution for Specific Inorganics, Distillate
Oil-Fueled Gas Turbine (Sites 306, 307, 308) 185
D-5 SSMS Data for Distillate Oil-Fueled Gas Turbines (Site 111) . 186
D-6 SSMS Data for Distillate Oil-Fueled Gas Turbines (Site 112) . 188
D-7 SSMS Data for Distillate Oil-Fueled Gas Turbines (Site 306) . 190
D-8 SSMS Data for Distillate Oil-Fueled Gas Turbines (Site 307) . 192
D-9 SSMS Data for Distillate Oil-Fueled Gas Turbines (Site 308) . 194
D-10 SASS Train Distribution for Specific Inorganics, Distillate
Oil Reciprocating Engine (Sites 309, 310, 311, 312, 313) . . 195
D-11 SSMS Data for Distillate Oil Reciprocating Engine (Site 309). 197
D-12 SSMS Data for Distillate Oil Reciprocating Engine (Site 310). 199
D-l3 SSMS Data for Distillate Oil Reciprocating Engine (Site 311). 201
D-14 SSMS Data for Distillate Oil Reciprocating Engine (Site 312). 203
D-15 SSMS Data for Distillate Oil Reciprocating Engine (Site 313). 205
-------
TABLES (Continued)
Number Page
D-16 Level II Organic Analysis Results - Compounds Found in
Sample 309-2-XRPF-MRPR 207
D-17 Level II Organic Analysis Results - Compounds Found in
Sample 309-2-CD-LE ... 214
D-18 Level II Organic Analysis Results - Compounds Found in
Sample 312-2-XRPF-MRPR 216
D-19 Level II Organic Analysis Results - Compounds Found in
Sample 312-2-CD-LE 220
D-20 Level II Organic Analysis Results - Compounds Found in
Sample 313-2-XRPF-MRPR 221
D-21 Level II Organic Analysis Results - Compounds Found in
Sample 313-2-CD-LE 225
XI
-------
FIGURES
Number
1 Basic Level 1 Sampling and Analytical Plan for Particulates
and Gases 5
2 Average Size of Gas Turbines Ordered by the Oil and Gas
Industry 26
3 Schematic of Source Assessment Sampling System (SASS) .... 61
4 Typical Internal Combustion Unit 64
5 Schematic of Controlled Condensation System 65
6 Level I Inorganic Analysis Plan 67
7 Level I Organic Analysis Flow Chart 73
8 Level I Organic Analysis Methodology .... 74
9 EACCS Sample Control Numbers 100
10 Reconstructed Gas Chromatogram of Sample 309-2-XRPF-MRPR . . 114
11 Mass Chromatogram of M/e = 57 Showing Non-Aromatic Nature of
Sample 309-2-XRPF-MRPR . 115
A-l Step 1 Screening Mechanism for Emissions Data ........ 160
xii
-------
1. SUMMARY AND CONCLUSIONS
Emissions from gas- and oil-fueled gas turbines and reciprocating engines
for electricity generation and industrial applications are assessed in this
report. The assessment method involved a critical examination of existing
emissions data, followed by the conduct of a measurement program to fill data
gaps based on phased sampling and analysis strategy.
The phased approach to environmental assessments is designed to provide
comprehensive emissions information on all process waste streams in a cost
effective manner. To achieve this goal, two distinct sampling and analysis
levels are being employed in this program. Level I utilizes semiquantitative
(± a factor of 3) techniques of sample collection and laboratory and field
analyses to: provide preliminary emissions data for waste streams and pollu-
tants not adequately characterized; identify potential problem areas; and
prioritize waste streams and pollutants in those streams for further, more
quantitative testing. Using the information from Level I, available resources
can be directed toward Level II testing which involves specific, quantitative
analysis of components of those streams which do contain significant pollutant
loadings. The data developed at Level II is used to identify control techno-
logy needs and to further define the environmental hazard associated with each
process stream. A third phase, Level III, which is outside the scope of this
program, employs continuous or periodic monitoring of specific pollutants
identified at Level II so that the emission rates of these critical components
can be determined exactly as a function of time and operating conditions.
1.1 INTERNAL COMBUSTION SOURCE DESCRIPTION
Stationary internal combustion sources for electricity generation and
industrial applications are grouped into two categories: gas turbines and
reciprocating engines. Gas turbines may be classified into three general
types: simple open cycle, regenerative open cycle, and combined cycle.
1
-------
Regenerative type gas turbines constitute only a very small fraction of the
total gas turbine population. Emissions from identical gas turbines used in
the combined cycle and in the simple cycle are the same. Therefore, only
emissions from simple cycles need to be evaluated.
Reciprocating internal combustion engines may be classified into spark
and compression ignition (diesel) engines. All distillate oil reciprocating
engines are compression ignited, and all gasoline reciprocating engines are
spark ignited. Spark ignition gasoline engines have very limited use for
electricity generation and industrial application because of their poor part
load economy and cost of fuel. Gas reciprocating engines, with the exception
of the dual-fuel type, are spark ignited. Gas can only be used in a compres-
sion ignition engine if a small amount of diesel fuel is injected into the
compressed air/gas mixture to initiate combustion.
The principal application areas for gas turbines and reciprocating
engines are: electricity generation, oil and gas transmission, natural gas
processing, oil and gas production and exploration. For gas turbines, the
total 1978 installed capacity is 50,800 MW for electricity generation and
9,400 MW for industrial applications. For reciprocating engines, the total
1978 installed capacity is 5,300 MW for electricity generation and 19,500 MW
for industrial applications.
The current average size of electricity generation gas turbines is
approximately 31 MW. As of December 31, 1976, the capacity average age for
electricity generation gas turbines was approximately 5 years. Industrial gas
turbines were estimated to have an average size of 2.2 MW. For reciprocating
engines, the average size unit for electricity generation is 1.9 MW (2,500
HP), and the average size unit for oil and gas transmission is 1.5 MW (2,000
HP). Average age for reciprocating engines is approximately 10 years.
Air pollution control equipment is generally not installed on gas turbines
or reciprocating engines. However, there is increasing recognition that
water and steam injection are valid techniques for controlling NO emissions
A
from gas turbines. In addition, to reduce visible smoke emissions from oil-
fueled gas turbines, fuel additives such as soluble compounds of barium,
manganese and iron are often employed.
-------
1.2 THE EXISTING EMISSIONS DATA BASE
Air emissions from the flue gas stacks are the only significant emissions
from electricity generation and industrial gas turbines and reciprocating
engines. A major task in this program has been the identification of gaps and
inadequacies in the existing data base for these flue gas emissions. Decisions
as to the adequacy of the data base were made using criteria developed by
considering both the reliability and variability of the data. Estimated envi-
ronmental risks associated with the emission of each pollutant were also
considered in the determination of the need for, and extent of, the phased
sampling and analysis program.
The evaluation of emissions data has indicated that the existing emissions
data base is adequate for gas-fueled turbines and reciprocating engines. For
distillate oil-fueled gas turbines, the existing data base for NO , total
/\
hydrocarbons, CO, particulate, SO^ and SO, emissions is adequate. However,
the existing data base for trace elements and specific organic emissions was
inadequate. For distillate oil reciprocating engines, the existing data base
for NO , total hydrocarbons, CO, and S09 emissions is adequate. The existing
X c.
data base for particulates, SO-, trace elements and specific organic emissions
was found to be inadequate.
1.3 THE SOURCE MEASUREMENT PROGRAM
Because of the deficiencies in the existing emissions data base, eleven
internal combustion sites were selected for testing to provide a better
characterization of the emissions associated with these sources. The sites
tested included one gas-fueled gas turbine, five distillate oil-fueled gas
turbines, and five distillate oil reciprocating engines (diesel engines). A
gas-fueled gas turbine site was included to assure that previously unidentified
pollutants are not being emitted in environmentally unacceptable quantities.
Specific sites were chosen based on the representativeness of the sites as
measured against the important characteristics of systems within each source
category, including engine model, rated capacity, age and pollution control
method.
-------
Test results from the first phase were evaluated to determine the need
for and type of additional sampling and analysis. These evaluations led to
the recommendation of additional tests to determine S03 and organic emissions
from electricity generation distillate oil reciprocating engines. Level II
tests were subsequently conducted at three of the diesel engine sites previous-
ly tested.
1.3.1 Level I Field Testing
The Source Assessment Sampling System (SASS) train, developed under
contract to EPA, was used to collect both vaporous and particulate emissions
in quantities sufficient for the wide range of analyses needed to adequately
characterize emissions from internal combustion sources. Briefly, the SASS
train consists of a conventional heated probe, three cyclones and a filter in
a heated oven which collect four particulate size fractions, a gas conditioning
system, an XAD-2 polymer adsorbent trap to collect gaseous organics and some
inorganics, and impingers to collect the remaining gaseous inorganics and trace
3
elements. The train is run until at least 30 m of gas has been collected.
This criterion was established in conjunction with analytical technique sen-
sitivities, to ensure that any emission which would increase the ambient
3
loading by more than 1 yg/m will be detected. The cyclones were deleted as
particulate loadings were too low to provide weighable quantities of samples
in each cyclone.
In addition to using the SASS train for stack gas sampling, other equip-
ment was employed to collect those components not analyzable from the train
samples. A gas chromatograph (GC) with ionization detection was used in the
field to analyze C^-Cg hydrocarbons collected in gas sampling bags. Addition-
nally, these samples were analyzed for CO, C02> 02 and S02 by GC using a thermal
conductivity detector.
1-3.2 Modified Level I Laboratory Analysis
The basic Level I sampling and analytical plan for particulate and gaseous
emissions is depicted in Figure 1. A brief description of inorganic and organic
analyses performed and the deviations from the basic Level I procedure follows.
-------
PARTICULATE
MATTER '
I
S02/so3 ,
i
," "" I
i
SOURCE *
I
OPACITY
(STACKS) 1
i
1
GAS
'WEIGH
INDIVIDUAL
CATCHES
IF INORGANICS
ARE GREATER THAN
10% OF TOTAL CATCH.
-
^1A11 *
PROBE AND
OfC 1 C\ MP
RINSES
SASS TRAIN GAS
CONDENSATE
SASS TRAIN
IMPINGERS 2ND ^
3-10u* *
1 1/j * h
*
C6
ORGANIC
MATERIAL C1 - C^
ONE-SITE GAS
CHKUMA'IOORAPHY
XAD-2
AUiURBLK, "~» t
MODULE RINSE
PH
ON-SITE GAS IN
CHROMATOGRAPHY
. iMnnrANir' ELEMENTS (SSMS)/>
» INORGAIMICj SELECTED ANIONS
ORGANICS f"iAlct*rT,P^TIUN - "" PHYSirAI
FVTDArr INTO FRACTIONS, SFPARATIPiM
EXTRACT ip/ipAjr ' ^ DR^ANirS JtrAKAMUN
1 LR/IR/'MS wnwu^ INTO FRAaiONS,
_ . LR/IR/MS
isjnprAMirc;! ELEMENTS (SSMS) AND ' '
iiNUK^AiNi^ij SELECTED ANIONS
INORGANICS ELEMENTS AND
St. As, Sb,Hg SELECTED ANIONS
i Mr,or A Mir c ELEMENTS (SSMS) AND
INORGANICS SELECTED ANIONS
PHYSICAL SEPARATION
ORGANICS INTO FRACTIONS
tr /to /MC
ELEMENTS (SSMS) AND
' ShLbClbD ANIONb
ORGANICS ALIQUOT FOR GAS
AlRACTION > ( _ r ClIKOMA TOGKAPHIC
7 16 ANALYSIS
YSICAL SEPARATION
lUdt-LAiitb ORGANICS PHYSICAL SEPARATION
'6 LC/IR/MS
Figure 1. Basic Level 1 Sampling and Analytical Plan
for Participates and Gases
-------
Inorganic Analyses--
Level I analysis was used for all inorganics analyses. It was designed
to identify all elemental species in the SASS train fractions and to provide
semiquantitative data on the elemental distributions and total emission
factors. The primary tool for Level I inorganic analysis is the Spark Source
Mass Spectrograph (SSMS). SSMS data were supplemented with Atomic Absorption
Spectrometry (AAS) data for Hg, As, and Sb and with standard method determina-
tions for chlorides.
The following SASS train fractions were analyzed for their elemental
composition: (1) the particulate filter, (2) the XAD-2 sorbent, and (3) a
composite sample containing portions of the XAD-2 module condensate and HMO^
rinse, and the first impinger solution. Fuel was also analyzed for the oil-
fired sources.
Organic Analyses--
Level I organic analysis provides data on volatile (Cy-C,,-) and nonvolatile
organic compounds (> C,g) to supplement data for gaseous organics (C,-Cg)
measured in the field. Organics in the XAD-2 module condensate trap and XAD-2
resin were recovered by methylene chloride extraction. SASS train components
including the tubing were carefully cleaned with methylene chloride or
methylene chloride/methanol solvent to recover all organics collected in the
SASS train.
Because all samples are too dilute to detect organic compounds by the
majority of instrumental techniques employed, the first step in the analysis
was to concentrate the sample fractions from as much as 1000 ml to 10 ml in a
Kuderna-Danish apparatus in which rinse solvent is evaporated while the
organics of interest are retained . Kuderna-Danish concentrates were then
evaluated by gas chromatography (GC), infrared spectrometry (IR), liquid
chromatography (LC), gravimetric analysis, and sequential gas chromatography/
*
Kuderna-Danish is a glass apparatus for evaporating bulk amounts of
solvents.
-------
*
mass spectrometry (GC/MS) . The extent of the organic analysis is determined
by the stack gas concentrations found for total organics (volatile and non-
vplatile). If the total organics indicate a stack gas concentration below
2
500 yg/m , further analysis is not conducted. If the concentration is above
3
500 yg/m , a class fractionation by liquid chromatography is conducted
followed by GC and IR analyses.
The organic analysis plan is compatible with the performance of additional
Level II analyses at several points. For example, in the case of internal
combustion sources, polycyclic organic matter (POM) emission information was
desired and aliquots of concentrates from various portions of the SASS train
were analyzed for these species by GC/MS.
1.3.3 Level II Field Testing
At each of the diesel engine sites, the Goksoyr-Ross controlled condensa-
tion train was used for the measurement of oxidized sulfur emissions. In this
approach, SO- is separated from the gas stream by cooling the flue gas below
the dew point for S03 (HgSO^) but above the dew point of water. Particulate
matter (including metallic sulfates) is removed by means of a heated quartz
glass filter in a filter holder kept above 260°C. A condensation coil for SO,
3
(H2SO.) collection is maintained at 60°C by a water circulation bath. The SOp
is removed in impingers filled with FLO-.
Organic samples were acquired using the SASS train without cyclones. Other
changes made included the addition of acetone in the organic sample recovery
washes and the omission of isopropyl alcohol from the impinger recovery washes.
1.3.4 Level II Laboratory Analysis
Organic Analysis--
The primary tool used was gas chromatography/mass spectrometry (GC/MS)
with capillary column chromatography. All samples were analyzed in this
The major modification in the Level I sampling and analysis procedure was
the GC/MS analysis for ROM's.
-------
capillary column without additional preparation other than the introduction
of an internal standard.
In conjunction with capillary column analysis, several liquid chroma-
tography (LC) fractions were analyzed by GC/MS using both electron impact (El)
and chemical ionization (CI) modes of ionization. The purpose of analyzing
LC fractions was to identify compounds present at low concentration levels in
specific compound classes. Once identification was made, that specific com-
pound was searched for in the data obtained in the original sample. This
procedure was used to facilitate identification of species at low concentration
levels in rather concentrated samples. When no evidence of the compound was
found in the original sample, it was assumed to be a contaminant introduced
as part of the LC procedure. Compounds confirmed to be present in the original
sample, on the other hand, were quantified and reported.
Analysis for Sulfur Species--
Sulfur species collected in the Goksoyr-Ross controlled condensation
train were analyzed for emissions of S09, SO, and particulate sulfate from
L- O
dtesel engines. Sulfur trioxide, collected as H2S04 in the controlled conden-
sation coil, was determined by a bromophenol blue indicated acid-base titration
Sulfur dioxide, collected in the H^Og impinger, reacted to form H^SO, and was
subsequently determined by the turbidimetric sulfate analysis. Particulate
sulfates collected on the filter and from the probe rinse were also deter-
mined by the turbidimetric sulfate analysis.
1.3.5 Results
The results of the field measurement program along with supplementary
values for certain pollutants obtained from the existing data base are summa-
rized in Tables 1 and 2.
Tables 1 and 2 also list severity factors, defined as the ratio of the
calculated maximum ground level concentrations of the pollutant species to the
level at which a potential environmental hazard exists. A severity factor of
greater than 0.05 is indicative of a potential problem requiring further
attention. As can be seen from Tables 1 and 2, the major pollutant from
-------
TABLE 1. SUMMARY OF RESULTS OF EMISSIONS ASSESSMENT
FOR GAS-FUELED INTERNAL COMBUSTION SOURCES
Gas-Fueled Gas Turbines
Pollutant
N0x
Total hydrocarbons
CO
Particulate
so..
Elec.
Emission
Factor
(ng/J)
168
23.2
64.8
5.1
0.26
Gen.
Severity
Factor
0.17
0.020
0.0003
0.0019
<0.0001
Industrial
Emission
Factor
(ng/J)
130
8.6
48.8
5.1
0.26
Severity
Factor
0.52
0.025
0.0007
0.0062
<0.0001
Gas Reciprocating Engines
Elec.
Emission
Factor
(ng/J)
1549
528
340
5.7
0.26
Gen.
Severity
Factor
7.1
1.7
0.0051
0.0068
0.0002
Industrial
Emission
Factor
(ng/J)
1549
528
340
5.7
0.26
Severity
Factor
5.7
1.3
0.0040
0.0055
0.0002
-------
TABLE 2. SUMMARY OF RESULTS OF EMISSIONS ASSESSMENT
FOR OIL-FUELED INTERNAL COMBUSTION SOURCES
Pollutant
NOX
Total hydrocarbons
CO
Particulate
S0x
so3
Trace Elements
Copper
Nickel
Phosphorus
Distill
Elec.
Emission
Factor
(ng/J)
311
17.5
43.8
13.0
33.1
1.5
0.58
0.53
0.13
ate Oil -Fueled Gas Turbines
Gen.
Severity
Factor
0.32
0.015
0.0002
0.0049
0.0089
0.056
0.085
0.16
0.037
Industrial
Emission
Factor
(ng/J)
207
3.6
101
13.0
33.1
1.5
0.58
0.53
0.13
Severity
Factor
0.83
0.010
0.0014
0.016
0.029
0.18
0.28
0.51
0.12
Distillate Oil Reciprocating Engines
Elec.
Emission
Factor
(ng/J)
1392
52
266
14.1
H)l
1.8
0.45
0.56
0.097
Gen.
Severity
Factor
6.4
0.16
0.0040
0.019
0.097
0.23
0.23
0.60
0.10
Industrial
Emission
Factor
(ng/J)
1392
52
266
14.1
101
1.8
0.45
0.56
0.097
Severity
Factor
5.1
0.13
0.0032
0.015
0.077
0.18
0.20
0.48
0.082
-------
internal combustion turbines and reciprocating engines is nitrogen oxides.
For reciprocating engines, emissions of total hydrocarbons are also signifi-
cant, especially in the case of gas-fueled engines. Source severity factors
for SOp emissions from diesel engines, and for SO, emissions (in the form of
I O
sulfuric acid vapor and aerosols) from oil-fueled gas turbines and recipro-
cating engines are all greater than 0.05, indicating the environmental
significance of emissions of sulfur species.
Trace element emissions from the gas-fueled gas turbine tested were in-
significant. For oil-fueled gas turbines and reciprocating engines, sodium,
calcium, nickel, copper, iron, zinc and silicon were the trace elements
emitted in the largest quantities. Nickel, copper, and phosphorus were found
to be the only trace elements with severity factors greater than 0.05.
Data for polycyclic organic matter (POM) emissions obtained by GC/MS are
not reported in the summary tables. ROM's were not detected in the emissions
from the one gas-fueled gas turbine and the five distillate oil-fueled gas
turbines tested. POM emissions from the five diesel engines tested were found
to be mostly naphthalenes and substituted naphthalenes. Emissions of these
organic species resulted in calculated source severity factors which were all
well below 0.05. POM compounds known to be carcinogenic, such as benzo(a)-
pyrene and dibenz(a,h)anthracene, were not found above the detection limit of
0.05 yg/m .
1.4 CONCLUSIONS
Several conclusions, as listed below, can be drawn from the emissions
assessment of electricity generation and industrial internal combustion
sources:
NOX emissions from stationary internal combustion sources are a
potential environmental problem. These emissions account for
approximately 20 percent of the total NOX emissions from stationary
sources. Of the NOX emissions from internal combustion sources,
more than 80 percent are contributed by the industrial reciprocating
gas engine category. Source severity factors for NOX emissions
from gas turbines and reciprocating engines range from 0.17 to 7.1.
11
-------
Emissions of hydrocarbons from stationary internal combustion sources
contribute significantly to the national emissions burden. These
emissions account for approximately 9 percent of the total hydro-
carbon emissions from stationary sources. More than 80 percent of
the hydrocarbon emissions from internal combustion sources are
contributed by the industrial reciprocating gas engine category.
Source severity factors for hydrocarbon emissions range from 0.01
for industrial gas-fueled gas turbines to 1.7 for industrial recipro-
cating gas engines.
o CO emissions from stationary internal combustion sources are not an
environmental concern. Source severity factors for CO emissions from
internal combustion sources are all well below 0.05. Total CO
emissions from these sources account for approximately 1 percent of
CO emissions from all stationary sources. More than 80 percent of the
CO emissions from internal combustion sources are contributed by the
industrial reciprocating gas engine category.
0 Emissions of S02 and particulates from stationary internal combustion
sources contribute only an insignificant fraction of the emissions of
these pollutants from stationary sources. Source severity factors
for S02 and particulate emissions are well below 0.05, with the
exception of S02 emissions from diesel engines. Source severity
factors for S02 emissions from industrial and electricity generation
diesel engines are 0.08 and 0.10, respectively.
Combination of emissions data from this measurement program and the
existing data base provides adequate characterization of emissions
of criteria pollutants from stationary internal combustion sources.
SOs emissions from oil-fueled internal combustion sources require
further attention. Source severity factors for SOs emissions range
from 0.05 to 0.23. For distillate oil-fueled gas turbines, an
average of 3.8 percent of the sulfur present in the fuel is converted
to SOs. For diesel engines, an average of 1.4 percent of the fuel
sulfur is converted to $03. The percent of fuel sulfur converted to
SOs is lower for diesel engines because of the lower oxygen level in
reciprocating engines.
e For distillate oil-fueled gas turbines, the data base for SOs
emissions is adequate. For distillate oil reciprocating engines, the
data base for SOs emissions could be improved by additional field
tests.
Emissions of trace elements from gas-fueled internal combustion
sources are negligible when compared with emissions of trace elements
from oil-fueled sources. For oil-fueled internal combustion sources,
emissions of copper, nickel and phosphorus have source severity
factors greater than 0.05.
12
-------
The data base for trace element emissions from stationary diesel
engines is adequate. For distillate oil-fueled gas turbines, trace
elements for which the emissions data base is inadequate include
nickel, phosphorus and silicon. The emissions data base for these
trace elements may be improved by analysis of additional fuel
samples.
Emissions of individual organic species from stationary internal
combustion sources are environmentally insignificant. Analyses of
organic samples have indicated that organic emissions from oil-fueled
internal combustion sources consist mainly of saturated and unsatu-
rated aliphatic and aromatic hydrocarbons. The most prevalent organic
species present are saturated straight chain and branched hydrocarbons
Substituted benzenes are the second most abundant organic species
emitted. Source severity factors for these organic emissions are
well below 0.05.
POM emissions from internal combustion sources are not at levels of
environmental concern. POM emissions from gas- and oil-fueled gas
turbines were at levels too low to be differentiated from blank
values. For diesel engines, the POM's emitted were mostly naph-
thalenes and substituted naphthalenes, with source severity factors
well below 0.05. POM compounds known to be carcinogenic, such as
benzo(a)pyrene and dibenz(a,h)anthracene, were not found above the
detection limit of 0.05 ug/m3.
13
-------
2. INTRODUCTION
Conventional stationary combustion systems are major sources of pollutant
emissions to air, water, and land. A preliminary assessment of the signifi-
cance of stationary combustion systems as sources of pollution has been made
(Reference 1), and it was estimated that these combustion sources contribute
a major portion of the total man-made emissions of nitrogen oxides, sulfur
oxides, and particulates. The preliminary assessment also identified the
general inadequacy of the emissions data base for a number of potentially
hazardous pollutants, including trace elements, sulfur trioxide and particu-
late sulfate, and polycyclic organic matter (POM).
The overall objective of the current program is to provide a comprehen-
sive assessment of all emissions from selected conventional stationary com-
bustion systems. The assessment process is based on a critical examination
of existing data, followed by a phased sampling approach to resolve data gaps.
In the first phase, sampling and analysis procedures are used to provide
results accurate to a factor of 3 so that preliminary assessments can be
made and problem areas identified. The methodology employed is similar to
the Level I sampling and analysis procedures developed under the direction
of the Industrial Environmental Research Laboratory of the U.S. Environmental
Protection Agency (Reference 2), the major deviation being that GC/MS analysis
for POM's is performed on the samples collected in this program. Evaluation
of results from the first phase will determine all waste stream/pollutant
combinations requiring a more detailed and accurate Level II sampling and
analysis program. The characterization of combustion source emissions from
this program will allow EPA to determine the environmental acceptability of
combustion waste streams and pollutants and the need for control of environ-
mentally unacceptable pollutants.
The combustion source types to be assessed in this program has been
selected because of their relevance to emissions and because they are among
14
-------
the largest, potentially largest, or most numerous (in use) of existing com-
bustion source types. A total of 51 source types have been selected for
study. Selected source types have been classified under the following
principal categories:
1) Electricity generation - External combustion
2) Industrial - External combustion
3) Electricity generation and industrial - Internal combustion
4) Commercial/institutional - Space heating
5) Residential - Space heating
These five principal categories have been further divided into sub-
categories based on fuel type, furnace design, and firing method. The sub-
categorization is needed because of the differences in the emission character-
istics of combustion source types.
This program report is the second in a series of five reports, and is
concerned with the emissions assessment of electricity generation and indus-
rial internal combustion sources. A total of eight combusion source types
are considered*:
1.3.22.0.0 Electricity Generation Internal Combustion Distillate Oil-
Fueled Gas Turbine
1.4.22.0.0 Electricity Generation Internal Combustion Distillate Oil
Reciprocating Engine
1.3.30.0.0 Electricity Generation Internal Combustion Gas-Fueled Gas
Turbine
1.4.30.0.0 Electricity Generation Internal Combustion Gas Reciprocating
Engine
2.3.22.0.0 Industrial Internal Combustion Distillate Oil-Fueled Gas
Turbine
2.4.22.0.0 Industrial Internal Combustion Distillate Oil Reciprocating
Engine
* The I.D. code refers to the classification code used in Reference 1.
15
-------
2.3.30.0.0 Industrial Internal Combustion Gas-Fueled Gas Turbine
2.4.30.0.0 Industrial Internal Combustion Gas Reciprocating Engine
The approach utilized in the emissions assessment of electricity genera-
tion and industrial internal combustion sources is similar to that utilized
for the assessment of other combustion source types. First, available infor-
mation concerning the process and population characteristics of internal
combustion sources and their emissions was assembled and assessed to determine
the adequacy of the available data base. Sampling and analysis was then con-
ducted at selected representative sites (one gas-fueled gas turbine, five
distillate oil-fueled gas turbines, and five distillate oil reciprocating
engines) to resolve problem areas arising from inadequacies in the existing
data base. The results were evaluated to determine the need for and type of
additional sampling and analysis, and to identify the environmentally signi-
ficant substances emitted from internal combustion sources. These evaluations
led to the recommendation of additional tests to determine SO- emissions and
organic emissions from electricity generation distillate oil reciprocating
engines. Three Level II tests for this source category were subsequently
conducted. Results from these tests were evaluated to ensure that the
emissions data base has been adequately characterized. Lastly, emissions data
obtained from the sampling and analysis program were combined with existing
emissions data to provide estimates of current and future nationwide emissions
of pollutants from internal combustion sources.
16
-------
3. SOURCE DESCRIPTION
Stationary internal combustion engines, in which the products of
combustion of the fuel comprise the working fluid, are usually classified
according to the method of transformation of the fluid energy into mechanical
work or power. On this basis, internal combustion sources for electricity
generation and industrial application are grouped into two types: gas
turbines and reciprocating engines. To provide a better understanding of the
emission problems associated with stationary internal combustion engines,
brief descriptions of the engine types and variations, fuel characteristics,
principal applications, installed capacity, and future market trends are
provided. Population characteristics of utility and industrial gas turbines
and reciprocating engines, including average size and age and the prevalence
of pollution control equipment, were used to aid in the selection of repre-
sentative test facilities.
3.1 PROCESS CHARACTERISTICS
A basic gas turbine consists of a compressor, a combustor and a turbine.
High pressure air is supplied by the compressor to the combustor. Fuel is
mixed with the air in the combustor and burned. Combustion products are then
expanded through the turbine to drive a rotor and generate power. A variety
of advanced models have evolved from the simple gas turbine, and are classi-
fied into three general operating cycles: simple open cycle, regenerative
open cycle and combined cycle. In the simple open cycle, the hot gas dis-
charged from the turbine is exhausted to the atmosphere. In the regenerative
open cycle, the gas discharged from the turbine is passed through a heat
exchanger to preheat the combustion air. Preheating the air increases the
efficiency of the turbine. In the combined cycle, the gas discharged from
the turbine is used as auxiliary heat for a steam cycle. The combined cycle
17
-------
system offers a great increase in the combined efficiency of the overall
system.
Gas turbines use gas or liquids such as distillate oil and kerosene as
fuel. In open cycle gas turbines, where the products of combustion come in
direct contact with the turbine blades, the fuel used must result in combus-
tion gases that are free of corrosive ash and large particulates (>2 ym)
which cause erosion. The metallic contaminants in fuel that form relatively
low melting compounds during combustion must, therefore, be eliminated
because the resulting compounds would stick on the turbine blades and corrode
the protective oxide coatings. For these reasons, the ASTM Gas Turbine Fuels
Committee has set fuel impurity limits for the five critical trace elements:
sodium, potassium, lead, vanadium and calcium.
Reciprocating internal combustion engines may be classified according
to the method of ignition into spark ignition and compression ignition engines.
In spark ignition engines, the fuel is usually mixed with the air at the
intake valve (for gaseous fuels) or in a carburetor (for liquid fuels),
although occasionally the fuel is injected into the compressed air in the
cylinder. In compression ignition engines, on the other hand, only air is
taken into the engine on the intake stroke and compressed to ignition condi-
tions. Diesel fuel is then atomized directly into the combustion chamber at a
controlled rate. Ignition is spontaneous.
For reciprocating internal combustion engines, the spark ignition engines
use gas or volatile liquids such as gasoline as fuel, whereas the compression
ignition engines use liquid fuels of low volatility such as low-grade kerosene
and distillate oil (diesel fuel). All distillate oil reciprocating engines
are compression ignited, and all gasoline reciprocating engines are spark
ignited. Spark ignited gasoline engines have very limited use for electricity
generation and industrial application, because of their poor part-load economy
and demand for premium fuel. Gas reciprocating engines are mostly spark
ignited, but as can also be used in a compression ignition engine if a small
amount of diesel fuel is injected into the compressed air/gas mixture to
initiate combustion. Such compression ignition engines are known as dual-
fuel engines, and are normally designed to burn any mixture ratio of gas and
18
-------
diesel fuel. Most of the large bore, high power engines for utility and
industrial applications are four-stroke cycle compression ignition engines
designed to operate on diesel fuel or dual-fuel, and either two stroke cycle
or four-stroke cycle spark ignited gas engines.
3.2 INDUSTRY PROFILE
The principal application areas and the major manufacturers for utility
and industrial gas turbines and reciprocating engines are presented in
Tables 3 and 4. On the basis of total installed horsepower, electricity
generation is the predominant user of gas turbines. For 1976, the Federal
Power Commission (FPC) reported a generation capacity of 46,576 MW for gas
turbine plants owned by utilities (Reference 4). Utilizing the 1976 FPC
figure and the increase in capacity projected by the National Electric Reli-
ability Council (Reference 5), the estimated 1978 generating capacity is
50,800 MW for gas turbine plants owned by utilities. Of the installed
capacity, approximately 82 percent are oil-fueled combustion turbines, 7 per-
cent are gas-fueled combustion turbines, and 11 percent are combined cycle
plants (Reference 5). For industrial applications, Energy and Environmental
Analysis, Inc. (EEA), has indicated that the total gas turbine horsepower
installed through 1974 for the oil and gas industry, less electric power
generation, amounted to approximately 6,831,000 HP or 5,096 MW (Reference 6).
The total generating capacity for the oil and gas industry in 1974 was approxi
mately 460 MW. Analysis of the data published by the Oil and Gas Journal
showed that from 1974 to 1976, the gas turbine capacity for gas pipelines
increased by a modest 2.86 percent (References 7, 8 and 9). Assuming the
same percentage increase in gas turbine capacity for the other turbine appli-
cations, the total 1978 gas turbine installed horsepower for the oil and gas
industry is estimated to be 7,227,000 HP or 5,392 MW, plus an additional
487 MW for electricity generation. For other industrial applications, EEA
data indicated a 1974 total of 1,146,000 HP or 855 MW for industrial drive
type gas turbine applications and approximately 1,900 MW for private industry
electricity generation (Reference 6). Using a 6 percent annual growth rate,
the 1978 total would be 1,447,000 HP or 1,079 MW for industrial drive type
gas turbine applications and 2,400 MW for private industry electricity
generation.
19
-------
TABLE 3. PRINCIPAL APPLICATIONS AND MAJOR MANUFACTURERS
OF UTILITY AND INDUSTRIAL GAS TURBINES (Reference 3)
Size Category
Principal Applications
Major Manufacturers
< 1,000 HP
Compressor and pump drive,
standby electricity
generation
Garrett AiResearch
1,000-5,000 HP
Oil and gas transmission,
natural gas processing,
standby electricity
generation, private
industry electricity
generation, compressor
and pump drive
Solar Division of
International Harvester,
Detroit Diesel Allison
Division of General
Motors, Avco Lycoming
5,000-20,000 HP
Oil and gas transmission,
natural gas processing,
standby electricity
generation, private
industry electricity
generation
General Electric,
Turbo Power and Marine
Systems, Westinghouse
> 20,000 HP
(^ 15 MW)
Peak load electricity
generation
General Electric,
Turbo Power and Marine
Systems, Westinghouse
Combined cycle
> 100 MW
Base load electricity
generation
General Electric,
Turbo Power and Marine
Systems, Westinghouse
20
-------
TABLE 4. PRINCIPAL APPLICATIONS AND MAJOR MANUFACTURERS
OF UTILITY AND INDUSTRIAL INTERNAL COMBUSTION
RECIPROCATING ENGINES (Reference 6)
Size Category Principal Applications Major Manufacturers
400-1,000 HP Oil and gas production Detroit Diesel Allison
(Medium engines) and exploration, natural Division of General
gas processing, compressor Motors, White Superior,
and pump drive, private Allis-Chalmers, Cater-
industry electricity pillar, Cummins,
generation, standby Waukesha
electricity generation
> 1,000 HP Oil and gas transmission, Cooper-Bessemer,
(Large engines) natural gas processing, Electromotive Division
peak load and base load of General Motors,
electricity generation, Ingersoll-Rand,
nuclear standby power White-Superior, Alco,
Colt, Enterprise,
Dresser-Clark
Utilities will continue to dominate the gas turbine market in the future.
The National Electric Reliability Council (NERC) has surveyed its members for
major generating unit additions scheduled for the 1978-1985 period, and pro-
jected a 18.3 percent increase in oil-fueled combustion turbine capacity, a
14.7 percent decrease in gas-fueled combustion turbine capacity, a 133.3 per-
cent increase in oil-fueled combined cycle plant capacity, and a 25.8 percent
decrease in gas-fueled combined cycle plant capacity from 1978 to 1985 (Refer-
ence 5). These figures are used in the estimation of the projected 1935
installed capacity for utility gas turbines, as presented in Table 5. For the
oil and gas industry, the gas turbine power added per year for transmission
has decreased sharply over the last few years. Extrapolating from the 2.86
percent increase in installed gas turbine capacity from 1974 to 1976, the
increase in installed gas turbine capacity from 1978 to 1985 would be 11.0 per-
cent, and the total 1985 gas turbine capacity for the oil and gas industry
would be 5,950 MW plus an additional 540 MW for electricity generation. For
-------
other industrial applications, the 1985 installed capacity is estimated by
assuming a 6 percent annual growth rate. The 1978 and projected 1985 installed
gas turbine capacity for utility and industrial applications are compared in
Table 5. As noted in Table 5, the total projected 1985 installed capacity of
74,070 MW represents a modest 3.0 percent annual growth rate over the 1978
installed capacity of 60,160 MW. In both 1978 and 1985, the gas turbine
installed capacity for the utility sector amounts to approximately 84 percent
of the total installed capacity.
On the basis of installed horsepower, the principal applications of
reciprocating engines are oil and gas transport, oil and gas production, and
electricity generation. For 1976, FPC reported a generation capacity of
5,298 MW for internal combustion reciprocating engine plants owned by
utilities (Reference 4). This installed capacity is expected to stay at
approximately the same level for 1978. The major use of utility reciprocating
engines is for base load electricity generation by municipal power companies,
often in areas where demand does not justify the construction of large steam
power plants. The majority of new reciprocating engine orders, however, is
for nuclear standby power, where the high power diesel engines have dominated
the market. In a standards support and environmental impact statement for
reciprocating internal combustion engines document prepared for EPA, the 1975
installed capacity for industrial applications was estimated (Reference 6). The
data have been projected to 1978 by assuming a 1.6 percent annual increase in
installed capacity for all industrial applications, based on analysis of the
data published by the Oil and Gas Journal which showed that the reciprocating
engine capacity for oil and gas transmission increased by 1.6 percent from 1975
to 1976 (References 8 and 9). Estimations of the 1978 installed reciprocating
engine capacity for industrial applications are presented in Table 6. The
diesel engine predominates the utility market whereas the spark-ignited gas
engine predominates the industrial market.
For the nine-year period from 1976 to 1985, the Federal Power Commission
estimated that the net installed capacity for utility reciprocating engines
would only increase by approximately 100 MW (Reference 10). Reciprocating
engines in the natural gas industry are used primarily to power compressors
used in collecting gas from wells, pipeline transportation, underground stor-
age and gas processing plants. Recent sales data have indicated that most of
22
-------
TABLE 5. CURRENT AND PROJECTED GAS TURBINE INSTALLED CAPACITY FOR
UTILITY AND INDUSTRIAL APPLICATIONS
Application Area
Utilities
Oil-fueled combustion turbine
Gas-fueled combustion turbine
Oil-fueled combined cycle
Gas-fueled combined cycle
Oil and gas industry
Private industry electricity generation
Oil and gas industry
Other industry
Other industrial applications
Total
Installed Capacity
1978 1985
41,500 MW
3,410 MW
3,760 MW
2,130 MW
5,390 MW
490 MW
2,400 MW
1,080 MW
60,160
49,100 MW
2,910 MW
8,770 MW
1,580 MW
5,950 MW
540 MW
3,600 MW
1,620 MW
74,070
the sales of reciprocating engines to oil and gas pipelines were for additions
to, or replacement of, existing compressor stations (Reference 6). In addi-
tion, natural gas production is expected to decline in the 1978-1985 period.
There has also been a movement away from reciprocating engines used in refin-
ery operations to electric motors and steam turbines, and occasionally, fossil-
fueled combustion turbines (Reference 6). New sales for reciprocating engines
will, therefore, be mostly for the replacement market, and the installed
capacity of reciprocating engines for industrial applications will remain at
essentially the same level in the 1978-1985 period. Projections of the 1985
installed capacity of reciprocating engines for industrial applications,
assumed to be equal to the 1978 installed capacity, are presented in Table 6.
In terms of geographical distribution, the states with the highest
installed capacity of utility gas turbines include New Jersey, Florida,
New York, Pennsylvania, and Illinois. The states with the highest installed
capacity of utility reciprocating engines include Kansas, Iowa, Missouri,
23
-------
TABLE 6. CURRENT AND PROJECTED RECIPROCATING ENGINE INSTALLED CAPACITY
FOR UTILITY AND INDUSTRIAL APPLICATIONS
Application Area
Installed Capacity
1978 1985
Utilities
Diesel, dual fuel, and gas engine
Oil and gas transmission
Diesel engine
Gas engine
Natural gas processing
Gas engine
Oil and gas exploration
Diesel engine
Gas engine
Crude oil and natural gas production
Gas engine
Industrial processes
Gas engine
On site power generation
Gas engine
Total
5,300 MW
780 MW
9,380 MW
2,350 MW
840 MW
840 MW
4,000 MW
940 MW
350 MW
24,780
5,400 MW
780 MW
9,380 MW
2,350 MW
840 MW
840 MW
4,000
940 MW
350
24,880
Michigan, and Minnesota. In industrial applications, most of installed
capacity for gas turbines and reciprocating engines is for oil and gas trans-
mission, crude oil production, and natural gas production and processing.
Industrial gas turbines and internal combustion engines are, therefores mostly
found in states having more mileage of oil and gas transmission pipelines and
higher oil and gas production activities. For natural gas transmission for
24
-------
example, the nine states of Louisiana, Texas, Kansas, Mississippi,
Pennsylvania, Kentucky, Michigan, New Mexico and Tennessee account for approxi-
mately 65 percent of the installed reciprocating engine and gas turbine
horsepower (Reference 11).
3.3 POPULATION CHARACTERISTICS
For utility gas turbines, FPC has published data on plant capacity, plant
fuel use, number of units, size of each unit and the year of installation for
each unit (References 12 and 13). Analysis of the FPC data shows that as of
December 31, 1973, the average size for utility gas turbines (defined as total
installed capacity divided by the total number of units) was approximately
29 MW. The same data also shows that 44 percent of the total number of utility
gas turbine units were in the 15 to 20 MW size range. More recent data from
Sawyer's Gas Turbine International indicates that the average size of utility
gas turbines added after the end of 1973 is approximately 59 MW, with most of
the new additions in the 45 to 70 MW size range (Reference 14). Thus, the
trend is definitely toward the installation of large size turbines, and the
current average size of utility gas turbines is approximately 31 MW. However,
more than 40 percent of the total number of utility gas turbine units are still
in the 15 to 20 MW size range. On this basis, utility gas turbines in the
15 to 70 MW size range should all be considered as representative. Analysis
of the FPC age distribution data for utility gas turbines shows that as of
December 31, 1973, the capacity average age was 2.7 years, and that 80 percent
of the installed capacity was less than 5 years old. Combination of the FPC
data with the new utility gas turbine installation data from Sawyer's Gas
Turbine International then shows that as of December 31, 1976, the capacity
average age for utility gas turbines is approximately 5 years, and that more
than 80 percent of the installed capacity is less than 8 years old. Candidate
test facilities selected for the utility gas turbine category should, there-
fore, be less than 8 years old.
Size and age distribution data for industrial gas turbines are not readily
available. In Figure 2, the average size of gas turbines ordered for use by
the oil and gas industry for extraction or transmission purposes is presented
(Reference 3).
25
-------
6000
5000
a. 4000
3000
2000
1000
Figure 2. Average Size of Gas Turbines Ordered by the
Oil and Gas Industry
From Figure 2, it is reasonable to assume that the average size unit in
the oil and gas industry is approximately 3,000 HP or 2.2 MW. As the oil and
gas industry represents the major industrial market for gas turbines, the
average size unit for all industrial gas turbines would also be approximately
3,000 HP.
For reciprocating engines, it has been reported that the average size unit
for electricity generation is approximately 2,500 HP or 1.9 MW, and the aver-
age size unit for oil and gas transmission is 2,000 HP or 1.5 MW (Reference 6).
Recent data on the age distribution of utility and industrial reciprocating
engines are not available. Based on an installed capacity of 5,300 MW and
an estimated annual sales of 280 MW of reciprocating engines to the electric
utility market, the average age of the utility reciprocating engine is approxi-
mately 10 years. The average age is estimated by assuming all annual sales
are for the replacement market. Annual sales estimates are obtained from the
same report (Reference 6). For industrial applications, with an installed
capacity of 11,550 MW and an estimated annual sales of 570 MW of gas engines
for gas transmission and processing, the average age of the industrial recip-
rocating engine is again approximately 10 years.
Air pollution control equipment is generally not installed on gas turbines
or reciprocating engines, partially because particulate and SOX emissions
26
-------
from these combustion sources are significantly lower than corresponding
emissions from coal fired and resid oil fired boilers. There is, however,
increasing recognition that NOV emissions from gas turbines and NO , hydro-
X A
carbon, and CO emissions from reciprocating engines are major contributors to
the nationwide emission burden. For gas turbines, water and steam injection
have been accepted as valid techniques for NO control. In Table 7, a partial
J\
listing of the 74 turbine plants with water or steam injection for NO control
X
is presented. In addition, to reduce visible emissions from oil-fueled
turbines, fuel additives such as soluble compounds of barium, manqanese and
iron are often employed. For oil-fueled reciprocating engines, additives to
reduce visible emissions are not recommended by manufacturers because of con-
cern over possible build-up problems at the cylinder ports. Fuel additives
are, therefore, only infrequently used with oil-fueled reciprocating engines.
Control of NO , CO and hydrocarbons through catalytic converters and reduc-
J\
tions of CO and hydrocarbon emissions with afterburners are the only practical
exhaust treatment methods for reciprocating engines. These control measures,
however, have only been installed on a limited number of utility and industrial
reciprocating engines.
27
-------
TABLE 7. PARTIAL LISTING OF TURBINE INSTALLATIONS
WITH WATER OR STEAM INJECTION FOR NO CONTROL (Reference 3)
ro
oo
Injected Manufacturer User
Water Westinghouse Florida Power & Light
Florida Power Corp.
Kansas Power & Light
Jacksonville Elect.
Kansai Electric Power
(21
v 'Southern Calif. Edison
General Electric San Diego Gas & Elect.
San Diego Gas & Elect.
Houston Power & Light
Tucson Gas & Elect.
Iowa Public Service
Kansas Power & Light
GE (On Order) City of Jacksonville
Florida Power Corp.
Portland General Elect.
Arizona Power & Light
'^'Southern Calif. Edison
Ohio Edison
Accumulated Hours
Location No.
Enterprise, Fla.
Abilene, Kansas
Jacksonville, Fla.
Osaka, Japan
Daggett, Calif.
San Diego, Calif.
Naval Training Center
Houston, Texas
Tucson, Arizona
Jacksonville, Fla.
Portland, Oregon
Lucerne Valley, Calif.
of Turbines
4
-------
TABLE 7 (Continued)
ro
Fluid
Injected Manufacturer
Turbodyne
Turbo Power & Marine
Steam Westinghouse
General Electric
Turbodyne
Turbo Power & Marine
Accumulated Hours
User
Houston Lighting & Power
Burbank Public Service
City of Glendale
City of Pasadena
Southern Calif. Edison
Union Carbide
Union Carbide
Exxon
Southern Calif. Edison
City of Pasadena
Location
Houston, Texas
Burbank, Calif.
Glendale, Calif.
Pasadena, Calif.
Goleta, Calif.
Texas City, Texas
Texas City, Texas
Baytown, Texas
Pasadena, Calif.
Total installations:
No. of Turbines Hrs
not installed as of
1 NA
1 NA
2 NA
2 27.3 each
Date
July 1976
installed 4/74
installed 10/73
installed 5/74
1-13-76
IA\
1 3000 plusm
1 15 years -
7 48,000 as of 2-1
7 not instal
1 NA
: 58 minimum, water
16 steam
June 1975
5-73 on 1 turbine
led yet
NA
Notes: Water injection
system available but not bei
ng used.
' ' 19 gas turbines using water injection - total for both facilities.
^ ' NA - not available.
' ' Unit was overhauled at 47,000 hrs. of operation with the last 3,000 using
injection.
-------
4. EMISSIONS
Air emissions from the flue gas stack are the only significant emissions
from electricity generation and industrial gas turbines and reciprocating
engines. Fugitive emissions from these internal combustion sources are negli-
gible because the liquid fuels used have low volatility leading to minimum
evaporative losses and the gaseous fuels are received continuously from a pipe
rather than via a fuel storage tank and fuel pump. As a result of previous
investigations (References 1, 3, 6, 11, 15, 16 and 17), NOX emissions from
oil- and gas-fueled turbines, NOY, hydrocarbon, and CO emissions from oil- and
/V
gas-fueled reciprocating engines were identified as major contributors to the
nationwide emissions burden. Emissions of these pollutants are discussed
along with emissions of particulates, SO , trace elements, organic, and poly-
A
cyclic organic matter (POM) from internal combustion sources in this section.
4.1 EVALUATION OF EXISTING EMISSIONS DATA
4.1.1 Criteria for Evaluating the Adequacy of Emissions Data
A major task in this program has been the identification of gaps and
inadequacies in the existing emissions data base for combustion sources. The
results of this effort determine the extent of the sampling and analysis pro-
gram required to complete an adequate emissions assessment for each of the
combustion-source types.
The criteria for assessing the adequacy of emissions data are developed
by considering both the reliability of the data and the variability of the
data. A detailed presentation of the procedures used to identify and evaluate
emissions data is given in Appendix A. Briefly the general approach is to
use a three-step process. In the first step the available data are screened
for adequate definition of process and fuel parameters that may affect emis-
sions as well as for validity and accuracy of sampling and analysis methods.
30
-------
In the second step of the data evaluation process, emission data deemed accept-
able in Step 1 are subjected to further engineering and statistical analysis
to determine the internal consistency of the test results and the variability
in emission factors. The third and final step in the process uses a method
developed by Monsanto Research Corporation (MRC) which is based on both the
potential environmental risks associated with the emission of each pollutant
and the quality or variability of the data. The potential environmental risks
associated with pollutant emissions are determined by the use of a source
severity factor which is defined as the ratio of the calculated maximum ground
level concentration of the pollutant species for an isolated typical source to
the level at which a potential environmental hazard exists. If the variabil-
ity of emission factor data is < 70 percent the data are deemed adequate.
However, if the variability of the emissions data is > 70 percent the deter-
mination of data adequacy and the need for further measurement will be based
on calculated severity factors for each pollutant. The data will be considered
adequate if the upper bound of the source severity factor is <_ 0.05.
4.1.2 Existing Emissions Data for Gas Turbines
The present study classifies gas turbines into the following categories:
1.3.30.0.0 Electricity Generation Internal Combustion Gas-Fueled Gas
Turbine
1.3.22.0.0 Electricity Generation Internal Combustion Distillate
Oil-Fueled Gas Turbine
2.3.30.0.0 Industrial Internal Combustion Gas-Fueled Gas Turbine
2.3.22.0.0 Industrial Internal Combustion Distillate Oil-Fueled Gas
Turbine
As discussed in Section 3 of this report, on the basis of total installed
horsepower, electricity generation is the predominant user of gas turbines.
However, as the electric utility industry uses gas turbines primarily for
peaking power rather than continuous power service, the total power generation
and pollutant emissions from the utility sector are about the same order of
magnitude as those from the industrial users.
Gas turbines for electric industry use range in power generation capacity
from 14 to over 100 MW, with an average capacity of 30 MW. For industrial use,
31
-------
the typical capacity of gas turbines ranges from 10 to 20,000 HP (approximately
15 MW), with an average capacity of around 3,000 HP (2.2 MW). Thus the indus-
trial gas turbines are generally of smaller capacity than the electric utility
gas turbines, and the existing emissions data for these two user sectors will
be evaluated separately.
Emissions Data Sources-
Review of the literature indicated that there are six primary sources of
emissions data for gas turbines. The study conducted by McGowin contains
mainly eight sets of NOV emissions data for industrial gas turbines (Refer-
A
ence 15). The Standards Support and Environmental Impact Statement Document
contains a tabulation of NO , CO and hydrocarbon emissions data for all four
A
categories of gas turbines to be evaluated here (Reference 3). The Southwest
Research Institute (SWRI) reports contain emissions data for industrial gas
turbines, but the emissions data are restricted to NOV, CO and hydrocarbon
A
emissions from gas-fueled turbines (References 11 and 16). In another SMRI
study, Hare and Springer compiled emissions data for electric utility gas tur-
bines manufactured by General Electric, Turbo Power & Marine, and Westinghouse
(Reference 17). Emissions data compiled include NO , CO, hydrocarbon, partic-
A
ulate, and SOX emissions from both gas and distillate oil-fueled gas turbines.
A comprehensive stack sampling program on fossil fuel burning gas turbines was
conducted by Consolidated Edison during the May 1, 1973 to November 13, 1974
period (References 18 and 19). Emissions data collected include NO , CO, and
X
hydrocarbon emissions from gas, kerosene, and No. 2 distillate oil-fueled
gas turbines, and also particulate and trace element emissions for the oil-
burning gas turbines. Trace elements for which emissions data have been
reported include magnesium, lead, cadmium, beryllium, barium, vanadium and
manganese. SO emissions reported were not measured but calculated based on
A
the percent of sulfur in the fuel.
In addition to the primary reference sources cited above, Hurley and
Hersh recently completed a study to characterize the effects of smoke and cor-
rosion suppressant additives on the particulate and gaseous emissions from a
utility distillate oil-fueled gas turbine (Reference 20). Exhaust samples
from the turbine were analyzed for total particulate mass loading and composi-
tion, particulate size distribution, polycyclic organic matter (POM) and
32
-------
gaseous emissions including NO , CO, hydrocarbons, SOp and SO.,. The results
of the investigation showed a reduction in total particulate loading when fuel
additives of barium/manganese, organic manganese, iron or chromium are used,
although particulate size distributions were not shifted significantly.
Furthermore, the effects of fuel additives on gaseous emissions, including
POM, were found to be insignificant. This is an important conclusion since
fuel additives are commonly employed to suppress visible smoke emissions from
distillate oil turbines, and it has been shown that there is no need to sub-
classify the gaseous emissions data on the basis of fuel additive introduction.
Industrial Gas and Distillate Oil-Fueled Gas Turbines--
The emissions data for industrial gas and distillate oil-fueled gas
turbines, as compiled from the McGowin, SWRI and Standards Support and Environ-
mental Impact reports, are summarized in Tables 8 and 9. For the SWRI emis-
sions data for which accompanying humidity and load factor data are available,
a humidity correction factor K has been applied to the NO values and load
X
factor correction factors have been applied to the NO , CO and hydrocarbon
A
values (Reference 11):
K -
1 - 0.003 (H-44)
where H is the humidity in grains FLO/Ib dry air
Load Factor = Operating Load/Rated Load
Emission at Rated Load = Emission at Operating Load x Correction Factor
Correction Factor for NOV = (Load Factor)~°'5
A
o
Correction Factor for Hydrocarbons = (Load Factor)
p
Correction Factor for CO = (Load Factor)
As noted in Tables 8 and 9, the emissions data for industrial gas and
distillate oil-fueled gas turbines are limited to NOV, CO and hydrocarbon
A
emissions. For these types of emissions, the existing data base is judged to
be adequate as the variability ts(x)/x is less than 0.7 for all cases. For
gas-fueled industrial turbines, SO emissions may be estimated from the sulfur
A
content of natural gas, and particulate emissions may be assumed to be equal
33
-------
TABLE 8 EXISTING EMISSIONS DATA FOR INDUSTRIAL GAS-FUELED
GAS TURBINES UNDER BASE LOAD CONDITIONS
Turbine Model*
DDA 404-3
GA 831-800
Solar Saturn
Solar T-1001
Unknown
Unknown
Solar Centaur
Unknown
DDA 501 K- 13
Unknown
Unknown
GE(I) M3912R
6E(I) Frame 3(S)
TPM GG 3C-1
GE(I) M3112R
TPM GG 3C-4
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Mean x
Standard Deviation
of the Mean s(x)
Variability ts(x)/x
Base Load
Rating
(HP)
270
690
1,050
1,050
1,100
1,100
2,700
3,350
3,350
6,200
6,900
9,100
9,300
10,500
11,100
12,000
13,900
13,900
13,950
14,700
14,700
14,700
20,000
Emission Factor, nq/J
-NT)X
213
183
76
61
66
78
140
159
173
223
199
185
100
112
176
102
40
110
133
72
125
117
139
130
11
0.174
CO
79.5
7.2
65.9
54.2
__
65.0
30.7
12.1
--
--
7.7
8.6
65.0
3.9
79.6
81.1
139.8
--
--
__
31.0
48.8
10.0
0.441
HC
--
2.4
17.8
5.7
--
6.9
3.4
20.8
6.9
17.2
2.1
--
__
2.9
8.6
2.3
0.594
Reference
3
3
3
11,16
15
15
3
3
3
15
15
11,16
11,16
11,16
11,16
11,16
3
3
15
15
15
15
11,16
GE - General Electric
TPM - Turbo Power and Marine Systems
34
DDA - Detroit Diesel Allison
GA - Garrett At Research
-------
TABLE 9. EXISTING EMISSIONS DATA FOR INDUSTRIAL DISTILLATE OIL-FUELED
GAS TURBINES UNDER BASE LOAD CONDITIONS
Turbine Model*
DDA 404-3
DDA 404-3
GA 831-800
GA 831-800
Solar Saturn
Unknown
Solar Centaur
Unknown
Unknown
DDA 501 K 15
Unknown
Unknown
Unknown
Mean x
Standard Deviation
of the Mean s(x)
Variability ts(x)/x
Base Load
Rating
(HP)
270
270
690
690
1,050
1,350
2,700
3,350
3,350
3,350
3,350
13,900
13,900
Emi
NOX
91
409
258
256
130
113
160
263
254
223
192
89
248
207
25
0.264
ssion Factor,
CO
248
178
16
18
186
40
142
65
30
62
--
160
63
101
23
0.493
ng/J
HC
__
--
0.6
5.7
--
5.7
5.1
--
3.4
--
1.0
3.6
0.9
0.680
Reference
3
3
3
3
3
3
3
3
3
3
3
3
3
* DDA - Detroit Diesel Allison
GA - Garrett Airesearch
to those of gas-fueled utility turbines on an emission factor basis. Also,
trace element emissions are not of concern because of the low trace element
content of natural gas, and POM emissions are not of concern because of the
paraffinic nature of natural gas and the large amount of excess air present in
gas turbines. Other things being equal, the tendency for hydrocarbons to form
POMs is:
Aromatics > Cycloolefins > Olefins > Paraffins
35
-------
Natural gas contains predominantly saturated hydrocarbons which do not promote
addition-type reactions between hydrocarbon species. Also, the absence of
ring structure type compounds in natural gas means that there are no convenient
building blocks for more condensed ring structures such as ROMs. Based on the
above considerations, it is concluded that the existing emissions data base is
adequate for industrial gas-fueled gas turbines.
For industrial distillate oil-fueled gas turbines, the lack of particulate,
SO , SOo, particulate sulfate, trace element and organics emissions data leads
s\ J
to the conclusion that the existing emissions data base is inadequate. How-
ever, the emission factors for distillate oil-fueled gas turbines for industrial
use and for electricity generation under base load conditions are expected to
be similar for these types of emissions, and emissions data for utility distil-
late oil-fueled gas turbines may be used to estimate the emissions from indus-
trial distillate oil-fueled gas turbines.
Electricity Generation Gas and Distillate Oil-Fueled Gas Turbines
For the electric utility industry, gas turbines are used primarily for
peaking power. An exception is combined cycle plants, which are generally
designed for base load operation. Because the type and quantity of exhaust
emissions from gas turbines are dependent on the operating load, it may be
necessary to develop composite emission factors based on the operating cycle
of gas turbines. In an analysis performed by Hare and Springer (Reference 17),
the operating cycle for simple gas turbines was postulated to include 15 per-
cent at zero load, 2 percent each at 25 percent, 50 percent and 75 percent
load, 60 percent at 100 percent load, and 19 percent at 125 percent load, as
depicted in Table 10. The composite emission factor was then calculated by
summing the products of the emission factor and percent operating time spent
at each load condition. The results of the analysis indicated that the com-
posite emission factors for NOX, particulate, and SOX are almost equal to the
unweighted emission factors at 100 percent rated power. For hydrocarbon and
CO emissions, however, the composite emission factors were found to be 58 per-
cent and 118 percent higher than the respective unweighted emission factors
at 100 percent rated power, mainly because of the high hydrocarbon and CO
emissions during gas turbine starts. On this basis, it is concluded that NO ,
X
36
-------
TABLE 10. POSTULATED OPERATING CYCLE FOR ELECTRIC
UTILITY GAS TURBINES (Reference 17)
% Operating
% of Rated Time Spend
Power At Condition
0
25
50
75
100 (base)
125 (peak)
15
2
2
2
60
19
Time at Condition
Based on 4.8 hr Day Contribution to Load
in Hours in Minutes Factor at Condition
0.72
0.10
0.10
0.10
2.88
0.91
4.81
43
6
6
6
173
55
289
0.00 x 0.15 =
0.25 x 0.02 =
0.50 x 0.02 =
0.75 x 0.02 =
1.0 x 0.60 =
1.25 x 0.19 =
^. = Load Factor =
0.0
0.005
0.010
0.015
0.60
0.238
0.868
particulate, and SO emissions data at base load conditions can be used to
/\
adequately characterize the emissions of these pollutants from gas turbines.
The composite emission factors for hydrocarbon and CO emissions will be 1.58
and 2.18 times the corresponding unweighted emission factors at base load con
ditions. These composite factors can be used to estimate the total annual
emissions from a simple cycle gas turbine:
Total annual emissions = Total installed base load rating x 8760
x capacity factor x average heat rate
x composite emission factor
fartor =
ractor
Net generation (MH-hr)
installed base load rating (MW) x 8760 hr
Combined cycle plants are normally operated at base load conditions and there-
for the composite emission factors and unweighted emission factors at based
load are the same.
For electricity generation gas-fueled gas turbines, the existing emissions
data for the criteria pollutants under base load conditions are presented in
Table 11. As noted in Table 11, the existing data base for NO emissions is
37
-------
TABLE 11 EXISTING EMISSIONS DATA FOR ELECTRICITY GENERATION
GAS-FUELED GAS TURBINES UNDER BASE LOAD CONDITIONS
Base Load
Turbine Model* Rating
(MW)
TPM GG 4A-8
TPM FT4A
TPM GG 4A-8
TPM FT4A-9DF
TPM FT4-9DF
GE MS 5001 -LA
GE MS 5001 -SC
GE MS 7001 -B
GE MS 5000-LA
GE MS 5000-N
GE MS 5000-LA
GE MS 5000-M
Unknown
Unknown
Unknown
Mean x
Standard Deviation
of the Mean s(x)
Variability ts(x)/
xu = x + ts(x)
19.5
19.0
19.5
19.2
19.0
17.5
Unkown
61.5
14.6
17.5
16.5
12.8
13.0
13.0
25.0
x
Emission Factor, ng/J
NOX
154
225
131
158
214
137
236
180
135
169
172
123
178
154
159
168
9
0.112
--
HC
--
<7.7
__
19.5
57.1
--
1.5
2.1
4.3
2.6
1.7
4.0
27.3
1.3
15.0
5.7
0.849
27.8
CO Part bUx
18.0 4.39
13.5 7.32 2.22
__
24.2 3.47 6.22
124
492
__
1.8
15.0
8.6
11.6
6.5
44
85
3.9
29. 7^ 5.06 4.42
10.8 1.16 2.19
0.803 0.987 6.32
53.6 10.06 32.4
Reference
17
17
17
17
18,1
17
17
3
18,
18,
18,
18,
3
3
21
9
19
19
19
19
* TPM - Turbo Power & Marine Systems
GE - General Electric
The mean emission factor for CO was calculated after discarding the outlying
data point 492 ng/J.
38
-------
adequate. For hydrocarbon and CO emissions, the variability in emission
factors is slightly greater than 0.7. However, it may be noted that more than
10 existing data points are available for both hydrocarbon and CO emissions,
and the variability in emission factors is probably due to differences in
equipment and operational characteristics. As such, additional data points
would not necessarily reduce the variability in emission factors and the
existing data base for hydrocarbon and CO emissions should be considered as
adequate. For particulate emissions, the variability in emission factor is
also slightly greater than 0.7. The mean particulate emission factor of
5.1 ng/J, however, is almost identical to the published AP-42 particulate
emission factor of 5.7 ng/J for electricity generation gas-fueled gas turbines
(Reference 23). Furthermore, as will be discussed later, the mean source
severity factor for particulate emissions from electricity generation gas-
fueled gas turbines is approximately 0.002, indicating that particulate emis-
sions from gas-fueled turbines should not be an environmental problem. The
existing data base for particulate emissions is, therefore, also considered
to be adequate. For SO emissions, although only two existing data points
X
are available and the variability in SOV emissions is large, SOV emissions
A A
may be estimated assuming an average natural gas sulfur content of 4,6000
c o
g/10 m . Also, as discussed in the case of industrial gas turbines, trace
element and POM emissions are not of concern for gas-fueled gas turbines.
Overall, the existing emissions data base is, therefore, adequate for elec-
tricity generation gas turbines.
For electricity generation distillate oil-fueled gas turbines, the
existing emissions data for the criteria pollutants under base load conditions
are presented in Table 12. The variability ts(x)/x in NO , hydrocarbon, CO,
X
particulate and SO emissions for electricity generation distillate oil
X
turbines is less than 0.7 for all cases, and the existing data base for these
criteria pollutants is therefore considered to be adequate. In the Hurley and
Hersh study, particulate size distributions for the base load operation of a
Turbo Power and Marine FT 4C-1LF turbine were derived from impactor data
(Reference 20). The turbine operation in the investigation included the
introduction of optimum concentrations of manganese/barium, organic manganese,
and iron based fuel additives. The data showed that on the mass basis, 50 per-
cent of the particulates are less than 0.17 ym in size, and that approximately
39
-------
TABLE 12. EXISTING EMISSIONS DATA FOR ELECTRICITY GENERATION DISTILLATE
OIL-FUELED GAS TURBINES UNDER BASE LOAD CONDITIONS
Turbine Model*
TPM GG 4A-8
TPM TP 4-2
TPM FT 4A-9DF
TPM GG 4A-8
TPM FT 4-9DF
TPM FT 4-9DF
TPM FT 4A-8LF
TPM FT 4C-1LF
GE MS 5001 -LA
GE MS 5001 -SC
GE MS 7001 -SC
GE MS 7001 B
GE MS 5001 -NP
GE MS 7001 C
GE MS 7001 B
GE MS 5000-LA
GE MS 5000 N
GE MS 5000-LA
GE MS 5000-M
W 1916
W 501 -B4
W 501 D
W 251
W 191
Turbodyne 11 C
Unknown
Base Load
Rating
(MW)
19.5
43.2
19.2
19.5
20.1
18.0
17.5
20.0
17.5
Unknown
Unknown
60.4
23.5
67.4
50.0
13.9
20.3
15.6
12.2
12.5
78.9
87.8
19.5
10.0
51.7
52.9
Emission Factor, ng/J
NOX
200
361
412
277
379
332
275
225
269
301
395
216
285
296
210
204
319
270
221
209
419
643
368
207
536
253
i
HC
40.0
<9.5
<9.0
0.9
4.8
3.0
2.3
--
--
--
3.0
4.3
3.0
9.0
--
__
2.9
3.4
"--" ~ ,.
Continued
CO
--
<16.7
<15.8
32.6
51.1
3.7
26.9
--
--
--
9.1
2.2
21.9
8.2
10.3
19.3
31.0
20.0
__
13.3
28.4
30.8
__
^
Part
15.5
18.5
29.0
16.7
--
10.3
6.7
--
__
--
__
--
__
30.5
9.1
14.0
16.3
«. _
_«.
12.5
7.0
--
sv
--
6.9
13.7
8.6
8.7
8.7
103
--
_
--
__
-_
__
43.8
57.1
44.2
66.2
-------
TABLE 12. (CONTINUED)
Mean x
Standard Deviation
of the Mean s(x)
Variability ts(x)/x
311
21
0.140
4.61
0.8
0.404
20.1
3.0
0.320
15,5
2.2
0.314
41.0
9.1
0.490
* TPM - Turbo Power & Marine Systems
GE - General Electric
W - Westinghouse
t The mean emission factor for HC was calculated after discarding the outlying
data point 40 ng/J using the method of Dixon.
t The SOX emissions data for the Con Edison gas turbines were calculated based
on the percent of sulfur in the fuel (Reference 19).
90 percent of the particulates are less than 1 ym in size. Additionally, it
was shown from the results of a particle-by-particle X-ray analysis that all
the particles which contained the additive base element fell in the upper end
of the measured size range, with typical diameters on the order of 1 ym. In
several previous investigations, particulate size distribution determinations
by filtration, light and electron microscopy and impaction have also shown that
particulate emissions from distillate oil turbines were submicron, and in
general, below 0.5 ym in diameter (References 24, 25 and 26). Thus, all the
studies conducted have indicated that at least 90 percent of the particulate
emissions from distillate oil turbines are less than 1 ym in size, and addi-
tional particulate size determinations are not required.
For S03 emissions from distillate oil fueled gas turbines, Johnson
reported that based on the test data available in 1973, an average of 3.66 per-
cent of the sulfur present in the fuel is converted to S03 and the remainder
is converted to S02 (Reference 27). More recently, the Hurley and Hersh study
found that based on 13 data points on a utility turbine with various injection
rates of three types of fuel additives, and using an absorption-titration
method for the determination of sulfur oxides, an average of 3.96 percent of
the sulfur present in the fuel was converted to SO^ (Reference 20). The excel-
lent agreement between the two sets of data points indicates that there is no
need for additional S03 measurements. In the Hurley and Hersh investigation,
it was also determined from the exhaust particulate studies that approximately
41
-------
1 percent of the sulfur present in the fuel was converted to particulate
sulfate. The particulate sulfate data reported included metallic sulfates and
a small fraction of particle-absorbed S03.
Emissions data for trace elements are presented in Table 13, and indicate
that of the trace elements naturally present in the fuel, lead and magnesium
are emitted in the greatest concentrations. Manganese and barium are addi-
tives to the kerosene or No. 2 distillate oil to retard visible smoke emis-
sions and are therefore also emitted in greater concentrations. Calculation
of the variability ts(x)/x in trace element emissions show that the emissions
data base is adequate for lead and beryllium. In addition, the ASTM gas
turbine fuels committee has recently approved a revised set of trace element
limits for gas turbine fuels (Reference 28). The limits for the critical
trace elements, including vanadium, sodium and potassium, calcium, and lead
are shown in Table 14. These trace element limits may be used to calculate
the maximum emissions for these four trace elements from distillate oil
turbines, as presented in Table 15. By comparison, the emission factors for
lead and vandaium estimated from existing data are well within the limits of
these maximum emissions. For trace element emissions for which variability
data are available, the upper bound S for the mean severity factors have also
been calculated from x^ = x + ts(x). As will be presented later, the results
of the source severity calculations show that among the trace element emis-
sions, $u <0.05 for barium, cadmium, magnesium, manganese and vanadium. Of
this basis, the existing emissions data base for these trace elements, as well
as that for lead and beryllium, can be considered to be adequate.
For POM emissions from utility distillate oil turbines, the only available
data are from the Hurley and Hersh study (Reference 20). Testing for POM was
conducted under reduced load conditions (approximately 70 percent of base load)
with fuel additive injection and also for baseline cases with no additive. The
POM samples were obtained using a Battelle Tenax absorption system. The POM
data presented in Table 16 show that the largest emissions to consistently
appear were the anthracene/phenanthrene species, both of which are known to be
noncarcinogenic. Benzo(a)pyrene, a known carcinogen, was found in only one
of the tests. The data also showed the apparent catalytic effect of the iron
additive on POM formation. The reliability of the Hurley and Hersh POM data,
42
-------
TABLE 13. EXISTING TRACE ELEMENT EMISSIONS DATA FOR ELECTRICITY GENERATION
DISTILLATE OIL TURBINES UNDER BASE LOAD CONDITIONS*
T 1 1 1" h i n f> Mn HP!
lUlUIIIC IIUUCI
and Location Fuel Mg
Ravenswood £4 Kerosene 3.86E-2
GE MS 5000-LA #2 Oil 1.12E-1
Marrows 1-1 Kerosene
GE MS 5000 N
Astoria ±12 =2 Oil
W 251
Astoria =7 =2 Oil 4.42E-2
W 191
Ravenswood =11 Kerosene
TPM FT 4-9DF
Ravenswood =5 Kerosene
GE MS 5000-LA =2 Oil
Ravenswood -7 =2 Oil
GE MS 5000 M
74th St =2 Kerosene
TPM FT 4A-8LF
Mean x 6.48E-2
Standard Deviation ^ 35F-2
of the Mean s(x)
Variability ts(x)/x 1 .563
x x + ts(x) 1.66E-1
u
Emission Factor,
4
6.
2
3
1
1
5
2
5
2
e.
2
0
1
Pb
.47E-3
.40E-3
.98E-3
.13E-3
.03E-3
.53E-2
.67E-3
.75E-3
.63E-3
.16E-2
89E-3
.05E-3
.672
15E-2
1 .
6,
4
4.
2.
2.
6
] .
5
6.
1.
5.
0
2
Cd
.03E-3
.40E-4
.73E-4
.60E-4
11E-5
.26E-3
.83E-4
.02E-3
.07E-4
.44E-3
36E-3
97E-4
.997
.71E-3
1
9
9
2.
2.
2.
7.
1 .
3
2.
1 .
3.
0
2
Be
.33E-4
.32E-5
.16E-6
.37E-5
.11E-5
.58E-4
.47E-5
.02E-4
.37E-4
. 98E-4
35E-4
80E-5
.637
.21E-4
ng/J
Ba
1 48E-3
3.20E-
1 .24E-
3
3
2.49E-2
1.86E-
2.58E-
1.06E-
2
3
3
1.22E-2
5.07E-4
8.94E-4
6.65E-
2.76E-
0.940
1 .29E-
3
0
.J
o
1
1
3.
3.
2.
3
7.
2.
5.
2.
1 .
4.
0
2
V
.48E-3
.60E-3
.79E-4
.77E-3
07E-4
.32E-3
47E-4
04E-4
.07E-4
.98E-4
25E-3
15E-4
.749
.19E-3
Mn
1 .62E-2
1.91E-2
3.55E-3
5.76E-2
3.92E-2
1.93E-3
4.30E-3
1.02E-3
3.07E-3
1 .56E-3
1.48E-2
6.10E-3
0.936
2.S6E-2
All the emissions data were obtained from Con Edison (Reference 19).
barium were added to the kerosene and No. 2 distillate oil to retard
emissions.
Also magnesium
visible smoke
and
43
-------
TABLE 14. ASTM-D-2880-76-TRACE METAL LIMITS FOR
GAS TURBINE FUELS (Reference 28)
ASTM
No.
0
1
2
3
Fuel
Type
Naphtha
Kerosene
No. 2 Fuel Oil
Heavy Distillate
Impurity Content, ppm by Weight
Vanadium
0.5
0.5
0.5
0.5
Sodium &
Potassium
0.5
0.5
0.5
0.5
Calcium
0.5
0.5
0.5
0.5
Lead
0.5
0.5
0.5
0.5
TABLE 15. MAXIMUM TRACE METAL EMISSIONS BASED ON ASTM-D-2880-76
GAS TURBINE FUEL LIMITS (Reference 28)
ASTM
No.
0
1
2
3
Fuel
Type
Naphtha
Kerosene
No. 2 Fuel Oil
Heavy Distillate
Emission Factor, ng/J
Vanadium
0.112
0.112
0.112
0.112
Sodium +
Potassium
0.112
0.112
0.112
0.112
Calcium
0.112
0.112
0.112
0.112
Lead
0.112
0.112
0.112
0.112
however, is somewhat questionable, especially because the highest POM levels
obtained were from an ambient air sample. The existing data base for POM and
other organics emissions is therefore inadequate. The overall assessment of
the existing emissions data for electricity generation distillate oil-fueled
gas turbines is that the data base is inadequate because of the paucity of data
for trace elements and organics emissions.
Source Seven ty--
The mean source severity factor is defined as the ratio of the calculated
maximum ground level concentration of the pollutant species for an isolated
44
-------
TABLE 16. POM EMISSIONS DATA FOR AN ELECTRICITY GENERATION
DISTILLATE OIL-FUELED GAS TURBINE OPERATING AT
70 PERCENT LOAD (Reference 20)
POM Species
Anthracene/phenanthrene
Methyl anthracenes
Fluoranthene
Pyrene
Methyl fluoranthenes/pyrenes
Chrysene/benz(a) anthracene
Benzo fluoranthenes
Benzo(a)pyrene
Benzo (e)pyrene
Perylene
No
Additive
1.53
0.95
0.23
0.10
ND
0.06
ND
ND
ND
ND
Emission
Mn
Additive
1.36
0.84
0.24
0.14
0.02
ND
ND
ND
ND
ND
Factor, pg/J
Ba/Mn
Additive
1.37
0.66
0.25
0.12
ND
ND
ND
ND
ND
ND
Fe
Additive
2.36
1.03
0.52
0.46
0.06
0.18
0.06
0.03
0.06
ND
ND - Not Detected. Detection limits were not specified in Reference 20.
typical source to the level at which a potential environmental hazard exists.
Detailed methods for the calculation of source severity factors are described
in Appendices A and B. In general, the potential environmental hazard level
is taken to be the Threshold Limit Value (TLV) divided by 300 for non-criteria
pollutants and the primary ambient air quality standard for the criteria pol-
lutants. For pollutants for which no TLV is available, the Minimum Acute
Toxicity Effluent (MATE) values based on health effects will be used in place
of TLV's. The MATE concept was originally developed as a guide for environ-
mentally safe emission concentrations from fossil energy processes, and MATE
values for a large number of compounds have been recently developed under the
direction of the U.S. Environmental Protection Agency (Reference 29). The
MATE value based on health effects is usually assumed to equal the TLV when-
ever the TLV is available. The MATE values and TLV's are therefore equivalent,
and it is reasonable to use MATE values as TLV's in the calculation of source
severity factors whenever necessary.
45
-------
In Tables 17 and 18, the mean emission factors and the mean source
severity factors of air emissions from gas and distillate oil-fueled gas tur-
bines are presented. Of the known emissions, NOX has mean source severity
factors >0.05 for all four gas turbine categories, indicating a potential
environmental effect. In addition, S03 emissions from distillate oil-fueled
gas turbines also have mean source severity factors >0.05, and should be
considered as environmentally significant. The source severity factors for
POM emissions have not been computed because reliable POM emissions data are
not available from the existing data base.
The source severity concept has also been used in the evaluation of the
adequacy of emissions data base. As discussed previously, the upper bound $u
for the mean source severity factor has been calculated for trace elements for
which variability data are available. The results of these calculations show
that among the trace element emissions from distillate oil-fueled gas turbines,
S <0.05 for barium, cadmium, magnesium, manganese, and vanadium. The existing
emissions data base for these trace elements has therefore been considered adequate
Status of Existing Emissions Data Base--
In summary, the evaluation of the adequacy of existing emissions data for
gas turbines has led to the following conclusions:
0 The existing emissions data base is adequate for industrial and
electricity generation gas-fueled gas turbines.
The existing data base for NO , HC and CO emissions is adequate for
industrial distillate oil-fueled gas turbines. For other types of
emissions, emissions data for electricity generation distillate oil-
fueled gas turbines may be used to estimate the emissions from
industrial distillate oil-fueled gas turbines.
0 The existing data base for NOX, HC, CO, particulate, S02 and S03
emissions is adequate for electricity generation distillate oil-fueled
gas turbines. Among the trace elements, the existing data base for
barium, beryllium, cadmium, lead, magnesium, manganese and vanadium
emissions is adequate. However, the existing data base for other
trace elements and organics emissions is inadequate for electricity
generation distillate oil-fueled gas turbines
46
-------
TABLE 17. EMISSION FACTORS AND MEAN SOURCE SEVERITIES OF AIR
EMISSIONS FROM GAS-FUELED GAS TURBINES
Parameter
Average Unit
Size
Average Fuel
Consumption
Average Stack
Height
Pollutant
N0y
A
HC
CO
Part
S0x
Industrial
2.24 MW
3.19 x 10
Gas Turbine
(3,000 HP)
14 J/year
24 m
Emission Factor
(ng/J)
130
8.6
48.0
5.1
0.26
Mean
Severity S
0.5212
0.0246
0.0007
0.0062
<0.0001
Elec. Gen.
30
4.28 x 10
159
Emission Factor
(ng/J)
168
23.8
64,8
5.1
0.26
Gas Turbine
MW
15 J/year
m
Mean
Severity S
0.1711
0.0207
0.0003
0.0019
<0.0001
(1) Average fuel consumption for industrial gas turbine was calculated
assuming an average heat rate of 15,400 Btu/KW-hr and a capacity factor
of 100%.
(2) Average fuel consumption for electricity generation gas turbine was
calculated assuming an average heat rate of 15,400 Btu/KW-hr and a
capacity factor of 100%.
(3) For industrial gas turbines, the NOx, HC and CO emission factors were
based on existing emissions data, the particulate emission factor was
assumed to be the same as that for electricity generation gas turbines,
and the SOx emission factor was calculated assuming an average natural
gas sulfur content of 4,600 g/106 m3.
(4) For electricity generation gas turbines, the NOx, HC, CO and particulate
emission factors were all based on existing emissions data, whereas the
SOX emission factor was calculated assuming an average natural gas sulfur
content of 4,600 g/106 m3. Also, the HC and CO emissions factors are
composite emission factors, which are equal to 1.58 and 2.18 times the
corresponding unweighted emission factors at base load conditions.
47
-------
TABLE 18.
FACTORS AND MEAN SOURCE SEVERITIES OF AIR
FROM DISTILLATE OIL-FUELED GAS TURBINES
Industrial Distillate
Parameter
Average Unit
Size
Average Fuel
Consumption
Average Stack
Height
Pollutant
NOy
HC
CO
Part
SO?
SOs
As
Ba
Be
Br
Cd
Cu
Mg
Mn
Pb
Sn
V
Oil Turbine
2,238 MW (3,
3.19 x 1014
000 HP)
J/year
24m
Emission
Factor
(ng/J)
207
3.6
101
15.5
41.0
1.9
8.94E-4
6.65E-3
1.35E-3
2.24E-4
1.36E-3
6.71E-4
6.48E-2
1.48E-2
6.89E-3
1.10E-2
1.25E-3
Mean
Severity
S
0.8309
0.0103
0.0014
0.0190
0.0360
0.2320
0.0002
0.0013
0.0065
<0.0001
0.0026
0.0003
0.0010
0.0003
0.0044
0.0005
0.0002
Upper Bound
for Mean
Severity Su
_
0.0025
0.0107
0.0052
0.0027
0.0005
0.0074
0.0004
Elec. Gen. Distil
Oil Turbine
late
30 MW
4.
28 x 1015 J year
159 m
Emission
Factor
(ng/J)
311
7.3
43.8
15.5
41.0
1.9
8.94E-4
6.65E-3
1.35E-3
2.24E-4
1.36E-3
6.71E-4
6.48E-2
1.48E-2
6.89E-3
1.10E-2
1.25E-3
Mean
Severity
S
0.3158
0.0063
0.0002
0.0058
0.0110
0.0704
<0.0001
0.0004
0.0020
<0.0001
0.0008
<0.0001
0.0003
<0.0001
0.0014
0.0002
<0.0001
Upper Bound
for Mean
Severity Su
-
-
0.0008
0.0033'
0.0016
0.0008
0.0002
0.0023
0.0001
(1) Average fuel consumption for industrial distillate oil turbine was calculated
assuming an average heat rate of 15,400 Btu/KW-hr and a capacity factor of
100%
(2) Average fuel consumption for electricity generation distillate oil turbine
was calculated assuming an average heat rate of 15,400 Btu/KW-hr and a
capacity factor of 100%
(3) For industrial distillate oil turbines, the NOX, HC and CO emission factors
(4)
were based on existing emissions data, the particulate, SOg, $03 and trace
element emission factors were assumed to be the same as those for electri-
city generation distillate oil turbines.
For electricity generation distillate oil turbines, the NOX, HC, CO, parti-
culate, S02 and $03 emission factors were all based on existing emissions
data. Also, the HC and CO emission factors are composite emission factors,
which are equal to 1.58 and 2.18 times the corresponding unweighted emission
factors at base load conditions. Among the trace elements, the emission
factors for Ba, Be, Cd, Mg, Mn, Pb and V were based on emissions data provided
by Con Edison, whereas the emission factors for As, Br, Cu and Sn were obtained
from the GCA report (Reference 1)
48
-------
4.1.3 Existing Emissions Data for Reciprocating Engines
The present study classifies internal combustion engines into the follow-
ing categories:
1.4.22.0.0 Electricity Generation Internal Combustion Distillate Oil
Reciprocating Engine
1.4.30.0.0 Electricity Generation Internal Combustion Gas Reciprocating
Engine
2.4.22.0.0 Industrial Internal Combustion Distillate Oil Reciprocating
Engine
2.4.30.0.0 Industrial Internal Combustion Gas Reciprocating Engine
The largest engines in the United States are about 13,500 HP (10 MW). The
average size internal combustion (1C) engine for electricity generation is
approximately 2,500 HP (1.9 MW). For the industrial sector, the estimated
average size of 1C engines is 2,000 HP (1.5 MW). although the majority of the
sales for other industrial uses are below 1,000 HP. Because of the consider-
able overlapping in size ranges for electricity generation and industrial 1C
engines, the existing emissions data for these two user sectors will be
evaluated together.
Emissions Data Sources
Four primary sources of emissions data for electricity generation/
industrial 1C engines have been identified. The Acurex report contains a
tabulation of NO , CO and total hydrocarbon emissions source test data supplied
A,
by engine manufacturers (Reference 6). The McGowin report includes NO , CO
X
and total hydrocarbon emissions data from literature sources, engine manufac-
turers, and industrial sources of field data (Reference 15). The Southwest
Research Institute (SWRI) reports contain NOV, CO and total hydrocarbon
A
emissions data from testing at compressor stations of natural gas pipelines,
but the emissions data are restricted to gas-fueled 1C engines (References 11
and 16). In the SWRI study, analyses of the emissions data have indicated that
there is no direct relationship between NO emissions (the pollutant of primary
X
interest for 1C engines) and the engine cycle configuration (2- or 4-stroke
49
-------
cycle), or aspiration (natural or turbocharged) or rated engine horsepower.
Therefore, no subgrouping of emissions data is necessary.
Electricity Generation/Industrial Reciprocating Engines
The emissions data compiled from the Acurex, McGowin, and SWRI reports
are summarized in Tables 19 and 20*. For the SWRI NOX emissions data for
which accompanying humidity data are available, a humidity correction factor
K has been applied to the NOX values:
K = 1
l-0.003(H-75)
where H is the humidity in grams H20/lb dry air (Reference 11).
As noted in Tables 19 and 20, the emissions data available are limited to
NO , CO, and hydrocarbon emissions. For these types of emissions, the existing
X
data base is judged to be adequate since the variability ts(x)/x is less than
0.7 for all cases. For gas engines, SO emissions are not of concern and may
/\
be estimated from the sulfur content of natural gas. As discussed in the case
of gas-fueled turbines, particulate, trace elements and POM emissions from gas
engines should be insignificant. Also, particulate emissions from gas engines
may be assumed to be equal to particulate emissions from gas turbines on an
emission factor basis. It, therefore, follows that the existing emissions data
base is adequate for electricity generation/industrial internal combustion gas
reciprocating engines.
For distillate oil engines, SOX emissions may be estimated from the fuel
sulfur content. Manufacturers of diesel engines currently recommend that users
burn only fuels which contain less than 0.5 percent sulfur (Reference 6). This
practice is suggested to minimize corrosion, but it also results in SO emission
levels of less than 2 g/bhp-hr from most distillate oil engines, and an average
SOX emission level of 0.946 b/bhp-hr for these engines (Reference 1).
For S03 emissions from distillate oil-fueled reciprocating engines (diesel
engines), Hunter and Engel recently reported measurements made by Goksoyr-Ross
Note that emission factors for gas and distillate oil engines are normally
reported in units of g/bhp-hr.
50
-------
TABLE 19. EXISTING EMISSIONS DATA FOR ELECTRICITY GENERATION/
INDUSTRIAL GAS-FUELED STATIONARY RECIPROCATING
ENGINES UNDER BASE LOAD CONDITIONS
*
Engine Model
CB
CB
CB
CB
CB
CB
CB
CB
CB
CB
CB
CB
CB
CB
CB
CL
CL
CL
CL
CL
CL
CL
CL
CL
IR
IR
IR
IR
GMV-10
GMW-8
GMW-8
GMWA-6
GMWA-8
GMWC-6
GMWC-10
LSV-16
LSVA-16
10V-250
14V-250
16V-250
GMVA-8
GMVH-8
KSV-12
BA-8
BA-8
HBA-8T
TCV-12
TCV-16
TCVC-16
TLA-6
TLA-6
TLA-8
KVG-8
616-KVR
412-KVS
616-KVT
1
2
2
1
2
2
3
4
4
3
4
5
1
1
3
1
1
2
4
5
8
2
2
2
5
2
4
HP
,350
,050
,000
,500
,000
,000
,400
,400
,400
,400
,800
,500
,080
,600
,240
,600
,760
,050
,000
,500
,000
,000
,100
,700
800
,500
,000
,000
Emission Factor, g/bhp-hr Onf
NO
25.
1
0.
18.
1
1
3.
8.
0.
23.
10.
1
1
8.
1.
6.
18.
1
1
1
1
1
1
1
5.
3.
2.
8.
0.
4.
6.
6.
0.
8.
8.
8.
3.
9.
5.
7.
X
69
66
45
93
01
01
67
11
59
22
26
82
1
42
75
76
87
72
90
08
61
57
61
54
25
92
11
17
CO
0.
0.
0.
0.
0.
0.
0.
1.
4.
0.
0.
1.
0.
0.
-
0.
2.
2.
2.
1.
3.
2.
2.
2.
0.
0.
0.
1.
80
53
31
53
48
92
75
31
11
53
90
48
3
2
97
90
23
83
52
58
84
20
18
62
90
68
04
3
5
4
6
3
5
5
6
1
4
4
3
1
1
4
4
7
8
5
3
5
4
4
7
1
2
2
2
ii/-i I\^IG.ICII\rfC
.5
.6
.9
.3
.6
.4 11,16
.5
.2
.4
.1
.7
.9
.9
.45 6
.26
.1
.6
.3
.5
.8 11,16
.0
.3
.3
.6
.3
.2
.8 11J6
.8
- Continued -
51
-------
TABLE 19 (Continued)
*
Engine Model
IR 412-KVSR
WS 6G-510
WS 8G-825
WS 8GT-825
WS 6G-510
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
HP
2,400
400
800
1,100
360
large
large
large
large
large
large
1,600
2,140
1,940
5,230
400
800
800
1,000
2,260
1,950
1,610
1,540
3,600
3,655
2,000
1,080
1,350
1,600
400
2,200
..
Emission
NOV
X
17.5
17.8
17.7
22.1
21.5
12.5
13.5
12.5
12.4
14.0
7.8
20.13
7.4
8.9
11.8
7.6
14.2
9.4
16.8
9.6
12.1
9.7
10.9
9.1
7.4
8.5
15.23
10.0
4.6
7.6
17.9
- Continued
52
Factor,
CO
0.6
0.40
1.68
0.59
1.0
9.0
15.0
7.0
10.7
16.0
29.0
0.17
-
-
2.0
_
1.7
6.0
7.4
_
_
3.8
3.0
1.8
2.5
4.6
0.29
_
_
_
M
-
g/bhp-hr
HC
1.2
0.28
0.8
6.87
1.0
0.9
1.0
1.5
1.5
1.0
1.0
1.58
-
-
1.1
10.1
4.4
30.6
_
_
_
4.3
3.2
4.1
4.4
5.4
1.94
5.0
10.1
17.0
Reference
6
6
6
15
15
-------
TABLE 19 (Continued)
*
Engine Model HP
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Mean x
Standard
of Mean
Variabili
*
CB -
CL -
IR -
WS -
1,950
4,000
925
750
800
1,170
500
800
1,320
Deviation
s(a)
ty t s(x)/x
Copper Bessemer
Dresser Clark
Ingersoll Rand
White Superior
Emission
N0x
14.1
10.4
15.7
12.5
9.1
14.4
10.2
10.9
13.0
12.27
0.55
0.089
Factor,
CO
-
-
0.9
1.1
0.5
1.3
3.2
-
5.6
2.69
0.46
0.345
g/bhp-hr
HC
-
-
6.5
-
16.8
2.5
0.8
2.0
1.8
4.18
0.44
0.212
Reference
15
15
The mean emission factor for CO was computed after discarding the outlying
data point 29.0 g CO/bhp-hr using the method of Dixon. The mean emission
factor for hydrocarbons was computed after discarding the outlying data
point 30.6 g HC/bhp-hr using the method of Dixon.
53
-------
TABLE 20 EXISTING EMISSIONS DATA FOR ELECTRICITY GENERATION/
INDUSTRIAL DIESEL-FUELED STATIONARY RECIPROCATING
ENGINES UNDER BASE LOAD CONDITIONS (Reference 6)
*
Engine Model
EMD 12-645 E-3
CB KSV-12
Unknown
Unknown
Unknown
Unknown
Unknown
CB KSV-12-GDT
EMD 16-645 E
EMD 16-645 E-3
EMD 20-645 E-3
WS 40-8
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
Unknown
EMD 8-645-E-3
EMD 12-645 E
EMD 8-645 E
Mean x t
Standard Deviation of
Variability t s(x)/x
1 1 r\
HP
2,475
4,300
large
large
large
large
large
2,410
2,200
3,200
3,200
620
large
large
medium
medium
med i urn
medium
<500 hp
large
1 ,650
1,650
1,100
Mean s(x)
Emission Factor, g/bhp-hr
NOX
12.51
10.99
10.8
11.4
18.8
16.3
10.7
11.24
14.6
14.74
12.99
8.70
8.60
7.40
6.60
4.60
4.0
5.5
10.0
8.2
12.88
14.74
17.07
11.02
0.83
0.156
CO
1.19
3.85
1.71
-
0.63
0.53
0.85
3.02
5.4
1.23
1.56
8.50
2.10
0.8
1.9
4.1
1.6
1.3
4.3
1.0
0.93
4.14
2.20
2.11
0.31
0.310
HC
0.38
0.13
1.0
0.44
0.55
0.18
0.16
0.46
0.19
0.48
0.59
0.25
0.40
0.50
0.60
0.60
0.30
0.20
0.30
0.30
0.42
0.49
0.37
0.40
0.04
0.210
EMD - Electromotive Division (GM)
CB - Copper-Bessemer
WS - White-Superior
The mean emission factor for CO was computed after discarding the outlying
data point 8.5 g CO/bhp-hr using the method of Dixon.
54
-------
and Shell-Emeryville wet chemical methods (Reference 30). Results from the
nine test conditions indicated an increase of SOs level with increased 862
level. An average of 2.13 percent of the fuel sulfur was found to be con-
verted to $03, with a calculated variability ts(x)/x of 0.59. As this is
the only set of data available and only one diesel engine was tested, addi-
tional 863 emissions data are required.
For other types of pollutants, data on particulates, particulate
sulfate, trace elements and organics emissions are not available. The lack
of these emissions data leads to the conclusion that the existing emissions
base is inadequate for electricity generation/industrial internal combustion
distillate oil reciprocating engines.
Source Severity--
In Tables 21 and 22, the mean emission factors and the mean source
severity factors of air emissions from gas and distillate oil engines are
presented. Of the known emissions, NOX and hydrocarbons have mean source
severity factors >0.05, for all four reciprocating engine categories, indicat-
ing that these are the problem pollutants common to all reciprocating engines.
In addition, particulate, SO and SO, emissions from distillate oil engines
A O
also have mean source severity >0.05, even though these emissions have been
previously considered as relatively unimportant for distillate oil engines.
The mean source severity factors for particulate emissions from distillate
oil engines were calculated using the AP-42 emission factor for particulates,
and the reliability of this AP-42 emission factor is unknown.
Status of Existing Emissions Data Base--
In summary, the evaluation of the adequacy of existing emissions data for
reciprocating engines has led to the following conclusions:
The existing emissions data base is adequate for electricity
generation/industrial internal combusion gas reciprocating engines.
The existing data base for NOX, HC, CO, and S02 emissions is
adequate for electricity generation/industrial distillate oil
reciprocating engines. The existing data base for particulates,
S03, particulate sulfate, trace elements and organics emissions
is inadequate for these combustion categories.
55
-------
TABLE 21. EMISSION FACTORS AND MEAN SOURCE SEVERITIES
OF AIR EMISSIONS FROM RECIPROCATING GAS ENGINES
Parameter
Average Unit
Size
Average Fuel
Consumption
Average Stack
Height
Pollutant
N0x
HC
CO
Part
S0x
Industrial Gas Engine
1.5 MW
(2,000 HP)
1.39 x 1014 J/year
16.9 m
Emission Factor Mean
g/bhp-hr ng/J Severity S
12.27 1550 5.666
4.18 528 1.321
2.69 340 0.0040
0.04 5.1 0.0055
0.002 0.26 0.0002
El
ec. Gen. Gas
Engine
1 .9 MW
(2,500 HP)
1
.73 x 1014 J/year
16.9 m
Emission Factor
g/bhp-hr
12.27
4.18
2.69
0.04
0.002
ng/J
1550
528
340
5.1
0.26
Mean
Severity S
7.083
1.651
0.0051
0.0068
0.0002
01
cr>
(1) Average fuel consumption for gas engine was calculated assuming an average heat rate of
7,500 Btu/bhp-hr and a capacity factor of 100%.
(2) The NOX> HC and CO emission factors were based on existing emissions data, the particulate
emission factor was assumed to be the same as that for gas fueled turbines, and the SOX
emission factor was calculated assuming an average natural gas sulfur content of
4,600 g/106 m3.
-------
TABLE 22. EMISSION FACTORS AND MEAN SOURCE SEVERITIES OF AIR
EMISSIONS FROM RECIPROCATING DISTILLATE OIL ENGINES
Parameter
Average Unit
Size
Average Fuel
Consumption
Average Stack
Height
Pollutant
NO
X
HC
CO
Part
S0x
so3
As
Br
Cu
Mn
Sn
Industrial
Distillate
Oil Engine
1.5 MW
(2,000 HP)
1.39 x 1014 J/year
16.9 m
Emission
g/bhp-hr
11 .02
0.40
2.11
0.81
0.95
2.53E-2
0.70E-5
0.18E-5
0.53E-5
0.23E-4
0.86E-4
Factor
ng/J
1390
51
266
102
120
3.19
0.89E-3
0.89E-3
0.67E-3
2.89E-3
1.09E-2
Mean
Severity S
5.089
0.1264
0.0032
0.1103
0.0920
0.3316
0.0002
<0.0001
0.0003
<0.0001
0.0005
Elec. Gen
. Distillate
Oil Engine
1.9 MW
(2,500 HP)
1.
73 x 1014 J/year
16.9 m
Emission
g/bhp-hr
11 .02
0.40
2.11
0.81
0.95
2.53E-2
0.70E-5
0.18E-5
0.53E-5
0.23E-4
0.86E-4
Factor
ng/J
1390
51
266
102
120
3.19
0.89E-3
0.89E-3
0.67E-3
2.89E-3
1.09E-2
Mean
Severity S
6.361
0.1581
0.0040
0.1379
0.1150
0.4144
0.0002
0.0001
0.0004
<0.0001
0.0006
(1) Average fuel consumption for distillate oil engine was calculated assuming an average heat rate
of 7,500 Btu/bhp-hr and a capacity factor of 100%.
(2) The NOX, HC and CO emission factors were based on existing emissions data, the particulate
emission factor was obtained from AP-42 (Reference 23), and the SOX and trace element emission
factors were based on the average sulfur and trace element content of distillate oil (Reference 1)
-------
4.2 EMISSIONS DATA ACQUISITION
4.2.1 Selection of Test Facilities
Because gas turbines and reciprocating engines contribute significantly
to the nationwide NOX emissions burden, these combustion categories have been
identified as major stationary sources of air pollution. In the evaluation of
existing emissions data for these combustion sources, it has been determined
that the existing emissions data base is adequate for electricity generation
and industrial gas-fueled gas turbines and reciprocating engines, and inade-
quate for electricity generation and industrial oil-fueled gas turbines and
reciprocating engines. Further, the inadequacy of the existing emissions data
base for the oil fueled internal combustion sources is largely due to the
paucity of data for trace element and organic emissions. The combination of
significant air pollution impact and data inadequacy led to the decision of
selecting five test sites each for electricity generation distillate oil
turbines and for electricity generation distillate oil reciprocating engines
in the first phase. For electricity generation gas-fueled gas turbines and
gas reciprocating engines, it was decided to select one test site for each
source category in the first phase to assure that previously unidentified
pollutants are not being emitted in environmentally unacceptable quantities.
Emissions data obtained from the electricity generation internal combustion
sources will be extrapolated for use as estimates of emissions from the
industrial internal combustion sources, especially because the size ranges for
the electricity generation and industrial internal combustion sources often
overlap and the equipment characteristics are similar.
The choice of specific sites was based on the representativeness of the
sites as measured against the important characteristics of systems within
each source category. As discussed in Section 39 candidate test facilities
for electricity generation gas and distillate oil turbines should be in the
15 to 70 MW size range and less than 8 years old. Also, the use of fuel addi-
tives to reduce visible smoke emissions is quite prevalent for electricity
generation distillate oil turbines, and some tests with fuel additives should
be included. For electricity generation gas and distillate oil reciprocating
engines, the average size unit has been estimated to be 1.9 MW (2,500 HP),
58
-------
with an average age of approximately 10 years. The engine model, rated
capacity, age, and pollution control method for the eleven test sites selected
are presented in Table 23. For gas and distillate oil turbines, the six test
sites selected were all under 8 years old, in the 14.5 to 28 MW size range,
and manufactured by Turbo Power and Marine Systems, one of the three major
manufacturers of utility gas turbines. In addition, three of the distillate
oil turbines selected used CI-2 (methyl cyclopentadienyl manganese tricarbonyl)
a common organic manganese fuel additive. For distillate oil reciprocating
engines, the five test sites selected all have electricity generation capacity
of 2.5 MW, were either 1 year old or 8 years old, and all were manufactured by
the Electromotive Division of General Motors, the principal manufacturer of
utility diesel engines. An electricity generation gas reciprocating engine
test site, however, could not be located during the course of this program.
This is considered to have minimum impact because the existing emissions data
base for this combustion source category has been judged to be adequate.
4.2.2 Field Testing
Field testing procedures were based on Level I environmental assessment
methods. The Source Assessment Sampling System (SASS) was used to collect
particulate, organic and trace metal samples. The SASS train (Figure 3) is
a high volume (approximately 5 scfm) system designed to extract particulates
and gases from the stack, separate particulates into four size fractions, trap
organics in an adsorbent, and collect volatile trace metals in liquid solu-
tions. A high volume system is required to collect adequate quantities of
trace materials for subsequent laboratory analyses. The train is constructed
such that all sample contacting surfaces are of Type 316 stainless steel, tef-
lon or glass.
The internal combustion tests were carried out without the cyclones in
the SASS train due to the low concentrations of particulates and their
characteristic small particle diameters. The particulates were collected on
(R]
Spectrogradev ' glass fiber filters in the heated oven. The sample stream
was then cooled and the organic material collected by adsorption on XAD-2
59
-------
TABLE 23. CHARACTERISTICS OF INTERNAL COMBUSTION SITES TESTED
en
o
Combustion
Source Type
Gas Turbine
Distillate Oil
Turbine
Distillate Oil
Reciprocating
Engine
Site
No.
#110
#111
#112
#306
#307
#308
#309
#310
#311
#312
#313
*
Engine Model
TPM
TPM
TPM
TPM
TPM
TPM
EMD
EMD
EMD
EMD
EMD
FT 4A-11DF
FT 4A-11DF
GG 4C-1D-DF
FT 4A-8LF
FT 4A-8LF
FT 4A-11LF
64-5E4
64-5E4
64-5E4
654
654
Rated Capacity
Base Load Peak Load
20
20
28
14
14
20
2
2
2
2
2
.6
.6
.5
.5
.2
.5
.5
.5
.5
.5
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
22.6
22.6
30
22
22
26
2.75
2.75
2.75
2.75
2.75
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
MW
5
5
4
8
8
5
8
8
8
1
1
Age
Years
Years
Years
Years
Years
Years
Years
Years
Years
Year
Year
Pollution Control
Device
None
CI-2 Fuel Additive
None
CI-2 Fuel Additive
CI-2 Fuel Additive
None
None
None
None
None
None
TPM - Turbo Power and Marine Systems
EMD - Electromotive Division of General Motors
-------
STACK T. C.
HEATER
CON-
TROLLER
DRY GAS METER ORIFICE METER
CENTRALIZED TEMPERATURE
AND PRESSURE READOUT
CONTROL MODULE
r
ILTER I
F LTER | GAS COOLER
1
I 1
I
)|CONVECTK
jOVEN
L
)N
a
! 1
I
i
i
i ,
GAS
TEMPERATURE
T.C.
OVEN
T.C.
XAD-2
CARTRIDGE
IMP/COOLER
TRACE ELEMENT
COLLECTOR
CONDENSATE
COLLECTOR
10 CFM VACUUM PUMPS
IMPINGER
T.C.
Figure 3. Schematic of Source Assessment Sampling System (SASS).
-------
(a styrene, divinyl benzene copolymer). The gas then passed through an
impinger containing hydrogen peroxide to collect oxidizable constituents.
A second impinger with ammonium persulfate and silver nitrate and a third
impinger with ammonium persulfate were used to collect volatile trace
elements. At the time of testing, these were the methods outlined in the
manual. The methods have since been changed requiring silver nitrate also
in the third impinger. A fourth impinger containing silica gel was used to
remove the remaining moisture.
A flue gas sample was collected for on-site analyses using a stainless
steel probe, condenser, diaphragm pump and gas sampling bags. The gas in
the bag was injected into the gas chromatrograph through a heated gas sampling
valve. The resulting peaks were measured for retention times and areas and
compared against a known series of Cj-Cg standards for qualitative and quanti-
tative analysis.
Low molecular weight hydrocarbons were measured in the field using a
flame ionization detector gas chromatograph. The sample gas was compared to
C^-Cg N-alkanes. CC^, C^j N- and CO were measured using a thermal conduc-
tivity detector gas chromatograph. Standard mixes of the gases were used for
calibration.
Samples of the flue gas were obtained at a single traverse point approxi-
mating the average flow rate of the flue gas, as determined by a multi-point
traverse. Sample time was from 4 to 6 hours as required to obtain a total
sample volume of 30 cubic meters or greater.
Smoke spot numbers were determined using a Bachrach Smoke Spot Tester.
Visible emissions (percent opacity) were determined by a trained observer.
Water, solid waste and fuel samples were collected according to Level I
SASS procedures. Limited water analyses were carried out in the field as
specified in the procedures manual.
Sample recovery was carried out in a clean environment according to
Level I procedures. All sample containers were pre-cleaned and handled
according to the Level I specifications.
62
-------
Field tests were conducted at eleven internal combustion units in the
first phase. Seven of the units had sampling ports located in the stack.
The other four units were tested by use of a 3-foot SASS probe fitted with a
vertical nozzle adaptor. The SASS probe was positioned approximately six
inches above the stack at a point where the vertical adaptor sampled down
into this stack at a traverse point of average stack velocity. A typical lay-
out of an internal combustion unit is shown in Figure 4.
Test results from the first phase were evaluated to determine the need
for and type of additional sampling and analysis. These evaluations led to
the recommendation of additional tests to determine SCL and organic emissions
from electricity generation distillate oil reciprocating engines. Level II
tests were subsequently conducted at three of the diesel engine sites (Sites
309, 312, 313) previously tested. These were identified as Sites 309-2,
312-2 and 313-2.
At each of the Level II sites, the Goksoyr-Ross controlled condensation
train was used for the measurement of oxidized sulfur emissions. In this
approach, S0~ is separated from the gas stream by cooling the flue gas below
the dew point for SO, (H0SO«) but above the dew point of water. Particulate
matter (including metallic sulfates) is removed by means of a heated quartz
glass filter in a filter holder kept above 260°C (500°F). A condensation
coil for S03 (H2S04) collection is maintained at 60°C (140°F) by a water
circulation bath. The S02 is removed in impingers filled with H-Oo. A
schematic diagram of the controlled condensation train is shown in Figure 5.
Level II organic samples were acquired using the SASS train without
cyclones. Other changes made included the addition of acetone in the organic
sample recovery washes and the omission of isopropyl alcohol from the
impinger recovery washes.
4.2.3 Laboratory Analysis Procedures
The following sections present a detailed summary of the sample prepara-
tion and both inorganic and organic analysis procedures used for this part of
63
-------
SOUND SUPPRESSOR
SAMPLING PORT
EVAP. COOLER
AIR COMPRESSOR
&
FUEL PUMP
COMBUSTOR
COMPRESSOR
TURBINE
POWER
TURBINE
STACK
Figure 4. Typical Internal Combustion Unit
-------
en
en
ADAPTER FOR CONNECTING HOSE
TC WELL
ASBESTOS CLOTH
INSULATION
GLASS-COL
HEATING
MANTLE
STACK
RUBBER VACUUM
HOSE
DRY TEST
METER
PUMP
QUARTZ
FILTER
HOLDER
THREE WAY
VALVE
SILICA GEL
EMPTY
RECIRCULATOR
THERMOMETER
Figure 5. Schematic of Controlled Condensation System.
-------
the program. An exact written procedure for each disbursement and analytical
operation is given in the program Methods and Procedures Manual (Reference 31)
which has been published separately.
Inorganic Laboratory Analysis--
Level I inorganic analysis consisted of a Spark Source Mass Spectrometric
(SSMS) elemental survey along with specific analyses for mercury, arsenic,
antimony, and sulfate. Additional analyses for nitrate, fluoride, and chlo-
ride were also performed on selected samples. The analytical scheme followed
is shown in Figure 6.
Both liquid and solid samples were received in the laboratory for analy-
sis. Aqueous liquids required only minor preparations which are described in
each analytical procedure (Reference 31). Organic materials, both liquid and
solid, were combusted in a Parr oxygen bomb to destroy the organic matrix.
Solids that were primarily inorganic (with the exception of glass fiber par-
ticulate filters) were analyzed directly by SSMS, but were digested with aqua
regia for the other individual analyses. Particulate filters generally were
acid digested for the SSMS analysis as well, because of the cohesion and
sparking problems that are associated with having glass filters in the graphite
electrodes. It is still preferable, however, to run all particulate samples
for SSMS neat, and this was done whenever possible. Samples for chloride and
nitrate analysis were prepared by extraction with hot water. These hot water
extract solutions were also the preferred sample for sulfate analysis.
The prepared samples were aliquoted and disbursed by the Sample Bank
Manager. Mercury was analyzed by a cold vapor technique and both arsenic and
antimony were determined by hydride generation and Atomic Absorption Spectro-
metry (AAS) detection. The sulfate determination was a turbidimetric procedure
and nitrate was measured colorimetrically after reaction with brucine. Specific
ion electrodes were used to analyze both fluoride and chloride. These analyses
are described further in the following paragraphs.
Spark Source Mass Spectrometry (SSMS) -- SSMS analysis was used to
perform a semiquantitative elemental survey analysis on the Level I samples
taken. The analysis was performed using a JEOL Analytical Instruments, Inc.
Model JMS-01BM-2 Mass Spectrometer. The JMS-01BM-2 is a high resolution,
66
-------
'
0-2
IN
RR
MB
|
FILTER
L
T
1
1 - 3/j
CYCLONE
J
HOT WATER
EXTRA CTION
|
SO., Cl,
NO3
SOLID
SAMPLES
* t
3 - IOC
CYCLONE
>IO(J BULK
CYCLONE SOLIDS
1. j.l
HOT WATER
EXTRACTION
|
SO,, Cl,
N03
t
* t
1
FILTE
SOLID
PBIMABIIV MAJOR ORGA-
PRIMARILt" N|cs PRESENT
INORGANIC (E.G.COAL)
ji^ ^_ f
(»MS)^MS)* fl^B
Hg
As
Sb
S04
Cl
DRY
WEIGH
APS - ammonium persulfate
Figure 6. Level I Inorganic Analysis PI
an
-------
double focusing mass spectrometer with Mattauch-Herzog ion optics. The
instrument is specially designed to carry out high sensitivity trace element
analysis with the aid of an RF spark ion source and photoplate detection. An
aliquot of each sample to be analyzed is incorporated into two electrodes
which are then mounted in the ion source of the mass spectrometer. These
electrodes are "sparked" with a high voltage discharge which decomposes and
ionizes the electrode material. Because of the high energy of the electrical
discharge, most of the material is reduced to its elemental form. The ions
formed are collected with focusing plates and subsequently measured in the
mass spectrometer. Spark source mass spectrometry can be used to detect ele-
mental concentrations down to Iff9 g(one nanogram). Although the sensitivity
may vary somewhat from sample to sample, practically all elements (except H,
C, N, 0, and the inert gases) in the periodic table can be detected.
Interferences can result from the formation of multiple charged ions,
ion clusters and molecular ions such as oxides, hydrides, hydroxides, and
carbides. These interferences, coupled with the fact that the discharge con-
ditions in the ion source are not easily reproduced, limit the accuracy of the
technique. Spark source mass spectrometry, however, is very useful as a
survey tool, and is capable of providing semiquantitative results (i.e.,
accurate to within a factor of 2 or 3).
Mercury - Cold Vapor -- The cold vapor mercury analysis is based on the
reduction of mercury species in acid solution with stannous chloride and the
subsequent sparging of elemental mercury, with nitrogen, through a quartz cell
where its absorption at 253.7 nm is monitored.
Arsenic - Hydride Evolution -- The procedure entails the reduction and
conversion of arsenic to its hydride in acid solution with either stannous
chloride and metallic zinc or sodium borohydride (NaBH.). The volatile
hydride is swept from the reaction vessel, in a stream of argon, into an
argon-hydrogen flame in an atomic absorption spectrometer. There, the hydride
is decomposed and its concentration monitored at the resonance wavelength
193.7 nm. Some interferences with the Level I samples have been reported for
this arsenic procedure. In particular, it has been found that excess hydrogen
peroxide and nitric acid must be removed prior to the addition of either the
zinc slurry or sodium borohydride used to generate the arsenic hydride.
68
-------
Antimony - Hydride Evolution Antimony-containing compounds are de-
composed by adding sulfuric and nitric acids and evaporating the sample to
fumes of sulfur trioxide. The antimony liberated is subsequently reacted
with potassium iodide and stannous chloride and finally with sodium borohydride
to form stibine (SbH,). The stibine is removed from solution by aeration and
O
swept by a flow of nitrogen into a hydrogen diffusion flame in an atomic
absorption spectrometer. The gas sample absorption is measured at 217.6 nm.
Interferences in the flame are minimized because the stibine is freed from
the original sample matrix.
Sulfate - Turbidimetric -- The basis of the analysis is the formation of
a barium sulfate precipitate in a hydrochloric acid medium with barium chloride
in such a manner as to form barium sulfate crystals of uniform size. The
absorbance of the barium sulfate suspension was measured by a transmission
photometer and the sulfate ion concentration determined by comparison of the
reading with a standard curve.
Nitrate - Brucine Colorimetric -- Nitrate analysis was performed on hot
water extracts of particulate samples from selected sites using the standard
brucine nitrate colorimetric procedure. The reaction between nitrate and
brucine sulfate produces a yellow color which can be used for the colorimetric
estimation of nitrate. The intensity of the color is measured at 410 my. To
each sample aliquot to be analyzed, sodium chloride and sulfuric acid solutions
are first added. If any color or turbidity are present at this point, the
absorbance is measured for a blank correction. The brucine-sulfanilic acid
reagent is then added and the samples are kept in a bath of boiling water for
20 minutes. They are then cooled and their absorbance measured.
Fluoride - Specific Ion Electrode -- Fluoride was determined potentio-
metrically using a selective ion fluoride electrode in conuunction with a
standard single junction sleeve-type reference electrode and a pH meter having
an expanded millivolt scale. Sample pH was between 5 and 9. Polyvalent
+4 +3 +3
cations of Si , Fe , and Al interfere by forming complexes with fluoride.
The addition of a pH 5 total ionic strength adjuster buffer (TISAB II) con-
taining a strong, chelating agent preferentially complexes aluminum (the most
common interference), silicon, and iron and eliminates the pH problem.
69
-------
The addition ot TISAB II also provides a high total ionic strength
background to help mask the difference in total ionic strengths between samples
and standards. However, the TISAB II cannot entirely compensate for this
difference due to the very high and variable level of ionic strength in the
Level I SASS samples. Thus a known addition technique is employed to eliminate
the necessity of drawing different calibration curves for different types of
samples.
Chloride - Specific Ion Electrode -- Chloride was determined potentio-
metrically using a solid state selective ion chloride electrode in conjunction
with a double junction reference electrode and a pH meter having an expanded
millivolt scale. The solid state electrode is used because it is not sensi-
tive to the higher levels of nitrate, sulfate or bicarbonate which could be
present in many of the samples. This method does require that the sample and
standards have the same total ionic strength. A known addition technique is
employed to eliminate the necessity of drawing different calibration curves
for different types of samples because samples can have a very high and
variable level total ionic strength.
Detection Limits--
The determination of a system's detection limits for different chemical
species must include a discussion of three interrelated items. The first item
is the determination of the analytical detection limit for each species as
listed in the first part of Table 24. The second item is the determination of
the species quantities needed in each type of SASS sample (particulate filters,
XAD-2 module, impingers, etc.) to meet these analytical detection limits. The
analytical detection limits together with the average volume, weight, or
amount of the collected sample will yield through calculation the species
quantity needed in each of the SASS train components in order to be detectable.
This data when divided by the average volume of gas sampled, 30 m3, yields the
detectable species concentration in the gas stream (yg/m3). This data appears
in the second section of Table 24.
70
-------
TABLE 24. ANALYTICAL SASS TRAIN DETECTION LIMITS
I. Analytical Procedure
Detection Limit (ppm)
II. Average SASS Train
Detection Limits (mg/m )
a) Parti cul ate on Filter
b) XAD-2 Resin
*
c) Composite
d) Ammonium Persulfate
impinger
III. Necessary Fuel Concentration
to Meet Calculated SASS
Train Detection Limits (ppm)
a) Parti cul ate on Filter
b) XAD-2 Resin
*
c) Composite
d) Ammonium Persulfate
impinger
Hg
0.0001
0.0008
0.013
0.005
0.003
0.00006
0.001
0.0004
0.0003
As
0.005
0.08
1.3
0.5
0.3
0.003
0.07
0.02
0.01
Sb S04 NO"
0.005 1.0 0.1
0.07 62 1.6
1.2 1000
0.4 390
0.2
0.003 0.6 0.06
0.07 14 1
0.02 4 .4
0.01
F" Cl"
0.2 0.5
3.1 9.1
50 125
20 50
-
0.01 0.03
0.3 0.7
0.1 0.2
Composite - FLO- impinger + condensate + module rinse.
-------
The third item, shown in the last section of Table 24, is the deter-
mination of the species concentrations needed in the fuel to meet these gas
stream detectable concentration values. This is derived by multiplying the
volume of gas created by the combustion of one gram of fuel and the gas
stream concentration values. This yields (in ppm) the species concentrations
in the fuel required to produce detectable species quantities in the gas
stream. The volume of gas per gram of fuel is obtained by using the Nernst
equation and the stack emission formula (Appendix C) given below.
n
FG 1 - 4.762 (°2 )
100
where:
nFG = gram-moles of dry effluent/gram of fuel
F = gm-moles of dry effluent/gram of fuel under stoichiometric
combustion (Appendix C)
62 = volumetric 02 concentration, in percent, as determined from
field gas analysis.
The value "npo" is then used in the Nernst equation to yield the volume of gas
per gram of fuel, assuming 1 atm. and 20°C.
The values obtained for SASS train detection limits and corresponding
fuel concentration levels necessary to meet these limits will vary for each
site approximately ± one order of magnitude. This fluctuation is due to
variations in field sample liquid and solid volumes and weights, and exit gas
oxygen content.
Level I Organic Analysis Methodology--
An overview of the sources of the samples and the appropriate combinations
of the samples for analysis is shown in Figure 7. The overview of the
methodology and decision criteria used for the Level I organic sample prepara-
tion and analysis is shown in Figure 8.
72
-------
CALCULATE
CORRECTION FACTORS AND
ANALYZE SPECIAL SAMPLES
PER FIG- 7-2
a) FROM FIELD
Figure 7. Level I Organic Analysis Flow Chart
-------
4~~
LIQUID SAMPL
4
SASS TRAIN
SOLVENT RINSES
i '
ML AL
FOR GC
SECTIO
GC-'MS
7 10
ETHOD 1 ±
TOTAL ORGANICS
>500 (jg/M3
TCO >IO°o TOTAL
4
ALIQUOT FOR LC
9 MG TO 100 MG
UP TO 8 ML
^
SOLVENT
EXCHANGE
SECTION
7.8
4
LC,
SECTION 7.8
*
1
1234567 8
V J 1
T 4
TCO * GRAV - IR GRAV
SAMPLE
APPORTIONATION
SECTION 3.0
4
ORGANIC
ANALYSES
4
ES
4 £1
AQUEOUS SOLID
SOLUTIONS MATERIAL!
4 4
V
1 CONCENTRATE
,,77»Mn SECTION 7.4
SECTION TCO INPUT ^4g GRAV INPUT
^^ OF TOTAL ^\
\s. TCO, Mg'M3 ^
METHOD 2 ^^
TOTAL ORGANICS
> 500 19 ''M3;
TCO <10"- TOTAL
4
ALIQUOT FOR LC
9 MG TO 100 MG
UP TO 8 ML
4
EVAPORATE
AND TRANSFER
TO COLUMN
1
LC.SECTION 7,8
^
Ml 1
r ^12345678,
' IR GRAV. ' IR
> rt 4
\ -S I-RAUION x^
OP L No ^^ son , ...3 , ,.,^\ Yes LOW RESOLUTI ON
V X^^S?^ -» rEACT^EC7TR9°SCOPY'
' \ SECTION /
\
GC'MS
SECTIOf
1 SPECIAL FRACTIONS
JS 3.0, 7. 10
4
SOLID SAMPLES
1 ' I
PARTICULATE XAD-2
CRASH RESIN
1 ' T
1 '
EXTRACTION
SECTION 7.3
)f
ML
GRAVIMETRIC, SECTION 7.5
AND IR SECTION
7.6
4
TOTAL ORGANICS
< 500 M g M
1 STOP
Figure 8. Level I Organic Analysis Methodol
74
ogy
-------
As indicated in these two figures, the extent of sample preparation
required varied with sample type. Organic liquids did not need pretreatment.
The majority of the samples, including SASS train components, aqueous solu-
tions, bottom ashes, and other solids required an initial solvent extraction
to separate the organic and inorganic portions of the samples before the
analyses could be continued.
Both the extracts and the neat organic liquids were concentrated in a
Kuderna-Danish evaporator to a 10 ml volume. Two 1 ml aliquots were then
taken from each concentrate for the following analyses:
t Total chromatographable organic material (GC-TCO) and, should Level II
efforts have been required, GC/MS analysis.
Gravimetric determination of non-volatile organic material and an
infrared analysis on the residue from the gravimetric determination.
The data provided by performing the TCO and the gravimetric analyses were
used to make the decision as to the analysis path to be followed for all other
determinations. The TCO analysis provided quantitative information on the
bulk amount of semi-volatile organic material in the boiling range of the C7
to C-|g alkanes -- 90°C to 300°C. The gravimetric analysis provided quantitative
results on the amount of non-volatile organics in the sample. These two
values combined give an estimate of the total organic content of the sample.
Whenever the total organic content of the sample was equivalent to a stack
q
concentration of 500 yg/m or less, the organic analysis was terminated. When-
3
ever the value was greater than 500 yg/m stack concentration, the direction
of the analyses depended on the TCO results.
If the TCO was less than 10% of the total organic material, the analy-
tical pathway labeled "Method 2" in Figure 8 was followed. A suitably sized
sample aliquot was taken for liquid chromatographic fractionation, evaporated
to dryness and transferred to an LC column. Each separated fraction was sub-
sequently subjected to gravimetric and infrared analyses. If the TCO was
greater than 10% of the total organics, an aliquot for LC was prepared by
solvent exchange to preserve the volatile species. In this "Method 1" proce-
dure, each fraction separated still underwent gravimetric and infrared analyses;
however, in addition, the first seven LC fractions were first analyzed for TCO.
75
-------
The GC-TCO analysis has been used to obtain information on the quantity
of material boiling within discrete ranges corresponding to the boiling points
of the n-alkanes Cy through C]6 as well as on the total amount of material in
the overall n-alkane boiling range. Materials were classified solely on the
basis of their retention time relative to the n-alkane, and were quantitated
as n-alkanes. This means any compounds containing oxygen, nitrogen, sulfur or
halogens would also be reported as alkanes.
The infrared analyses provided information on the major functional groups
(i.e., chemical compound classes) present in a sample. Data obtained by the
GC-TCO and IR analyses interrelated: many compounds detected in the GC ana-
lysis were too volatile to remain for IR analysis, and many compounds detected
in the IR analysis had too low a volatility to be detected by the GC-TCO
procedure. In a similar manner, the results of GC analyses of the LC frac-
tions complemented the IR analyses of these samples.
The remaining paragraphs of this section briefly describe the analytical
techniques used in conducting the Level I organic analysis.
Extraction of Samples for Organics--
Extraction of aqueous samples for organics -- Typical liquid samples that
have been generated in this program include aqueous condensates, settling pond
samples, and ambient water samples. These liquid extractions were performed
with standard separatory funnels. The sample volume was measured and the
sample was transferred to the separatory funnel. Whenever necessary, the pH
of the sample was adjusted to neutral with either a saturated solution of
sodium bicarbonate or ammonium chloride. The sample was extracted three times
with a volume of high-purity methylene chloride equal to approximately 5 per-
cent of the sample volume. The resulting extract was measured, dried with
anhydrous sodium sulfate, and then concentrated to 10 ml.
Extraction of solid samples for organics -- Typical solid samples that
have been generated in this program include cyclone catches, particulate
filters, XAD-2 resin samples, bottom ashes, and electrostatic precipitator
dusts. These extractions were performed in appropriately sized Soxhlet extrac-
tors. Each sample was placed or weighed into a glass thimble and extracted
76
-------
for 24 hours with Distilled-in-Glass' ' or Nanograde^ ' purity methylene chlo-
ride. The resulting extracts were then concentrated.
Concentration of organic extracts -- Solvent extracts of solid and liquid
samples and solvent rinses of sampling hardware were concentrated in Kuderna-
Danish evaporators. Heat provided by a steam bath was sufficient to volatilize
the solvents. All samples were concentrated to a volume between 5 ml and
10 ml and then, when cool, transferred to a volumetric flask and diluted to a
final volume of 10 ml.
Gravimetric determinations for organics -- The weight of non-volatile
organic species in samples for Level I organic analyses was determined on the
concentrates obtained from the Kuderna-Danish concentrations of solvent extract
and rinse samples. The samples were transferred to either small glass beakers
(for LC fractions) or tared aluminum weighing dishes. The samples were then
evaporated at ambient temperature to a constant weight. The dry samples were
always stored in a desiccator. Weights of organic residues as small as 0.1 mg
were measured.
Infrared analysis -- Infrared analysis was used to determine the function-
al groups present in an organic sample or LC fraction of a partitioned sample.
The interpreted spectra provide information on functionality (e.g., carbonyl,
aromatic hydrocarbon, alcohol, amine, aliphatic hydrocarbon, halogenated
organic, etc.). Compound identification is possible only when that compound
is known to be present as a dominant constituent in the sample.
The minimum sample amount required for this analysis has been 0.5 mg. A
compound must be present in the sample at 5%-10% (w/w) at least for the charac-
teristic functional groups of a compound to appear sufficiently strong for
interpretive purposes. Organic solvents, water and some inorganic materials
cause interferences. Water, in particular, can cause a decrease in the quality
(i.e., resolution of a spectrum, sensitivity) of the analysis.
The initial organic sample or LC fraction, after evaporation, was either
(1) taken up in a small amount of carbon tetrachloride or methylene chloride
and transferred to a NaCl window, or (2) mixed with powdered KBr, ground to a
fine consistency, and then pressed into a pellet. A grating IR spectrophoto-
meter was used to scan the sample in the IR region from 2.5 to 15 microns.
77
-------
Cy-Ci6 total chromatographable organic material analysis -- Gas chromato-
graphy is used to determine the quantity of lower boiling hydrocarbons (boiling
points between 90°C and 300°C) in the concentrates of all neat organic liquids,
organic extracts and LC fractions 1 through 7 (when LC Method 1 is used)
encountered in Level I environmental sample analysis. Data were used to first
determine the total quantity of the lower boiling hydrocarbons in the sample.
3
Whenever the total of C7-C-,6 hydrocarbons exceeded 75 ygm , the chromatographic
results were reported as quantities In each of the C7-C16 boiling point ranges
rather than as a total.
The extent of compound identification is limited to representing all
materials as normal alkanes based upon comparison of boiling points. Also,
the analysis is semiquantitative because calibrations are prepared using only
one hydrocarbon, n-decane. The differences in instrument response, or sensi-
tivity, to other alkanes are well within the desired accuracy limits for Level
I analysis and are not taken into consideration in data interpretation.
Liquid chromatographic separations -- This procedure is designed to give
a separation of a sample into eight reasonably distinct classes of compounds
and is applied to Level I analyses of SASS train samples which contain a mini-
mum of 15 mg of non-volatile organics. Sample weights from bulk liquids and
solids were evaluated on a case-by-case basis. A sample weighing from 9 mg to
100 mg was placed on a silica gel liquid chromatographic column. A series of
eight eluents were employed to separate the sample into nominally eight
distinct classes of compounds for further analyses.
The use of HC1 in the final eluent results in a partial degradation of
the column material. Thus, the eighth fraction has silica contaminants present
in variable amounts. Filtration was attempted to separate silica gel from the
organics, but silica was still often observed, particularly in infrared spectra.
As indicated in Figure 8, two distinct analytical procedures can be used
in the performance of LC fractionations and subsequent analyses. The selection
of the pathway "Method 1" or "Method 2" was based on the results of gravimetric
and TOO determinations on the concentrated organic sample. For a LC separation
to be required, the total organic content of the total, original sample must
exceed 500 yg/m . Method 2 is used whenever the volatile hydrocarbon content
78
-------
determined by the TCO analysis is low -- less than 10% of the total. Method 1
is used whenever the volatile material content is in excess of 10% of the
total.
The first difference between Method 1 and Method 2 is in the method of
preparing the sample for introduction onto the LC column. In Method 2, where
there are few volatile substances, a simple, direct solvent evaporation step
is sufficient. In Method 1, however, care must be taken to preserve the lower
boiling components through the LC separation and subsequent analyses. There-
fore, a solvent exchange step has been incorporated to transfer the sample
from methylene chloride to the non-polar solvent hexane. In addition, when-
ever Method 1 was used, a TCO analysis was performed on the first seven
fractions for information on the mass and types of volatile compounds present
in each fraction. These data supplemented the gravimetric and infrared ana-
lyses which were performed on all fractions.
Low resolution mass spectrometric analysis -- This procedure is a survey
analysis used to determine compound types in an organic sample or in an LC
fraction of a sample. The analyst is specifically searching for hazardous
compounds or compounds which may be generally considered toxic, e.g., aromatic
hydrocarbons and chlorinated organics. Analysis using different sample ionizing
parameters results in molecular weight data, which, combined with IR and sample
source data, can provide specific compound identifications on a "most probable"
basis.
The mass spectrometer (MS) used in this procedure has sufficient sensi-
tivity such that 1 nanogram or less presented to the ionizing chamber results
in a full spectrum with a signal ratio of 10:1. A dynamic range of 250,000
is achievable. The detection limit for a specific compound related to the size
of an air sample or liquid sample varies widely depending on the types and
quantities of the species in the mixture. This is because of interfering
effects in the spectrum caused by multiple compounds. The impact of this inter-
ference is reduced by lowering the ionization voltage to produce spectra
containing relatively more intense molecular ions.
Solid samples are placed in a sample cup or capillary for introduction
via the direct insertion probe. More volatile samples are weighed into a
79
-------
cuvette for introduction through a batch or liquid inlet system. The probe
or cuvette is temperature programmed from ambient temperature to 300 C.
Periodic MS scans are taken with a 70 eV ionizing voltage as the sample is
volatilized during the program. A lower ionizing voltage range (10-15 eV)
can be used at the discretion of the operator if the 70 eV data are complex.
Spectra are interpreted using reference compound spectral libraries, IR data,
and other chemical information available on the sample. The results of LRMS
analysis give qualitative information on compound types, homologous series
and, in some cases, identification of specific compounds. This information is
then used to assess the hazardous nature of the sample.
Polycyclic organic compound analysis by gas chromatography/mass
spectrometry -- This is a combined gas chromatography/mass spectrometry
(GC/MS) method for qualitative and quantitative polycyclic organic material
(POM) determinations. Micro!iter quantities of concentrated sample extracts
derived from the sampling activity are used for this analysis.
Microliter sized samples are injected onto a gas chromatographic column
and are separated by the differences in the retention characteristics between
the sample components and the column material. As the components elute from
the column, they are transported via an instrument interface to the mass
spectrometer (MS), which is being operated in a Total Ion Monitoring (TIM)
mode.
In the MS, the various compounds are ionized, and all ion fragments in
the mass range of 40 to 400 AMU are monitored. The resulting mass spectra are
stored by the computerized data system. All compounds eluting from the GC in
detectable quantities could be identified, including aromatic compounds con-
taining heteroatoms, depending upon the desired scope of the analysis. At
this time, the computer is used to search the stored spectra for the specific
mass fragments shown in Table 25.
The spectra of POM's are quite distinctive because they yield very strong
molecular ions with little fragmentation. Using molecular ions to find POM's
in a mixture involves reconstructing the GC trace from the stored data using
only a single mass to charge (m/e) value. Any inflection in this mass
chromatogram indicates the possibility of a POM of that molecular weight. The
80
-------
spectrum is then displayed and the operator judges if the spectrum is con-
sistent with a POM. The GC retention time, as well as the spectrum, is used
to make this identification although it is often difficult to confirm which
isomer is causing a peak without standards for the specific material.
Using this technique, a large number of ROM's can be screened in a short
period of time and good identification of POM type is possible. More time is
required for exact identification. Table 26 lists POM's which are sought in
all samples; any POM with a molecular weight on this list will be determined.
If other POM's with different molecular weights are desired, all that is
needed for their identification is the molecular weight and a relative reten-
tion time or a standard. During the search of the data for POM compounds, non
POM compounds may interfere especially if they coelute with a POM. Computer
data interaction techniques, such as ion mapping, keep these interferences to
a minimum. If a POM is confirmed, the peak is quantitated using an internal
standardization method.
The GC/MS sensitivity varies with several parameters including the type
of compound, instrument internal cleanliness, resolution of closely eluting
peaks, etc. Under "everyday" operating conditions 20 nanograms (ng) eluting
in a peak about 5 seconds wide yields an MS signal with a usable signal to
noise ratio. Typically, this represents at least 100 yg of any single POM
compound in a concentrated extract of a sample.
TABLE 25. MASS TO CHARGE VALUES (m/e)s MONITORED*
128
154
162f
166
178
179
180
184
192
202
216
228
242
252
256
278
300
302
Mass to charge values have units in (gm/gm mole)/(electron/molecule)
flnternal Standard Chloronapathalene.
81
-------
TABLE 26. MINIMUM LIST OF ROM's MONITORED
Compound Name
Naphthalene
Biphenyl
Fluorene
9,10 Dihydro-phenanthrene
9 , 1 0-Di hydro-anthracene
2-Methyl-fluorene
1 -Methyl -fluorene
9-Methyl-fluorene
Phenanthrene
Anthracene
Benzoquinoline
Acridine
3-Methyl -phenanthrene
2-Methyl -phenanthrene
2-Methyl -anthracene
Fluoranthene
Pyrene
Benzo[a]fluorene or 1 ,2-benzofluorene
Benzo[b]fluorene or 2,3-benzofluorene
Benzo[c]fluorene or 3,4-benzofluorene
2-Methyl -f luoranthene
4-Methyl-pyrene
3-Methyl -pyrene
1 -Methyl -pyrene
Benzo [c]phenanthrene
Benzo[ghi]f luoranthene
Benzo[a]anthracene
Chrysene
Triphenylene (9,10 Benzo phenanthrene)
Molecular Weight
128
154
166
180
180
180
180
180
178
178
179
179
192
192
192
202
202
216
216
216 .
216
216
216
216
228
228
228
228
228
Mate Value,
Air, yg/rn^
5.0 x
1.0 x
1.4 x
N
N
N
N
N
1.59 x
5.6 x
N
9.0 x
3.0 x
3.0 x
3.0 x
9.0 x
2.3 x
N
N
N
N
N
N
N
2.73 x
N
4.5 x
2.2 x
N
104
103
104
103
104
104
104
104
104
104
105
104
101
103
(Continued)
82
-------
TABLE 26. (Continued)
* "
Compound Name
4-Methyl -benzo[a]anthracene
1 -Methyl -chrysene
6-Methyl-chrysene
7, 12-Di methyl -benzo [a] anthracene
9,10-Dimethy1-benzo[a]anthracene
Benzo [f]fluoranthene
Benzo [k]fluoranthene
Benzo [b]fluoranthene
Benzo[a]pyrene
Benzo[e]pyrene
Perylene
1 ,2,3,4-Dibenzanthracene
2,3,6,7-Dibenzanthracene
Benzo[b]chrysene
Picene
Benzo [c]tetraphene
Benzo [ghi]perylene
Coronene
1 ,2,3,4-Dibenzpyrene
1 ,2,4,5-Dibenzpyrene
Alkyl substituted naphthalenes
Dibenzothiophene
Methyl Dibenzothiophene
Dimethyl phenanthrenes
Trimethyl phenanthrenes
Alkyl substituted biphenyl
Ethyl fluorene
Molecular Weight
242
242
242
256
256
252
252
252
252
252
252
278
278
278
278
256
302
300
302
302
N/A
182
196
206
220
N/A
195
Mate Value,
Air, >ug/m3
N
1.79 x 103
1.79 x 103
2.6 x 10"1
2.96 x 101
N
1.63 x 103
9.0 x 102
2.0 x 10"2
3.04 x 103
N
1.0 x 1 04
N
N
2.5 x 103
N
5.43 x 102
N
N
N
2.0 x 105
2.3 x 104
N
N
N
N
N
N - Not Available
83
-------
4.2.4 Level II Analyses
Level II tests were conducted at three of the diesel engine sites
previously tested (sites 309, 312 and 313). These were identified as sites
309-2, 312-2 and 313-2. The principal sampling system was the SASS train.
The controlled condensation system (CCS) was used to sample for S03 emissions.
The following SASS train organic samples were composited for analysis: probe
rinse, module rinse, filter extract, XAD-2 resin extract. The condensate
extract was not composited. Standard Level I analyses were repeated: TCO,
GRAY, IR, and LC (followed by GRAV and IR). Level II analysis for the
organic and CCS train samples are described below.
Level II Organic Analysis--
Initially all samples listed in Table 27 were screened using a packed
Dexil 300 column, (column conditions for Dexil 300 are given in Table 28).
With the exception of the blanks, the packed column results suggested that
alternative chromatography procedures were required due to highly complex and
concentrated mixtures of organics in the samples.
Capillary column chromatography was chosen because previous work on
similar samples has shown that the Level I LC separation procedure causes
sample modification and losses which are in excess of Level II standards. The
LC procedure, however, is adequate for Level I studies, but Level II requires
significantly better quantitation. The column chosen was a glass OV-101 wall
coated open tube, 30 meters in length. The actual operating conditions for
the column are given in Table 28. All samples were analyzed using this
capillary column without additional preparation other than the addition of
an internal standard.
Prior to capillary column analysis, each sample was spiked with the
internal standard, chloronaphthalene, at a level approximating 20 yg/m3
emission from the source. Chloronaphthalene was chosen because it elutes at
approximately a mid-range in the chromatogram, is very stable, is not a
typical combustion product, and yields a unique mass spectrum due to its
chlorine isotope pattern.
84
-------
TABLE 27. LEVEL II SAMPLES ANALYZED FOR INTERNAL COMBUSTION SITES
Sample Code
Description
309-2-XRPF-MRPR
309-2-CD-LE
309-2-MCB
309-2-XRBPFB-MAB
312-2-XRPF-MRPR
312-2-CD-LE
312-2-MCB
312-XRBPFB-MAB
313-2-XRPF-MRFR
313-2-CD-LE
Combination of resin, particle filter,
module rinse, and probe rinse extracts
Condensate extract
Methylene chloride blank for condensate
extract
Combined blank extractions for resin,
particle filter, methylene chloride,
and acetone
Combination of resin, particle filter,
module rinse, and probe rinse extracts
Condensate extract
Methylene chloride blank for condensate
extract (used for both 312 and 313
sites)
Combined blank extractions for resin,
particle filter, methylene chloride,
and acetone (used for both 312 and
313 sites)
Combination of resin, particle filter,
module rinse, and probe rinse extracts
Condensate extract
85
-------
TABLE 28. LEVEL II ORGANIC ANALYSIS CONDITIONS
Chromatograph Conditions for OV-101 Capillary Column
Co-|umn: Glass OV-101 wall coated capillary, 30M
long by 0.01" id.
Injector: Operated in a split mode (50:1 split ratio)
at 290°C
Temperature Program: 50-270°C at 2°C/min after a three minute
delay
Flow Rate: 20 cm/sec Hcc/min) of Helium
Injection Size: 5 yl
Total Analysis Time: ^90 min
Chromatograph Conditions for Dexil 300 Packed Column (sample screening)
Column: Glass packed with 3% Dexil 300^on
Chromosorb W, 5' long by 2.1 mm id.
Injector: 300°C
Temperature Program: 50-3--°C at 4°C/min
Flow Rate: 30 cc/min of Helium
Injection Size: 1 yl
Total Analysis Time: ^80 min
Chromatograph Conditions for OV-17 Packed Solumn (LC Fraction Analysis)
Column: Glass packed with 3% OV-17 on
Chromosorb W, 5' long by 2.1 mm id.
Injector: 270°C
Temperature Program: 50-270°C at 4°C/min
Flow Rate: 30 cc/min of Helium
Injection Size: 1 yl
Total Analysis Time: %60 min
86
-------
The original samples were delivered with corresponding LC fractions.
Several of these LC fractions were analyzed both by electron impact (El) and
chemical ionization (CI) GC/MS using an OV-17 packed column (see Table 28 for
conditions). The results of all analyses are discussed in detail below.
In an attempt to determine the presence of heteroatom containing organics,
several LC fractions were analyzed by GC/MS using both El and CI modes of
ionization. Late eluting fractions (i.e. LC 4-7) which exhibited high TCO and
gravimetric numbers were chosen for analysis. Not all of the fractions were
available, but enough information was gained to support the conclusion that it
is not possible to do Level II analysis of samples fractionated in this way.
The purpose of analyzing the LC fractions was to identify compounds at low levels
in specific compound classes. Once an identification was made using an LC
fraction, that specific compound was searched for in the data obtained on the
original sample. This procedure was used to facilitate identification of
species at low levels in the rather concentrated samples. When no evidence of
the compound was found in the original sample, it was assumed to be a con-
taminant introduced as a part of the LC procedure. When a compound was
confirmed, it was quantitated and reported. As an example of the problems
encountered, LC fraction 6 of sample 309-2-XRPF-MRPR contained a rather high
concentration of fatty acid methyl esters. The fatty acid methyl esters con-
sisted of a homologues series starting with pentanoic acid methyl ester and
extending to pentacosanoic acid methyl ester with every carbon number in
between present. Given this information, the data collected from the original
sample, using the capillary column, was examined. No evidence of fatty acid
methyl esters could be found in the original sample; therefore, these com-
pounds were assumed to be contaminants introduced into the sample by handling
(fatty acid methyl esters are found in various hand cream formulations).
This Level II analysis procedure provides information only on the volatile
portion of the samples, up to about C3Q. Materials with high boiling points
would not be directly determined. Level II procedures for nonvolatile organics
are not well defined at the present time.
87
-------
Level II Analysis for Sulfur Species--
The Goksoyr-Ross controlled condensation system was used for Level II
sampling for sulfur species. Identification and quantisation of these species
was accomplished by the following analysis. Aerosol H2S04, a form typically
found in combustion gases, was collected in the controlled condensation coil.
The coil was completely rinsed with deionized water. The H2S04 concentration
in the collected rinse was determined by a bromophenol blue indicated acid-
base titration. Sulfur dioxide was collected in the H202 impinger. A reaction
between S02 and H202 formed H2S04 which was quantitatively determined by the
Level I turbidimetric sulfate analysis. Sulfates were collected by the filter
and/or adhered to the inside of the probe. Sulfates present in the filter
washings and probe rinses were also quantitatively determined by the Level I
turbidimetric sulfate analysis.
4.2.5 Test Results
Field Measurements and Emissions of Criteria Pollutants--
The operating load, fuel type, and fuel feed rates for the internal com-
bustion sites tested are presented in Table 29. Eleven of the fourteen sites
were tested under base load conditions, and the remaining three at slightly
derated conditions.
Oxygen concentration data and data on particulate and SO emissions and
A
Bachrach smoke readings for the tests conducted are presented in Table 30.
Gaseous hydrocarbon (C-j-Cg) measurements were also made in the field but will
be reported later along with emissions data for volatile (C7-C,g) and non-
volatile (>C16) organics. As discussed previously in Section 4.1, the existing
data base for NOX and CO emissions from internal combustion sources is adequate.
Additional NO and CO measurements were therefore unnecessary. The SO emis-
A
sions data presented were computed from the fuel sulfur content and not based
on field measurements.
Particulate emissions determined by weighing filters generally correlate
well with Bachrach smoke readings, i.e., higher particulate emissions normally
correspond to higher smoke numbers. Also, it may be noted that particulate
emissions from distillate oil engines are much higher than particulate emissions
from distillate oil-fueled gas turbines. The calculated SO emissions are
A
88
-------
TABLE 29. OPERATING LOAD AND FUEL FEED RATES
OF INTERNAL COMBUSTION SOURCES TESTED
oo
Combustion Site
Source Type No.
Gas Turbine #110
Distillate Oil #111
Turbine
#112
#306
#307
#308
Distillate Oil #309
Reciprocating
Engine #310
#311
#312
#313
#309-2
#312-2
#313-2
Operating
Load
19.5 MW
18.0 MM
22.5 MW
14.5 MW
14.5 MW
20.2 MW
2.5 MW
2.5 MW
2.5 MW
2.5 MW
2.5 MW
2.5 MW
2.5 MW
2.5 MW
% Base
Load
94.7%
87.4%
80.4%
100 %
100 %
100 %
100 %
100 %
100 %
100 %
100 %
100 %
100 %
100 %
Fuel Used
Natural Gas
JP-5
JP-5
JP-5
JP-5
JP-5
No. 2 Diesel
No. 2 Diesel
No. 2 Diesel
No. 2 Diesel
No. 2 Diesel
No. 2 Diesel
No. 2 Diesel
No. 2 Diesel
Fuel Rate
7,100 Nm3/hr
7.50 m3/hr
8.18 m3/hr
5.49 m3/hr
5.49 m3/hr
7.77 m3/hr
0.70 m3/hr
0.70 m3/hr
0.70 m3/hr
1.02 m3/hr
1.02 m3/hr
0.70 m3/hr
1.02 m3/hr
1.02 m3/hr
Energy
Input
294 GJ/hr
278 GJ/hr
303 GJ/hr
204 GJ/hr
204 GJ/hr
288 GJ/hr
26.2 GJ/hr
26.2 GJ/hr
26.2 GJ/hr
39.9 GJ/hr
39.9 GJ/hr
26.2 GJ/hr
39.9 GH/hr
39.9 GJ/hr
-------
TABLE 30. PARTICULATE AND SOX EMISSIONS FROM
INTERNAL COMBUSTION SOURCES TESTED
UD
O
Combustion
Source Type
Gas Turbine
Distillate Oil
Turbine
Distillate Oil
Reciprocating
Engine
Site
No.
#110
#111
#112
#306
#307
#308
#309
#310
#311
#312
#313
#309-2
#312-2
#313-2
°2
5T
18.50
19.40
17.50
14.97
13.45
16.48
11.11
13.70
15.82
11.30
12.88
14.0
12.3
12.4
Parti cul ate
mg/m
ND
6.71
2.91
2.46
3.85
4.37
21.02
29.41
33.15
12.44
15.71
14.72
14.87
19.17
Emissions
mg/J
ND
21,4
4.2
2.1
2.6
4.9
11.0
20.8
33.0
6.6
10.0
10.8
8.8
11.5
S0x
ppm
ND
3.4
7.9
<1.9
<2.3
<1.4
60
81
58
43
44
43
67
61
Emissions
mg/J
ND
28.5
30.6
< 4.2
< 4.2
< 4.2
83.1
153
153
61.2
74.3
83.3
106
97.0
Bachrach
Smoke No.
0
3.5
3.0
3.0
4.0
5.0
6.5
7.0
6.5
ND
6.0
6.0
5.0
5.0
ND - Not Determined.
-------
lower than those seen in the stacks of utility boilers, due to both the low
sulfur content of the types of fuel used and the large amount of excess air
normally present in the combustion gases or turbines and reciprocating
engines.
The data reduction procedure for converting emission concentrations
(ppmv or mg/m ) to emission factors (mg/J) is based on calculations of the
combustion of fuel with air, as described in detail in Appendix C.
Inorganic Analysis Results--
The inorganic analysis data, generated using the analytical procedures
described in Section 4.2.3, are contained in Appendix D in 15 tables. Tables
D-l and D-2 contain the results from the gas turbine site (Site 110). Tables
D-3 to D-9 present results from the distillate oil turbine sites (Sites 111,
112, 306, 307 and 308). Tables D-10 to D-15 present results from the
distillate oil reciprocating engine sites (Sites 309, 310, 311, 312, and 313).
These tabulated results are presented for each section of the SASS train and
also are summed to provide a total value. Analytical data for the starting
fuels are also shown in these tables (except for Site 110). Mass emissions,
3
in mg/m , for each element reported, were calculated based on both the starting
fuel analysis (assuming that all of the element exited with the flue gas) and
the total catch determined in the SASS samples. Calculated mass emissions were
computed using the formula presented in the discussion of analytical detection
limits (Section 4.2.3).
A summary of the data from the specific inorganic analyses is given in
Table 31. Mercury, arsenic, and antimony emissions were all quite low. From
all three source types, these elements were found to be collected primarily
in the XAD-2 resin. Chloride and fluoride were found almost exclusively in
the XAD-2 resin and composite (acid XAD-2 module rinse plus XAD-2 module
condensate plus peroxide impinger) samples.
The SSMS analysis found the major elements present in all sites to be Al ,
B, Ba, Ca, Cu, Fe, K, Mg, Na, Ni, P, Pb, S, Si, and Zn. In addition, Mn levels
were found to be at least a factor of twenty higher for those sites (111, 306,
and 307) using an organic manganese fuel additive. The above elements were
91
-------
TABLE 31. SUMMARY OF RESULTS FROM SPECIFIC INORGANIC ANALYSES
Combustion
Source Type
Gas Turbine
Distillate Oil
Turbine
Distillate Oil
Reciprocating
Engine
Site
No.
no
in
112
306
307
308
309
310
311
312
313
Hg
0.0091
0.00018
0.0014
<0. 00074
0.0016
<0. 00033
0.00016
0.00077
<0. 00091
0.00003
-------
TABLE 32. LEVEL II CONTROLLED CONDENSATION TRAIN ANALYTICAL RESULTS
Sampl e
Number
309-2-GC
309-2-GI
309-2-GP/GF
312-2-GC
312-2-GI
312-2-GP/GF
313-2-GC
313-2-GI
313-2-GP/GF
Sample Type
Coil rinse
H202 impinger
Probe rinse and filter wash
Coil rinse
H202 impinger
Probe rinse and filter wash
Coil rinse
H?0? impinger
Probe rinse and filter wash
H2S04 S02 S04
mg/m3 mg/m3 mg/m3
ND * *
* 38.96 *
* * 1.56
1.38 * *
* 88.64 *
* * 1.58
1.36 * *
* 81.20 *
* * 1.74
ND indicates not detected
*The sulfur species indicated is not expected to be trapped in this part of
the sampling train. Samples collected are therefore not analyzed for the
specific sulfur species.
chromotograph is about 1000 yg hydrocarbon/m , whereas the laboratory gas
chromatograph can detect 1 yg/m3. This is the principal reason for the
apparent absence of the lighter materials, e.g., C^, Cg and Cg.
The nonvolatile organic content of the samples is also determined in the
laboratory. The procedure has been described briefly earlier in the text.
A summary of all results is presented in Table 33. There is a large
variation in the CrC6 concentrations found in testing oil fired turbines
(sites 111, 112, 306, 307 and 308). The diesel fuel fired engines (sites
309 through 313) varied in total Ci-C6 content from 10 mg/m3 to 30 mg/m3.
Fluctuations in the ethane content of these samples were the most notable.
93
-------
TABLE 33. VOLATILE AND NONVOLATILE ORGANIC EMISSIONS FROM INTERNAL COMBUSTION SYSTEMS
Combination Source Type
Site
Volatile Organic Gases
Analyzed in Field, vq/n?
Cl
C2
C3
C4
C5
ce
Volatile Organic Materials
Analyzed in Laboratory by
GC-TCO Procedure: ,iq/m3
C-, (B.P. 90-110°C)
C0 (B.P 110-140°C)
o
Cg (B.P. 140-160°C)
CIG (B.P 160-180°C)
C^ (B.P. 180-200°C)
C1? (B.P 200-22G°C)
C13 (C.P. 220-240UC)
C14 (B.P. 24G-260°C)
C15 (B.P. 260-28C°C)
C]6 (B.P. 280-300°C)
Nonvolatile Organic Matter
>C16 From Laboratory
Gravimetric Analysis,
Total Organics, mg/m
Gas
Turbine
110
BL*
BL
BL
BL
BL
BL
483
1202
444
727
23
SL
29
BL
BL
BL
310
3.22
Distillate Oil Turbine
111
BL
BL
BL
BL
BL
BL
32
100
137
927
BL
84
BL
BL
BL
BL
6800
8.08
112
BL
BL
BL
BL
BL
BL
29
147
200
613
21
152
56
BL
46
457
3710
5.43
306 307 308
BL BL BL
6762C 15130 2275
BL BL BL
BL BL BL
BL BL BL
BL BL BL
100 82 BL
52 27 BL
7 5 BL
17 14 99
89 12 BL
6 15 25
28 BL 12
210 BL 11
484 1 38
783 8 71
440 1400 1270
69.8 16.7 3.80
Distillate
309
1000
7765
3535
BL
BL
BL
24
251
685
1488
1945
2916
4919
3632
3103
2606
56180
89.0
309-2
500
700
700
BL
BL
BL
10
370
850
2410
2890
3230
3000
3580
2760
2290
55380
76.8
310
1570
10380
3065
BL
BL
BL
21"
328
633
1516
2292
2512
3827
3810
4192
3746
53880
92.0
Oil Reciprocating Engines
311
2570
5970
1140
BL
BL
BL
98
497
683
1228
1265
1438
2899
1933
1810
1941
43040
66.5
312
3285
17540
705
BL
BL
BL
585
251
565
1704
2159
2663
3970
2413
2389
2149
63590
104
312-2
800
1900
BL
BL
BL
BL
90
400
1100
1800
2120
2450
2330
2200
2250
1680
55040
71.5
313
4000
26015
745
BL
BL
BL
87
154
301
1034
682
1267
1742
1509
1771
937
46680
86.9
313-2
1100
1700
BL
BL
BL
BL
BL
560
1290
2120
2580
3120
2810
3100
3010
2350
66340
87.3
*BL Concentration of the species is below the limit of detection of the instrument; 1 ppm (=1000 ng/m ) per C-j -C^ and
0.001 ppm (=0.5 pg/m3) per Cy-C-jg.
-------
The concentration of materials boiling between 90°C and 300°C varied from
3
200 to 3000 yg/m in the samples from the gas- and oil-fired turbines. The
C6"C16 nydrocarbon content of samples from the diesel fuel-fired engines
ranged from about 10 to 20 mg/m . On the vaerage, the diesel burning engines
emitted approximately 15 times more C6-C16 materials than the gas- or oil-
fired turbines.
In all cases, the majority of volatile materials were collected in the
XAD-2 module, which is designed as the principal organic material collector.
This is readily seen from the tabulation of individual sample analyses pre-
sented in Table 34. (An explanation of the sample identification codes is
given in Figure 9.) Also because of the design, the second highest organic
concentration should be and is in the module rinse. Analyses of the Level II
samples (309-2, 312-2, 313-2) for volatile organics were performed on
composites (i.e., PR+PF+MR+XR and CD) rather than on the individual samples.
Therefore, these results are not presented in Table 31.
In a similar manner, the nonvolatile content of the samples from the
diesel engine sites 309 through 313 was about 25 times more than the nonvola-
tile content in the samples taken from the gas- or oil-fired turbine units.
The samples from the diesel engine unit contained between roughly 45 and
65 mg/m nonvolatile material, whereas the samples of gas- or oil-fired tur-
3
bines contained between 300 and 7000 yg/m .
Overall, the average total organic content of samples from the gas- or
o
oil-fired turbines was 6 mg/m and the average total organic content of samples
3
from diesel fuel fired engines was 88 mg/m .
As with the volatile organics, and for the same reason, the bulk of the
nonvolatile materials is in the XAD-2 module. The module rinses from the
diesel engine sties 312 and 313 also have a heavy quantity of nonvolatiles.
Gravimetric results for individual samples are presented in Table 35.
Organic Component Analysis -- The analysis of the material collected was
based on the data in the preceding paragraphs which showed that the only
organics of any potential interest were obtained from the XAD-2 module rinse
and XAD-2 resin and met the organic analysis criteria explained in Section 4.2.
95
-------
TABLE 34. RESULTS OF GC-TCO ANALYSIS FOR C,-C1C HYDROCARBONS IN LEVEL 1 SAMPLES
/ ID
en
Sample
Identification
Number
110-PR-O-KD-l
110-XR-Wet-S-GC
110-XR-Dry-S-GC
110-XM-S-KD-l
**
111-PR-O-KD
Reserve
111-XR-SKD
Reserve
m-XM-S-KD
Reserve
**
111-PF-S-KD
Reserve
112-OR-O-KD-l
112-XR-Wet-S-GC
112-XR-DRY-S-GC
**
112-XM-S-KD-l
C7
106
t
BL
377*
32
BL
29
BL
t
C8
153
t
1049
BL
61
37
118
t
t
C9
67
377
BL
BL
57
80
83
56
61
C10
(yg/m3 of
25
357
345
BL
912
15
21
394
198
Cll
Sampl
23
BL
BL
BL
BL
BL
21
BL
BL
C12
e Gas)
<1
BL
BL
BL
84
BL
9
113
30
C13
BL+
BL
29
BL
BL
BL
BL
56
BL
C14
BL
BL
BL
BL
BL
BL
BL
BL
BL
C15
BL
BL
BL
BL
BL
BL
BL
BL
46
C16
BL
BL
BL
BL
BL
BL
BL
244
213
Total
C7"C16
374
734
1394
377
BL
1146
132
2
281
863
548
29
Corrected for blanks
BL indicates below detection limit (0.5 yg/m )
Peaks, if any, obscured on shoulder of solvent peak
t
Response possibly caused by traces of methanol not removed during K-D concentration
** 3
Total less than 75 yg/m , so quantities in each range are not reported.
(Continued)
-------
TABLE 34. (CONTINUED)
Sampl e
Identification
Number
306-PR
306-XR
306-PF+
307-PR+
307-XR
307-PF+
308-PR+
308-MR+
308-XR
308-CDS+
308-PF+
309-PR+
309-MR
309-XR
309-CDS+
309-PF+
309-2+
C7 C8 C9 C10 C11 C12 C13 C14 C15 C16 Total
(yg/m3 of Sample Gas)* C7"C16
BL BL BL BL BL BL 23 BL 149 188 360
100 52 7 17 89 6 5 210 335 595 1416
34
BL
82 27 5 14 12 15 BLf <1 1 8 164
35
BL
BL <1 BL 99 BL 25 12 11 38 71 257
19
BL
30
24 <1 <1 <1 <1 26 14 38 150 234
0 251 685 1488 1945 2914 4913 3618 3065 2456 21335
8
5
21
Connected for blanks
(Continued)
Total less than 75 yg/m , so quantities in each range are not reported.
BL indicates below detection limit (0.5
-------
TABLE 34. (CONTINUED)
UD
00
Sample C7 CR
Identification
Number
310-PR+
310-MR
310-XR
310-CDS+
310-PF
311-PR+
311 -MR
311 -XR
311-CDS+
311 -PF+
312-PR+
312-MR
312-XR
312-CDS
312-PF
312-2
7 <1
207 323
BLf 5
BLf <1
98 497
386 BL
110 239
35 12
54 1
r r r r r
L9 10 11 12 13
(yg/m of Sample Gas)
<1 <1 <1 21 129
611 1486 2200 2426 3639
22 29 92 65 59
<1 <1 <1 <1 45
683 1228 1265 1438 2854
3 1 3 9 44
534 1652 2100 2614 3895
24 31 19 11 5
4 19 37 30 25
C14
164
3554
92
38
1895
139
2250
6
18
C15
462
3508
222
396
1424
393
1956
18
22
C16
611
3006
129
523
1418
417
1621
2
9
Total
C7~C16
30
1394
20960
3
715
7
992
12800
42
40
5
1495
16971
164
218
16
(Continued)
Corrected for blanks.
Total less than 75 yg/m , so quantities in each range are not reported.
a. 3
BL indicates below detection limit (-0.5 yg/m )
-------
TABLE 34. (CONTINUED)
Sample
Identi fication
Number
313-PR+
313-MR
313-XR
313-CDS
313-PF
313-2+
C7 C8
BLf BL
10 154
59 BL
18 <1
r r
L9 ho
(yg/m3 of
BL BL
300 1032
1 2
<1 <1
cn
Sampl e
6
672
3
<1
r r r
H2 H3 14
Gas)*
5 18 75
1261 1706 1433
1 1 1
<1 18 <1
C15
248
1457
14
52
C16 Total
C -C
L7 L16
36
287 640
646 8671
2 84
3 91
21
10
WD
Corrected for blanks.
+ 3
Total less than 75 yg/m , so quantities in each range are not reported.
t 3
BL indicates below detection limit (=0.5 yg/m ).
-------
o
o
xxx-xx-xx-xxx-xx-x
T ^r- >^ ^^S. ~^^^ --jj. SECOND LEVEL *
SITE IDENTIFICATION SAMPLE TYPE SAMPLE PREPARATION FIRST LEVEL ANALYSIS ANALYSIS THIRD LEVEL ANALYSIS
Consecutively numbered
by sampl ing team:
100-199, TRW West Coast
200-299, TRW East Coast
300-399, GCA
Numbers and corresponding
sample types are as
fol lows :
1-bulk liquid
(separated from a
slurry)
2-bulk liquid
(separated from a
slurry)
3-bulk liquid
4-bulk liquid
FF-liquid fuel feed
CD-condensate from
XAD-2 module
PR-solvent probe/
cyclone rinse
MR-solvent XAD-2
module rinse
HM-HN03 XAD-2 module
rinse
HI-H202 impinger
AI-APS impingers
XR-XAD-2 resin
PF-filter(s)
1C-1-3)J. cyclone
3C-3-10(-L cyclone
10C->10u cyclone
XM-XR extract plus MR
CH-HM plus CD plus HI
FC-PF plus 1C
CC-3C plus inc
CF-solid fuel feed (coal)
5-bulk sol ids
6-bulk solids
7-bulk solids (separated
from a slurry)
8-bulk solids (separated
from a slurry)
Numbers and corresponding
preparation steps are
as follows:
0-no preparation
LE-1 i qu i d- 1 i qu i d extraction
SE-Soxhlet extraction
A-acidified al iquot
B-basified aliquot
PB-Parr bomb combustion
HH-hot water extraction
AR-aqua regia extraction
Numbers and corresponding
procedures are as
fol lows :
Organic
0-no cone
required
GC-C7-C-|7 GC
KD-K-D Cone
Inorganic
SS-SSMS
AAS-Hq,As,Sb
S04-S04
N03-N03
CF-C1 ,F
Organic analyses on
cone samples will
be coded as
follows :
PM PP/MC -Fnw* DAMc
bPI-uL/no TOr rMnS
GI-Grav. ,IR
MS-LRMS
LC-LC separation
Resulting LC fractions
for grav./IR/LRMS
analyses will be
numbered in order,
1-8
Figure 9. EACCS Sample Control Numbers
-------
TABLE 35. GRAVIMETRIC RESULTS FOR INTERNAL COMBUSTION SITES
Sample
Identification
Number
110-XR-Wet-S-KD-2
110-XR-Dry-S-KD-2
110-PR-0-KD-2
110-XM-S-KD-2
lll-XR-S-KD-2
lll-PR-O-KD-2
lll-XM-S-KD-2
lll-PF-S-KD-2
112-XR-Wet-S-KD-2
112-XR-Dry-S-KD-2
112-PR-0-KD-2
112-XM-S-KD-2
306-PR
306-MR
306-XR
306=PF
306-CDS3
Residue
Weight
fag)
11.7
9.9
0.4
0.6
38.7
4.3
0.6
1.0
19.4
15.3
0.4
1.0
0.5
0.6
3.8
0.1
Aliquot
Factor
x 10
x 10
x 10
x 10
x 10
x 10
x 10
x 10
x 10
x 10
x 10
x 10
0.2 x 0.75
0.2 x 0.75
0.2 x 0.95
0.2 x 0.49 x 0.75
Total
Weight
(nig)
117.2 \
98.8 J
3.7
6.5
386.7
43.3
6.4
9.8
194.0 i
152.6 /
3.7
10.0
3.33
4.00
20.00
1.36
Blank
Corrected
Weight
(mg)
0
3.4
6.0
147.9
42.8
6.0
8.6
107.8
3.4
9.7
1.11
1.78
12.8
0.30
Net Sample
Nonvolatile
Content
(mg/m3)
0
0.1
0.2
4.9
1.4
0.2
0.3
3.3
0.1
0.3
0.03
0.05
0.35
0.01
*Not analyzed because of small condensate volume.
(Continued)
-------
TABLE 35. (CONTINUED)
o
r-o
Sample
Identification
Number
307-PR
307-MR
307-XR
307-PF
307-CDS
308-PR
308-MR
308-XR
308-PF
308-CDS
309-PR
309-MR
309-XR
309-PF
\
309-CDS
310-PR
310-MR
310-XR
310-PF
310- CDS
Residue
Weight
(mg)
0.5
0.7
8.2
0.1
0.5
0.7
1.0
5.5
0.1
0.5
0.7
74.6
208.2
0.0
1.5
0.7
77.3
199.2
1.1
1.0
Aliquot
Factor
0.2 x 0.75
0.2 x 0.75
0.2 x 0.95
0.2 x 0.50
0.2 x 0.75 x 0.67
0.2 x 0.75
0.2 x 0.75
0.2 x 0.95
0.2 x 0.51
0.2 x 0.75 x j^j-
0.2 x 0.75
0.2 x 0.75
0.2 x 0.95
0.2 x 0.47 x 0.75
0.2 x 0.75 x ~
6HO
0.2 x 0.75
0.2 x 0.75
0.2 x 0.95
0.2 x 0.53
0.2 x 0.75 x |f£
£DO
Total
Weight
(mg)
3.33
4.67
43.16
1.00
4.98
4.66
6.67
28.95
0.01
5.93
4.67
497.33
1,095.79
0.00
17.20
8.67
515.33
1,048.42
10.38
12.93
Blank
Corrected
Weight
(mg)
0
0
43.16
0
0
4.66
6.67
21.99
0.01
5.93
4.67
497.33
1,080.19
0.00
17.20
1.89
505.61
1,004.72
6.78
4.53
Net Sample
Nonvolati le
Content
(mg/m3)
0
0
1.40
0
0
0.15
0.22
0.71
0
0.19
0.16
17.47
37.95
0.00
0.60
0.07
17.88
35.52
0.25
0.16
( Continued)
-------
TABLE 35. (CONTINUED)
o
CO
Sample
Identification
Number
311-PR
311-MR
311-XR
311-PF
311-CDS
312-PR
312-MR
312-XR
312-PF
312-CDS
313-PR
313-MR
313-XR
313-PF
313-CDS
Residue
Weight
(mg)
2.9
72.2
125.8
10.2
2.1
1.0
131.6
196.5
0.6
2.3
2.0
49.7
78.6
0.6
4.1
Al iquot
Factor
0.2 x 1.00
0.2 x 0.75
0.2 x 0.95
0.2 x 0.50
0.2 x 1.0 x 0.5085
0.2 x 0.75
0.2 x 0.75
0.2 x 0.95
0.2 x 1.0 x 0.5028
0 2 x 0 75 x 40°
U . L. A U . / O A r/io
0.2 x 0.75
0.2 x 0.25
0.2 x 0.95
0.2 x 1.0 x 0.4471
0.2 x 0.75 x 0.6947
Total
Weight
(mg)
14.50
481.33
662.11
102.00
20.65
6.67
877.33
1,034.21
5.97
20.78
13.33
994.00
413.68
6.71
39.35
Blank
Corrected
Weight
(mg)
11.32
Ml .11
634.84
100.2
18.65
3.73
873.12
1 ,007.57
4.17
15.04
1.69
991.00
392.89
1.25
17.33
Net Sample
Nonvolatile
Content
(mg/m3)
0.39
16.56
21.98
3.47
0.64
0.12
29.17
33.66
0.14
0.50
0.06
32.94
13.06
0.04
0.58
-------
In the case of the gas turbines, only the oil-fueled sources had enough
material to warrant liquid chromatography fractionation. Of these samples,
sites 111 and 112 XAD-2 resin extracts had a contamination/blank problem and
it is not clear whether LC fractional was warranted by Level I criteria. In
any event, the level of material was at the borderline of criteria limits and
LC fractionation on those samples showed only species associated with the
blank could be identified. Sites 306-308 were treated in the normal manner.
Sites 309-313 were electrical generators powered by diesel engines.
These sites as shown in Table 33 produced substantial quantities of material,
almost all of which was collected in the XAD-2/module rinse sample. This large
and extraordinary complex mixture produced the opposite problem in that it
taxed the Level I procedures to the point where very little useful information
was obtained. This is explained in detail below.
Oil- and Gas-Fueled Turbines (Sites 110-112, 306-308) - Infrared Analysis -
Infrared spectra were obtained on the nonvolatile residues of both the original
organic sample concentrates and all liquid chromatography sample fractions.
A listing of classes of compounds identified in these spectra is provided in
Table 36. Of the compounds listed, benzoates, phthalates, and glycols are
contaminants commonly found in blanks, and they should not be considered as
emissions. These compounds are ubiquitous, e.g., phthalates are common plas-
ticizers, and avoiding contamination by them is extremely difficult. Silica
is from the partial decomposition of the chromatographic column. Because the
column packing is silica gel which is slightly soluble in alcohols and acids,
silica is generally found in fractions 6-8.
The infrared spectra of samples for Sites 306 through 308 were obtained
on a spectrometer which, although in conformance with instrument specifications
for Level I analysis, was insufficiently sensitive to produce a readable spec-
trum of the very small amounts of material available. Table 37 shows that
only very intense absorption bands were noticeable, such as those produced by
alkyl and aryl groups and OO and C-0 stretching.
Liquid Chromatographic Fractionation - Oil-Fueled Gas Turbine -- In the
case of Sites 110 through 112, the level of contamination in the resin was con-
sidered too great for a fractionation procedure to provide useful information.
104
-------
TABLE 36. CLASSES OF COMPOUNDS IDENTIFIED IN INFRARED SPECTRA OF SAMPLE CONCENTRATES AND LC FRACTIONS
Site Residue of Original Sample
LCI
LC2 LC3 LC4 LC5
LC6
LC7
LC8
O
tn
110 Esters: includes benzoates,
phthalates and vinyl ester;
amide; glycol; aldehyde;
chlorinated compound; other
benzene derivatives.
Ill Aliphatic hydrocarbons;
esters: includes benzoates
phthalates and vinyl ester;
amide; glycol; aldehyde;
chlorinated compound; other
benzene derivatives;
inorganic sulfate
Aliphatic
hydrocarbons
Esters: includes vinyl
ester; aldehyde/ketone;
aromatic nitro compound;
other organic nitrate;
silica
Esters: includes vinyl
ester; aldehyde/ketone;
glycol; aromatic nitro
compound; other organic
nitrate
Esters: includes vinyl
ester; aldehyde/ketone;
aromatic nitro compound;
other organic nitrate;
silica
Esters: includes vinyl
ester; aldehyde/ketone;
glycol; aromatic nitro
compound; other organic
nitrate
Esters (trace);
silica; water
Esters (trace);
silica; water
112 Esters: includes benzoates
and phthalates; glycol,
aldehyde; chlorinated
compound; other benzene
derivatives
Insufficient material was found in these samples to justify further analysis.
-------
TABLE 37. CLASSES OF COMPOUNDS IDENTIFIED IN INFRARED SPECTRA OF
LC FRACTIONS OF SAMPLES FROM OIL-FUELED GAS TURBINES
Site LCI
LC2
LC3
LC4
LC5
LC6
LC7
LC8
306
Species containing
alkyl, unsaturated
allphatlcs, aryl,
carbonyl and
C-O-X groups"1"
307
o
cr>
Species containing
alkyl and C-O-X
groups - all
aliphatic
308 Aliphatics Species containing
alkyl, aryl and
C-O-X groups
Species containing
alkyl , aryl and
C-O-X groups
Species containing
alkyl , aryl ,
carbonyl and C-O-X
groups
Species containing
al kyl , aryl ,
carbonyl and C-O-X
groups
Species containing
alkyl , aryl ,
carbonyl , aliphatic
C-O-X and unsatu-
rated aliphatic
groups
Species containing
alkyl , aryl ,
unsaturated ali-
phatics, carbonyl
and C-O-X groups
Species
containing
alkyl and
C-O-X groups
- all
aliphatic
Insufficient material was found in these samples to justify further analysis
^X group in C-O-X linkages was not identified in any sample
-------
Liquid chromatographic separations were performdd on the mixed XAD-2 resin
extract and the module rinse samples from the oil-fired units at Sites 306, 307
and 308. The analysis results, in Table 38, showed the predominant amount of
material to be in the nonvolatile portion. There is no apparent trend among
these samples as to what fraction contains the most material, although fractions
1 and 6 are reasonably heavy in all three cases. Fraction 1 contains almost
all aliphatic and some aromatic hydrocarbons; fraction 6 contains such polar
species as esters and other carboxylic acid derivatives, aldehydes and ketones,
phenolics and amines.
Organic Analysis of Diesel Engine Sites 309-313 -- The data tabulated in
Table 33 show that substantial quantities of material were collected in the
XAD-2 module rinse samples and, as a result, liquid chromotographic (LC) separ-
ation was required for all sites. In addition, the nonvolatile organic material
averaged 1.6 g per site which is 30-160 times greater than that which was
routinely found in previous sites. As a result, the aliquoting procedure
yielded samples that were far too concentrated for the LC columns that were
used. This caused the columns to overload and no meaningful separation was
effected. A second set of columns was run with less material, but the large
amount of hydrocarbon oils present overloaded the early stages (Fractions 1-3)
of the columns, and again prevented any meaningful interpretation of the data.
This smearing of components throughout the LC fractions is illustrated in
Table 39 which tabulates the infrared assignments for these columns and where
it is clearly evident that the same components are present in all fractions.
More detailed assignments could not be made due to the extraordinary complexity
of the mixture and the lack of resolution on the instrument that was used.
Similar results were obtained from the Level II tests at Sites 309, 312,
and 313. Table 38 presents a summary of LC, TCO, and GRAV results which may
be compared with results from oil-fired turbine Sites 306-308. Large amounts
of hydrocarbon oils again caused smearing in the LC separations. IR inter-
pretations of LC fractions from Sites 309-2, 312-2, and 313-2 are presented in
Table 39.
107
-------
TABLE 38. LC/TCO/GRAV SUMMARY FOR SASS SAMPLES FROM SITES 306-313-2
CD
CX)
Site-
Sample
306-
XR+MR
307-
XR+MR
308-
XR+MR
309-2-
XR+PF+MR+PR
312-2-
XR+PF+MR+PR
313-2-
XR+PF+MR+PR
TCO, mg
GRAV, mg
Total , mg/m
TCO, mg
GRAV, mg
Total , mg/m
TCO, mg
GRAV, mg
Total , mg/m
TCO, mg
GRAV, mg
Total , mg/m
TCO, mg
GRAV, mg
Total , mg/m
TCO, mg
GRAV, mg
3
Total , mg/m
LCI
*
0.7
+
BL
0.5
0.016
BL
1.7
0.055
611
892
48.1
220
954
38.4
190
1395
50.9
LC2
*
0.3
+
BL
0.3
0.0097
BL
0.6
0.0194
1.62
57.2
1.88
2.42
34.1
1.19
4.4
153
5.05
LC3
*
0.1
+
BL
0.3
0.0097
BL
0.4
0.0129
0.10
77.8
2.52
BL
71.3
2.33
0.53
48.2
1.57
LC4
*
0.5
+
BL
0.3
0.0097
BL
0.5
0.0162-
10.8
94.7
3.38
0.57
83.8
2.76
BL
33.6
1.08
LC5
*
0.4
+
BL
BL
BL
BL
0.6
0.0194
0.07
46.5
1.49
BL
48
1.57
BL
59.8
1.92
LC6
*
2.8
+
BL
1.1
0.036
BL
2.6
0.0841
BL
16.8
5.37
0.48
127
4.17
1.4
102
3.32
LC7
*
BL
+
BL
0.9
0.029
BL
4.1
0.133
BL
534
17.0
BL
16.7
0.55
BL
31.6
1.02
LC8
*
*
+
*
*
*
*
1.0
0.034
t
+
t
t
t
t
t
t
t
Total
.
4.8
+
BL
3.4
0.11
BL
11.5
0.374
624
1719
79.7
223
1335
51
196
1823
64.9
Data not required.
Total not meaningful because of lack of TCO data.
t
Fraction 8 is no longer part of the Level I scheme.
-------
TABLE 39. CLASSES OF COMPOUNDS IDENTIFIED IN INFRARED SPECTRA OF LC FRACTIONS
OF SAMPLES FROM DISTILLATE OIL RECIPROCATING ENGINES
Site
309
309-2
310
311
312
312-2
313
313-2
LCI
Species containing
alkyl , aryl and
C-O-X groups'1;
carboxylic acid
Species containing
hydrocarbons and
ethers
Only al iphatic
species
Species containing
alkyl and aryl
groups
Species containing
alkyl and aryl
groups
Species containing
hydrocarbons
Species containing
al kyl , aryl and
C-O-X groups
Species containing
hydrocarbons
LC2
Species containing
al kyl , carbonyl ,
and C-O-X groups
Species containing
hydrocarbons and
possibly ethers
Only al iphatic
species
Species containing
al kyl , aryl and
C-O-X groups
Species containing
al kyl , aryl and
C-O-X groups
Species containing
hydrocarbons,
unsaturaled or
aryl esters,
ketones
Only aliphatic
species
Species containing
hydrocarbons ,
esters, ketones
LC3
Species containing
al kyl , al kenyl ,
aryl , carbonyl and
C-O-X groups
Species containing
hydrocarbons and
possibly nitro
compounds
Only al iphatic
species
Species containing
al kyl , aryl and
C-O-X groups
Species containing
alkyl , aryl and
C-O-X groups
Species containing
hydrocarbons ,
unsaturated or
aryl esters
Species containing
al kyl , al kenyl
aryl , carbonyl and
C-O-X groups
Species containing
hydrocarbons,
esters, ketones
LC4
Species containing
alkyl and C-O-X
groups - all
aliphatic
Species containing
hydrocarbons ,
ketones, esters,
Species containing
alkyl , arly and
C-O-X groups
Species containing
al kyl , gl kenyl ,
aryl and C-O-X
groups
Only al iphatic
species
Species containing
hydrocarbons ,
saturated ketones
Only saturated
and unsaturated
aliphatic species
Species containing
hydrocarbons
LC5
Species containing
alkyl , al kenyl
and C-O-X groups -
all aliphatic
Species containing
saturated and
unsaturated
ketones
Species containing
al kyl , aryl and
C-O-X groups
Species containing
alkyl , al kenyl ,
arly and C-O-X
groups
Species containing
alkyl , al kenyl ,
aryl and C-O-X
groups
Species containing
unsaturated or
aryl esters,
ketones
Only aliphatic
species
Species containing
saturated ketones,
aryl o"r unsatu-
rated esters
LC6
Species containing
al kyl , arly,
carbonyl and C-O-X
groups
Species containing
aldehydes, ketones,
esters
Species containing
al kyl , aryl and
C-O-X groups
Species containing
alkyl , al kenyl ,
aryl , carbonyl and
C-O-X groups
Species containing
al kyl , al kenyl ,
aryl and C-O-X
groups
Species containing
esters, aldehydes,
ketones
Species containing
al kyl , al kenyl ,
aryl and C-O-X
groups
Species containing
esters, ketones
LC7
Only al iphatic
species
Species containing
hydrocarbons,
esters, ketones
Species containing
alkyl , aryl and
C-O-X groups
Species containing
alkyl , aryl and
C-O-X groups
Species containing
al kyl , aryl and
C-O-X groups
Species containing
unsaturated or
aryl esters,
ketones
Species containing
alkyl and aryl
groups
Species containing
esters, ketones,
amides, amines
unsaturated or
aryl ketones
LC8
Species containing
alkyl and C-O-X
groups - al 1
al iphatic
ir
Species containing
al kyl , aryl and
C-O-X groups
Species containing
alkyl , aryl and
C-O-X groups
Only aliphatic
species
*
No data
*
aX group in C-O-X linkages was not identified in any sample.
-------
In order to further identify potential components of these mixtures, a
selected set of liquid chromatographic fractions were analyzed by low resolu-
tion mass spectroscopy. These results are shown in Table 40. Again the
specific assignments could not be made due to the complexity of the mixtures.
However, it is clear that the major portion of the sample consists of hydro-
carbon oils and aromatic compounds. Previous experience indicates that the
presence of dioctyl phthalate and fatty acid esters are the result of sample
contamination. Dioctyl phthalate is a common plasticizer, and fatty acid
esters are ingredients in many hand lotions. Thus, contamination by these
compounds is difficult to prevent. Because of the complexity of the samples
and the contamination problems, assignments should be considered tentative.
Gas Chromotography/Mass Spectroscopy (GC/MS) for Polycyclic Organic
Matter (POM) -- All samples obtained at the oil and gas-fueled gas turbine fad
lities and which were subjected to TCO and gravimetrics analysis were analyzed
by GC/MS for POM compounds. Gas chromatography/mass spectroscopy on these
samples was not possible by the normal procedure used on this program because
the hydrocarbon oils masked the POM spectra to the point of preventing
unequivocal identification and quantification. As a result, a POM clean-up
procedure, as developed by Battelle-Columbus, was used to remove the oils.
This consisted of separating 10 percent of the sample on the standard Level I
liquid chromotography column and combining fractions 2, 3, and 4. This
resulted in substantial improvement in the samples, but column smearing of
the hydrocarbon oils still compromised the results shown in Table 41. How-
ever, because all components that were found were several orders of magnitude
below the level of concern (see Section 4.3.4), these data are considered
adequate.
Level II Organic Analysis by GC/MS -- Table 41 also presents summary
results at the Level II GC/MS analyses. Detailed results are given in
Appendix Tables D-16 to D-21. The samples consist mainly of saturated and
unsaturated hydrocarbons and aromatics. Some POM compounds were detected but
only at very low levels. The majority of organic material was found in the
sample composite which included the XAD-2 resin extract. Only low levels of
organic material were found in the condensate extract; and the blanks were
unusually clean. The majority of aromatics found were substituted
110
-------
TABLE 40. LOW RESOLUTION MASS SPECTROSCOPY RESULTS FOR DIESEL ENGINE SITES
Sample Hydrocarbon
Identification Oil Aromatics
Number
309-XM-LC1 +*
310-XM-LC1 + +
310-XM-LC6 + +
310-XM-LC7 tr
311-XM-LC1 + +
311-XM-LC3 + +
311-XM-IC4 +
312-XM-LC1 +
312-XM-LC3 + +
312-XM-LC4 + +
312-XM-LC6 + +
313-XM-LC1 +
Dioctyl Fatty Acid
Phthalate Esters Other
tr + Di-tert-butyl phenol (possible)
+ + Anisole (possible)
+
tr
+ Di-tert-butyl phenol (possible)
+ +
+ Nonyl phenol (possible)
+ Di-tert-butyl phenol (possible)
+
+ Trimethyl naphthalene (possible)
+ Anisole (possible)
+ Di-tert-butyl phenol (possible)
* + means the particular species was present.
^ possible means the compound named is most probably the species present.
-------
TABLE 41. POM EMISSIONS FROM DIESEL ENGINE SITES 309-313* (yg/m3)
Compound 309
Naphthalene 16
Methylnaphthalenes BL
C2-substituted naphthalenes 30
(^-substituted naphthalenes 8
C,-substituted naphthalenes BL
(^-substituted naphthalenes BL
Biphenyl 2
Methyl biphenyls BL
(^-substituted biphenyls BL
Dibenzothiophene 5
Methyldibenzothiophenes BL
Phenanthrene 8
Methyl phenanthrenes 20
Dimethyl phenanthrenes 4
Trimethylphencenthrenes BL
Ethyl fluorene BL
Pyrene BL
Detection limit, tjg/m 0.08
309-2
170
461
506
631
462
120
T+
BL
BL
BL
BL
94
86
BL
BL
24
T
0.05
310
18
22
12
4
BL
BL
6
BL
BL
2
0.8
3
8
0.8
2
BL
BL
0.08
311
36
BL
64
BL
BL
BL
10
BL
BL
BL
BL
BL
60
24
BL
BL
BL
0.08
312
BL
BL
BL
BL
BL
BL
BL
BL
BL
BL
BL
BL
77
46
12
BL
BL
0.08
312-2
58
570
798
266
BL
BL
BL
BL
BL
BL
BL
38
22
BL
BL
BL
BL
0.05
313
3
BL
BL
BL
BL
BL
15
BL
BL
BL
BL
BL
150
58
15
BL
BL
0.1
313-2
220
590
1090
672
28
BL
37
150
BL
BL
BL
92
T
BL
BL
BL
T
0.05
POMs were found only in XAD-2/XAO-2 module rinse samples
+T indicates trace, 0.5-1.0 pg/m
-------
naphthalenes, and the hydrocarbons were for the most part saturated branched
and straight chain molecules.
Some oxygenated organics were found which can be classified as aromatics -
aldehydes and esters, including phthalates. The phthalates are ubiquitous;
their source is indeterminate, and it is questionable whether they are actually
products of combustion. Oxygenates found in the original samples were also
found in the LC fractions. However, no other heteroatomic organic compounds
were found.
As an example of the complexity of the capillary GC/MS data. Figure 10
shows the reconstructed gas chromatogram for sample 309-2-XRPF-MRPR. Figure 11
is a mass chromatogram of the same sample for M/e = 57 which shows the presence
of nonaromatic (i.e., saturated and unsaturated) hydrocarbons. This type of
data presentation illustrates at a glance the amount of hydrocarbon compounds
present in the sample. Comparing Figures 10 and 11 shows that the bulk of
compounds detected (Figure 10) are saturated straight chain and branched
hydrocarbons (Figure 11).
The detection limit for these Level II analyses has been established at
0.05 yg/m based on the analysis of standards. This detection limit is based
on instrument performance only and does not consider sample losses during the
preparation phase or the efficiency of the sampling device.
It was noted earlier that Level II analysis techniques were not suffi-
ciently well defined for analyzing the nonvolatile residues of the Level II
samples. However, an indirect measure of the composition of these higher
boiling organic organic compounds can be made by assuming that high molecular
weight nonvolatile species would be represented by lower molecular weight
homologues. Based on this assumption, the nonvolatile portion of the sample
should consist of hydrocarbon tars, primarily straight and branched chain
compounds with some aromatic species at low concentrations.
113
-------
100.6
RIC
BIC DATA: 3092XRCON1 81
88/30/78 14:49:00 CALI: DC0831 «1
SAMPLE: 5UL UITH INTERNAL STANDARD CONCENTRATED 10 : 1
RANGE.- f. 1,3900 LAflLl: N 0, 4.0 QUAN: A 8. 1.0 BASE: U 20, 3
SCANS 1 TO 320»
i
1
I
j
i
i
j.
i, i ;!
,1
1 '
j
If
T !
lili
, i J
* .. , 1
1
M
i
ii
i J
:'! |
1'
(
\
i
!|
S'
t;
'' <
1
|i
Jl
ip
!
j
t
I
]
ii
j
ii
ii
!
i
i
;
| j
i' '
i\ i
i
!
14 !'
\J
\
i
i ]
i
I
I
j
ill
Ii \
v
te
i
5A*
i
i
i:
^£mi'\ ' ," lV rkr^'ftM'r^
Af'lif^v'^t'l,^ '
1495M.
500
16:40
33:20
1500
50:00
2000
66:40
2500
83:20
3000
160:00
SCAN
TIIC
Figure 10. Reconstructed Gas Chromatogram of Sample 309-2-XRPF-MRPR
-------
CHROMATOGBAH MAP
08/38/78 14:49:00
SAMPLE: 5UL UITH INTERNAL STANDARD CONCENTRATED 10 : 1
DATA: 3092XBCON1 «1
CALI: DC0831 »1
SCANS 1 TO 3200
HASS 57 TO 57
J
&
1
j
k
r
|
L j
51
16
hi
1 T"
90
:40
i
[
j
1
\
|J
|i>
1 1
\
\
10
33
!
^
i
90
:20
;
i
\
ii
!j
'
.[
1
V
i
!
!
1
I
V
15
50
,
t!
M
:00
i
i
!
i
1
|
?
t
'i j
|
i
1
i
i i
bi
''iyJ
j
l
1
i .
\J '''^,
l
20
66
il:
1
i
00
:40
:
1 1
U-
1
25
83
|
i ; i i 1 1
W 3009
:20 100:00
INTEN
10030.
i.
MASS
J/
SCAN
TIME
Figure 11. Mass Chromatogram of M/e = 57 Showing Non-Aromatic Nature of Sample 309-2-XRPF-MRPR
-------
4.3 ANALYSIS OF TEST AND DATA EVALUATION RESULTS
4.3.1 Emissions of Criteria Pollutants
The particulate and total organics emissions data collected in this
sampling and analysis program for internal combustion sources are presented in
Table 42. In addition, the SO emissions, calculated from the weight percent
X
of sulfur in the fuel, are also presented.
As shown in Table 42, data variability for particulate, SO , and total
A
organics emissions is large for the distillate oil-fueled gas turbines tested.
By comparing these emissions data with the existing emissions data presented
in Table 12, it may be noted that the SO emissions data are within the range
/\
of existing emissions data, whereas the particulate data show lower emissions
and the total organics data show higher emissions than the existing data. The
larger variability for particulate and SO emissions are the result of inherent
/\
variability in the ash and sulfur content of the JP-5 fuel used, and the five
data points acquired provide a valuable addition to the existing data base.
It may also be recalled that for three of the five distillate oil-fueled
gas turbines tested (Site Nos. Ill, 306, and 307), an organic manganese
additive was used to reduce visible smoke emissions. Hence the particulate
emissions were lower than those normally found. The organic emissions, on the
other hand, were higher than those in the existing data base for two reasons.
First, some of the distillate oil-fueled gas turbines tested were not
functioning properly, as indicated by the high C2 emissions for Site Nos. 306
(C2 = 50.5 ppmv) and 307 (C2 - 11.3 ppmv). Second, the total hydrocarbon
emissions determined by previous investigators were obtained using gas
chromatography with flame ionization detector, and some of the heavier hydro-
carbons were probably condensed in the sampling line and not measured*. The
slight malfunctioning of some distillate oil-fueled gas turbines, however, may
represent the real situation for the electricity generation turbine population.
*
The total hydrocarbons normally reported may be equivalent to the C,-CC hydro-
carbons measured by TRW/GCA in the field. ' b
116
-------
TABLE 42. SUMMARY OF EMISSION FACTOR DATA FOR PARTICIPATE, SOX AND
TOTAL ORGANICS FROM INTERNAL COMBUSTION SOURCES TESTED
Combustion
Source Type
Gas-Fueled
Gas Turbine
Distillate
Oil-Fueled
Gas Turbine
Distillate Oil
Reciprocating
Engine
Site
No.
#110
#111
#112
#306
#307
#308
Mean x
s(x)
ts(x)/x
#309
#310
#311
#312
#313
#309-2
#312-2
#313-2
Mean x
s(x)
ts(x)/x
Emission
Particulate
ND
21.4
4.2
2.1
2.6
4.9
7.0
3.6
1.4298
11.0
20.8 1
33.0 1
6.6
10.0
10.8
8.8 1
11.5
14.1 1
3.1
0.5176
Factor,
SO
x
ND
28.5
30.6
<4.2
<4.2
<4.2
14.3
6.2
1.2038
83.1
53.1
53.1
61 .2
74.3
83.3
06.3
97.0
01.4
12.2
0.2856
ng/J
Total
Organics
11.1
27.9
9.0
57.8
2.8
7.5
21.0
10.2
1.3425
47.7
65.9
74.1
54.6
54.4
58.2
45.8
54.4
56.9
3.3
0.1366
ND - Not determined
s(x) = Standard deviation of the mean
ts(x)/x = Variability
117
-------
The higher total organics emissions data should therefore be included in the
usable data base. For electricity generation gas-fueled gas turbines, the one
data point on total organics emissions is well within the range of existing
emissions data for total hydrocarbons presented in Table 11.
For electricity generation distillate oil reciprocating engines, existing
data on particulate and SO emissions are not available. Variability for the
A
particulate emissions data collected in this program is 0.52 and is considered
acceptable. Variability for the SOV emissions data is 0.26 and is considered
j\
acceptable. Variability for the total organics emissions is also less than 0.7.
In fact, all the organic emissions data collected are well within the range of
existing organic emissions data presented in Table 20.
In Table 43, the emission factors for gas and distillate oil-fueled gas
turbines calculated from data collected in this program and the emission
factors derived from existing data are compared with the EPA AP-42 emission
factors (Reference 23). For industrial gas-fueled gas turbines, the EPA
emission factors were all based on the Southwest Research Institute (SWRI)
data (References 11 and 16), whereas the emissions data for the McGowin and
Durkee reports (References 15 and 3) in addition to the SWRI data have been
used in the computation of the existing data emission factors. As noted in
Table 43, the EPA and the emission factors calculated from existing data are
almost identical for industrial gas-fueled gas turbines.
For industrial distillate oil-fueled gas turbines, the EPA and existing
data emission factors for NO are again almost identical, but the existing
s\
data emission factor for hydrocarbons is 79 percent lower and that for CO is
114 percent higher than the EPA emission factors. The existing data emission
factors for CO and hydrocarbons should be considered more reliable than the
EPA emission factors, because the existing data base for CO and hydrocarbon
emissions is adequate and the basis for the EPA emission factors is not well
documented.
For electricity generation gas-fueled gas turbines, the one data point
collected on emissions of total organics is in good agreement with the mean
emission factor for hydrocarbons based on existing data. Generally, there is
also good agreement between the EPA and the existing data emissions factors,
118
-------
TABLE 43. COMPARISON OF CRITERIA POLLUTANT EMISSIONS FACTORS FOR
GAS AND DISTILLATE OIL-FUELED GAS TURBINES
Combustion
Source Type
Industrial
Gas-Fueled
Gas Turbines
Industrial
Distillate
Oil -Fueled
Gas Turbines
Electricity
Generation
Gas-Fueled
Gas Turbines
Electricity
Generation
Distillate
Oil -Fueled
Gas Turbines
Emission Factor, ng/J
Data Source
Existing Data
EPA
Existing Data
EPA
Current Study
Existing Data
Combined
Existing Data &
Current Study
EPA
Current Study
Existing Data
Combined
Existing Data &
Current Study
EPA
NOX
130
123
207
208
ND
168
168
169
ND
311
311
208
HC
8.6
9.4
3.6
17.0
11.1
15.0
14.7
17.2
21.0
4.6
11.1
17.0
CO
48.8
49.1
101
47.1
ND
29.7
29.7
47.0
ND
20.1
20.1
47-1
Part
ND
ND
ND
15.3
ND
5.1
5.1
5.7
7.0
15.5
13.0
15.3
SO
X
ND
0.26
ND
430S
ND
4.4
4.4
0.26
14.3
41.0
33.1
430S
ND - No data
S - Weight percent of sulfur in fuel
119
-------
except in the case of SO emissions. The EPA emission factor for SOX was
calculated by assuming an average natural gas sulfur content of 4,600 g/10 m ,
and should be considered to be more representative than the S0x emission factor
calculated using two existing data points.
For electricity generation distillate oil-fueled gas turbines, the EPA
emission factors are identical to the EPA emission factors for industrial
distillate oil-fueled gas turbines. By comparison, emission factors from the
current study for hydrocarbons are higher, and for particulates and SOX are
lower than the corresponding emission factors based on existing data. The
lower particulate and SO emission factors obtained in this program are due
A
to the low ash and sulfur content of the JP-5 fuel used in the five distillate
oil-fueled gas turbines tested. Emission factors based on combined current
study and existing data are in reasonably good agreement with the EPA emission
factors for hydrocarbons and particulates. The SO emission factor based on
A
current study and existing data corresponds to an average sulfur content of
0.08 weight percent for the distillate oils used as turbine fuel. The existing
data NO emission factor is 50 percent higher than the EPA NOV emission factor,
A X
and the existing data CO emission factor is 57 percent lower than the EPA CO
emission factor. Again, the existing data emission factors for NO and CO
A
should be considered more reliable, because the existing data base for NO and
A
CO emissions is adequate and the quality of the data sources for the EPA
emission factors cannot be readily assessed.
In Table 44, the emission factors for distillate oil reciprocating engines
calculated from data collected in this program and the emission factors for
reciprocating engines derived from existing data are compared with the EPA AP-42
emission factors (Reference 23). For industrial gas engines, the EPA emission
factors were all based on the Southwest Research Institute (SWP.I) data (Refer-
ences 11 and 16) and the data reported in the Standard Support Document and
Environmental Impact Statement for Stationary Reciprocating Internal Combus-
tion Engines (Reference 6), whereas the emissions data from the McGowin report
(Reference 15) in addition to the above data sources have been used in the
computation of the existing data emission factors. The EPA and existing data
emission factors are almost identical, except in the case of CO emissions. The
120
-------
TABLE 44. COMPARISON OF CRITERIA POLLUTANT EMISSION FACTORS
FOR GAS AND DISTILLATE OIL ENGINES
Emission Factor, ng/J
Combustion
Source Type
Industrial
Gas Engines
Industrial
Distillate
Oil Engines
Electricity
Generation
Gas Engines
Electricity
Generation
Distillate
Oil Engines
Data
Source
Existing
EPA
Existing
Da-t-a
Uata
EPA
Existing
Data
EPA
Current Study
Existing
Data
Combined
Existing Data
and Current
Study
EPA
NOX
1550
1390
1390
1420
1550
1230
ND
1390
1390
1420
HC
528
573
51
115
528
17
56.9
51
52
115
CO
340
176
266
312
340
47
ND
266
266
312
Part
ND
ND
ND
102
ND
5.7
14.1
ND
14.1
102
S0x
ND
0.26
ND
430S
ND
0.26
101
ND
101
430S
ND - No data
S - Weight percent of sulfur in fuel
121
-------
primary reasons for the lower EPA CO emission factor were the exclusion of a
number of high CO emission data points reported in Reference 6 and the exclusion
of the CO emission data in the McGowin report. As no explanation was given
for the exclusion of these CO emission data points, the higher CO emission
factor based on a larger number of data points is considered to be more repre-
sentative of the emission characteristics of the total gas engine population.
In the current emissions assessment program, emissions from industrial and
electricity reciprocating engines are evaluated together, because of the con-
siderable over-lapping in size ranges for these two user sectors. The existing
data emission factors for industrial and electricity generation gas engines
are therefore identical. The EPA emission factors for industrial and electri-
city generation engines, however, are different. For electricity generation
gas engines, the EPA NO emission factor is slightly lower than the EPA NO
A A
emission factor for industrial gas engines and the existing data NO emission
X
factor for industrial/electricity generation gas engines. Comparison of the
EPA emission factors presented in Tables 43 and 44 also shows that for hydro-
carbon, CO and particulate emissions, EPA assumed identical emission factors
for the electricity generation gas turbine and gas engine categories. This
assumption is only reasonable when emissions data are not available, as in the
case of particulate emissions from gas engines, because the emission charac-
teristics for gas turbines and gas engines are quite different. For
industrial/electricity generation gas engines, the existing data emission
factors for NO hydrocarbons and CO are considered to be more reliable than
A
the corresponding EPA emission factors, especially because the existing
emissions data base for these pollutants is adequate and contains over 70 data
points. Particulate and SO emissions from gas engines are insignificant and
X
the EPA emission factors for these pollutants may be used.
For distillate oil reciprocating engines, emissions from the industrial
and electricity generation sources have been assumed to be identical by both
EPA and in the evaluation of existing data. Adequate NO , hydrocarbon, and
CO emissions data are available from the existing data base. The existing
data N0x and CO emission factors are about the same as the corresponding EPA
emission factors. As noted in Table 44, the hydrocarbon emission factor
122
-------
obtained from the field tests in the current program is almost identical to the
existing data hydrocarbon emission factor. Both the current study and existing
data hydrocarbon emission factors are approximately half of the EPA hydrocarbon
emission factor. For particulate and SOX emissions, usable existing data are
not available. The particulate emission factor, obtained from the eight field
tests in the current program, is only 14 percent of the EPA particulate emission
factor. The S0x emission factor of 101 ng/J from the current study corresponds
to a diesel fuel sulfur content of 0.24 percent. When there are differences in
emission factors, emission factors based on combined current study and existing
emissions data are considered to be more reliable, primarily because of the
unknown quality of the data base for the EPA emission factors.
The significance of the emissions of criteria pollutants from the indus-
trial and electricity generation internal combustion sources can be assessed
using the source severity concept. The source severity concept has been dis-
cussed in Section 4.1, and detailed methods for the calculation of source
severity factors are described in Appendix A. Basically, the source severity
factor is defined as the ratio of the calculated maximum ground level concen-
tration of the pollutant species to the level at which a potential environmental
hazard exists. Source severity factors below 0.05 are deemed insignificant.
Source severity factors for the criteria pollutants have been calculated
using emission factors based on combined current study and existing emissions
data. EPA emission factors were only used for particulate and SO emissions
A
from gas-fueled internal combustion sources. The calculated source severity
factors, as presented in Table 45, indicate that the major pollutant from
internal combustion turbines and reciprocating engines is nitrogen oxides.
Significant amounts of hydrocarbons are also produced, especially in the case
of reciprocating gas engines. For distillate oil reciprocating engines, source
severity factors for SO emissions are greater than 0.05, indicating that these
A
pollutants are of some concern and may require evaluation of control needs.
In general, emissions of criteria pollutants from reciprocating engines are
found to have greater potential environmental impact than emissions from tur-
bines. With the combination of current study and existing emissions data, the
data base for emissions of criteria pollutants from internal combustion sources
is now adequate, and there is no need for additional tests.
123
-------
TABLE 45. MEAN SOURCE SEVERITY FACTORS FOR CRITERIA POLLUTANTS
Gas Turbine
Pollutant
NO
X
HC
CO
Particulate
SO
Industrial
Gas
0.52
0.025
0.0007
0.097
<0.0001
Industrial
Distillate
Oil
0.82
0.010
0.0014
0.016
0.029
Elec.
Gen.
Gas
0.17
0.021
0.0003
0.0019
<0.0001
Elec. Gen.
Distillate
Oil
0.32
0.052
0.0002
0.0049
0.0089
Industrial
Gas
5.66
1.33
0.0040
0.0055
0.0002
Reciprocating Engine
Industrial
Distillate
Oil
5.09
0.13
0.0032
0.015
0.078
Elec.
Gen.
Gas
7.09
1.65
0.0051
0.0068
0.0002
Elec. Gen.
Distillate
Oil
6.35
0.16
0.0040
0.019
0.097
-------
4.3.2 Emissions of SOs, Participate Sulfate, and Fine Particulates
Data on the composition of SO from combustion sources indicate that from
A
90 to 100 percent of emitted S0x is sulfur dioxide. The remaining fraction of
SO emissions is sulfur trioxide and its derivatives. The main sulfur trioxide
A
derivative in effluent gases from combustion of distillate oil is sulfuric
acid; metallic sulfates appear to be directly emitted only in trace quantities.
Since sulfur trioxide combines with water vapor in the flue gas to form sulfuric
acid vapor at temperatures below 400°C, reported values of sulfur trioxide
emissions are generally equivalent to sulfuric acid emissions. As the flue gas
is cooled below its dew point, a mist of sulfuric acid particles would begin to
appear. Depending on the sampling temperature and procedure, the particulate
sulfates collected would include all the metallic sulfates and some or all of
the sulfuric acid aerosols.
For distillate oil-fueled gas turbines, it has been determined in the
evaluation of existing data that an average of 3.81 percent of the sulfur con-
tent in the fuel is converted to SO.,- For distillate oil reciprocating
engines, an average of 2.13 percent of the fuel sulfur content was found to be
converted to SO-, based on a single set of existing data. SO- emissions from
gas-fueled internal combustion sources are insignificant because of the low
sulfur content of natural gas.
In Table 46, the particulate sulfate emissions data obtained in this
sampling and analysis program are presented. The particulate sulfate data
reported here represent the total sulfate collected in the particulate filter,
which includes metallic sulfates as well as a small amount of sulfuric acid
aerosols. As noted in Table 46, only a small fraction of the sulfur in the
fuel is converted to metallic sulfate.
As discussed previously, the Goksoyr-Ross controlled condensation train
was used for the measurement of S03 emissions from three diesel engine sites.
For Site No. 309-2, S03 was not detected from condensation coil rinse. This
was probably because the condensation coil was maintained at a temperature
above the dew point for H2S04> and as a result none of the H2S04 present was
collected. For Sites Nos. 312-2 and 313-2, sufficient quantities of H2S04 were
collected, and it was determined that 0.99 and 1.07 percent of the fuel sulfur
were converted to SO.,, respectively. The combined current study and existing
125
-------
TABLE 46. SUMMARY OF EMISSION FACTOR DATA FOR
PARTICULATE SULFATE FROM INTERNAL
COMBUSTION SOURCES TESTED*
Combustion Site
Source Type No.
Emission
Factor
(ng/J)
Sulfur in Parti cul ate SO:
Sulfur in Fuel
Distillate Oil #112
Fueled Gas #3Q6
Turbine
#307
#308
Mean x
s(x)
ts(x)/x
Distillate Oil #309
Reciprocating «_ln
Engine #6W
#311
#312
#313
Mean x
s(x)
ts(x)/x
0.335
0.030
0.011
0.077
0.113
0.075
2.1143
0.383
0.520
0.971
0.268
0.468
0.522
0.120
0.6385
0.731%
>0.476%
>0.175%
>1.222%
0.651%
0.222%
1.0835
0.308%
0.226%
0.423%
0.292%
0.420%
0.334%
0.038%
0.3190
The particulate sulfate data reported include metallic sulfates and a small
amount of condensed sulfuric acid aerosols.
s(x) - Standard deviation of the mean.
ts(x)/x - Variability.
126
-------
data indicate an average of 1.40 percent of the fuel sulfur is converted to
S03 for diesel engines, with a variability ts(x)/x of 1.13. Because of the
lower oxygen level in reciprocating engines, the percent of fuel sulfur con-
verted to S03 is also lower for diesel engines than for distillate oil-fueled
gas turbines.
The source severity factors for S03 emissions from electricity generation
and industrial distillate oil turbines can be calculated by using a mean SO
/\
emission factor of 33.1 ng/J and an average conversion factor of 3.81 percent
of sulfur content of the fuel to S03- The SO- emission factor calculated on
this basis is 1.51 ng/J. The source severity factors for S03 are computed to
be 0.056 and 0.18, respectively. This indicates that S03 emissions (in the
form of sulfuric acid vapor and mist) from distillate oil-fueled gas turbines
are potentially hazardous.
For distillate oil reciprocating engines, the general high sulfur content
of diesel fuel would lead to higher SO- emissions. By assuming an average
diesel fuel sulfur content of 0.24 percent and an average conversion factor of
1.40 percent of fuel sulfur to SO-,, the S0~ emission factor for diesel engines
is calculated to be 1.77 ng/J. Using this emission factor, the source severity
factors for SO- emissions from electricity generation and industrial distillate
O
oil reciprocating engines are computed to be 0.23 and 0.18, respectively.
In the evaluation of existing data, it has been determined that at least
90 percent of the particulate emissions from distillate oil turbines are
submicron in size. For diesel engines, there is only limited amount of infor-
mation on the size of the particulates emitted. The study conducted by Turley
et al on a diesel engine, however, did indicate that approximately 75 percent
by weight of the particulate emissions were less than 1 ym in size, and
approximately 85 percent by weight of the particulate emissions were less than
3 ym in size (Reference 32). Thus, most of the particulate emissions from
either distillate oil turbines or distillate oil engines can be considered as
fine particulates.
127
-------
4.3.3 Emissions of Trace Elements
Existing trace element data for oil-'fueled internal combustion sources
are generally inadequate. For distillate oil turbines, the existing data
base for barium, beryllium, cadmium, lead, magnesium, manganese and vanadium
emissions is adequate; however, the existing data base for the other trace
elements is inadequate. For distillate oil engines, existing data on trace
elements are not available. During the current program, trace element emissions
in the stack gases were measured. Trace element content of the distillate oils
was also determined and potential emissions calculated. In almost all cases
the measured stack emissions were lower than the potential emissions.
Trace element measurements on the one gas turbine site (Site No. 110)
showed emissions that could not be differentiated from the blank values in
most cases. Even for those elements for which measured emissions were higher
than blank values, these emission factors are considerably lower than the
corresponding trace element emission factors for distillate oil-fueled gas
turbines. Source severity factors for trace element emissions from gas-fueled
gas turbines are well below 0.05. The conclusion is that emissions of trace
elements from gas-fueled gas turbines are negligible when compared with total
emissions of trace elements from all internal combustion sources. Additional
measurements to improve the trace element data base for gas turbines are there-
fore unnecessary and estimates of trace element emission factors are of little
use.
In Table 47, the trace elements emissions data for the distillate oil-
fueled gas turbines tested in this program are presented. The emission factors
presented are based primarily on the trace element content of the JP-5 fuel
used at the test faciliites, and represent maximum potential emission rates.
All trace elements that could have been emitted at any single site in amounts
above 50 yg/m (corrected to 15% 02) are included in Table 47. Trace elements
that are particularly hazardous (defined here as those with TLV < 1 mg/m3) are
also included in Table 47. The emission factors show that the JP-5 fuel for
Site No. 112 was contaminated with excessive amounts of barium, silicon,
aluminum, magnesium, sodium, boron, and mercury. The emissions of these trace
elements from Site No. 112 were considered to be outliers (using the method of
Dixon described in Appendix A) and discarded in the calculation of the mean
128
-------
TABLE 47 SUMMARY OF EMISSION FACTOR DATA FOR TRACE ELEMENTS FROM
ELECTRICITY GENERATION DISTILLATE OIL-FUELED GAS TURBINES TESTED
Trace
Element
Pb
Ba
Sb*
Sn
Cd
Mo
Br
Se
As*
Zn
Cu
Ni
Co
Fe
Mn
Cr
V
Emission Factor, pg/J
Site
m
27
29
< 5.2
2.7
2.9
1.9
< 11.5
2.3
< 0.31
251
65
67
1.1
377
1487
2.7
1.3
Site
112
90
293
< 5.2
42
3.8
2.8
7.1
< 5.2
< 0.31
607
649
94
1.6
356
8.6
38
1.7
Site
306
59
13
< 2.0
115
1.0
3.6
6.9
1.9
< 2.0
314
649
1110
7.3
419
188
12
9.8
Site
307
< 46
0.07
< 2.1
3.6
0.3
2.9
< 0.07
0.3
< 2.1
<201
649
461
3.8
5
335
15
2.7
Site
308
84
8
14.5
9.6
5.8
6.7
1.8
1.9
< 2.1
96
879
900
5.7
124
4.9
31
< 1.1
X
61
12.6
5.8
35
2.8
3.6
5.5
2.3
< 1.4
294
578
526
3.9
256
405
20
3.3
s(x)
11
6.2
2.3
21
0.98
0.82
2.0
0.81
0.43
86
136
210
1.2
81
277
6.5
1.7
ts(x)
X
0.53
1.55
1.09
1.71
0.99
0.64
1.04
0.96
0.87
0.81
0.65
1.11
0.84
0.88
1.90
0.91
1.37
*u
-
32
12
94
5.5
-
11
4.6
2.6
533
-
mo
7.2
481
1175
38
7.9
(Continued)
-------
TABLE 47. (CONTINUED)
CO
CD
Trace
Element
Ca
K
P
Si
AT
Mg
Na
B
Be
Hg*
Emission Factor, pg/J
; Site
111
314
335
184
1256 1
57
<230
691
82
< 0.044
0.84
Site
112
460
230
92
10,970
293
1068
6280
3770
0.11
10
Site
306
565
118
230
533
< 59
152
<440
< 15
< 0.12
0.50
Site
307
<107
<107
< 46
< 30
< 50
< 63
<460
< 2.3
< 0.14
0.15
Site
308
205
135
80
482
90
61
768
< 12
< 0.38
0.06
X
330
185
127
575
64
127
590
28
0.16
0.39
s(x)
83
43
35
254
8.9
41
82
18
0.06
0.18
ts(x)
X
0.70
0.65
0.76
1.40
0.44
1.02
0.44
2.08
1.02
1.46
*u
_
-
223
1382
-
256
-
86
0.32
0.95
* Sb, As, and Hg emissions were determined by AA.
x = Mean emission factor
s(x) = Standard deviation of the mean.
ts(x)/x = Variability.
x = x + ts(x).
-------
emission factors. For Site Nos. Ill, 306 and 307, the manganese emission
factors were higher than average values because organic manganese fuel addi-
tives were used in these three sites to suppress visible smoke emissions. With
the possible exception of Site No. 307, emission factors for calcium, potassium
and sodium all appear to be excessively high. As discussed in Section 4.1, a
maximum limit of 0.5 ppm in fuel has been set for each of the critical trace
elements: vanadium, combined sodium and potassium, calcium, and lead. The
maximum limit of 0.5 ppm in fuel corresponds to a maximum emission factor of
112 ng/J. As noted in Table 47, the emission factors for calcium, potassium,
and sodium have exceeded the 112 nq/J limit at all sites except possibly
Site No. 307. On the other hand, the emission factors for lead and vanadium
are well within the 112 ng/J limit for all the sites tested.
In Table 48, trace element emission factor data for distillate oil-fueled
gas turbines based on combined current study and existing data are summarized.
The calculated variability ts(x)/x presented in Tables 47 and 48 shows that the
emissions data base is adequate for lead, barium, cadmium, molybdenum, copper,
vanadium, calcium, potassium, aluminum, magnesium, sodium, and beryllium. For
trace element emissions where the variability is greater than 0.7, the upper
bound S for the mean source severity factors have also been calculated from
x = x + ts(x). The results of these source severity calculations show that
among the trace element emissions, S < 0.05 for antimony, arsenic, boron,
bromine, chromium, cobalt, iron, manganese, mercury, selenium, tin, and zinc.
The emissions data base is therefore also adequate for these trace elements.
Trace elements for which the emissions data base appears to be inadequate
include nickel, phosphorus, and silicon. These are the trace element emissions
with both the variability ts(x)/x > 0.7 and Su > 0.05. Additional emissions
data for these trace elements can be obtained by analysis of fuel samples and
field tests are not required.
The mean source severity factors for trace element emissions from electric-
ity generation and industrial distillate oil turbines have been calculated using
emission factors based on combined current study and existing emissions data.
All trace elements with calculated mean source severity factors greater than
0.05 are presented in Table 49. These calculations indicate that among the
trace elements, nickel, copper, and phosphorus are the principal pollutants.
131
-------
TABLE 48 SUMMARY OF EMISSION FACTOR DATA FOR TRACE ELEMENTS FROM
ELFCTRICITY GENERATION DISTILLATE OIL-FUELED GAS TURBINES
BASED ON COMBINED CURRENT STUDY AND EXISTING DATA
Trace
El ement
Pb
Ba
Cd
Mn
V
Mg
Be
Mean Emission
Factor x
(pg/J)
25
8.4
1.8
145
1.9
TOO
0.14
s(x)
(pg/J)
7.8
2.6
0.52
99
0.63
27
0.03
ts(x)
X
0.67
0.68
0.62
1.46
0.70
0.65
0.46
*u
(pg/J)
-
-
-
357
-
-
""
s(x) - Standard deviation of the mean.
ts(x)/x - Variability.
x = x + ts(x). xu values are not computed for trace element emissions
u with ts(x)/x 5 0.7.
TABLE 49. MEAN SOURCE SEVERITY FACTORS FOR TRACE ELEMENT
EMISSIONS FROM DISTILLATE OIL-FUELED GAS TURBINES
Mean Source Severity Factor
Trace
Element
Cu
Ni
P
Emission
Factor
(pg/J)
578
526
127
TLV
(mg/irr)
0.20
0.10
0.10
Elec. Gen.
Distillate Oil-
Fueled Gas Turbine
0.085
0.16
0.037
Industrial
Distillate Oil-
Fueled Gas Turbine
0.28
0.51
0.12
132
-------
In Table 50, the trace element emissions data for the distillate oil
engines tested in this program are presented. Again, the emission factors pre-
sented are based primarily on the trace element content of the diesel fuel used
at the test facilities. All trace elements that could have been emitted at any
single site in amounts above 50 yg/m or are particularly hazardous (TLV <
2
1 mg/m ) are included in Table 50. The emissions data show that among the
trace elements, sodium, nickel, copper, iron, and silicon were emitted in the
largest quantities. The calculated variability ts(x)/x indicates that the
emissions data base is adequate for lead, tin, cadmium, bromine, copper,
nickel, manganese, potassium, phosphorus, aluminum, and mercury. For trace
element emissions where the variability is greater than 0.7, the upper bound
S for the mean source severity factors have been calculated. The S values
calculated are for electricity generation distillate oil engines. The S
values for industrial distillate oil engines would be proportionally lower.
The results of these source severity calculations show that S < 0.05 for all
the remaining trace elements. Since all trace element emissions either have
their variability ts(x)/x < 0.7 or S < 0.05, it is concluded that the data
base for trace element emissions from distillate oil engines is adequate.
The impact of trace element emissions from distillate oil engines is
assessed on the basis of the calculated mean source severity factors. All
trace elements with calculated mean source severity factors greater than 0.05
are presented in Table 51. Among the trace elements, it is seen that nickel
and copper emissions have the greatest potential impact, whereas phosphorus
emissions are also of some concern.
The trace element emission factors for distillate oil-fueled gas turbines
and distillate oil engines are compared in Table 52. It may be noted that for
almost every trace element, the emission factors for the two internal combus-
tion categories are about the same magnitude. The single exception is the
difference between the emission factors for manganese. The manganese emission
factor for distillate oil turbines is higher because of the use of organic
manganese fuel additives at three of the five sites tested. The mean manga-
nese emission factor, based on existing data and sites not employing manganese
additives, is 13 .pg/J for distillate oil turbines as compared to the manganese
emission factor of 16 pg/J for distillate oil engines. The similarity between
133
-------
TABLE 50. SUMMARY OF EMISSION FACTOR DATA FOR TRACE ELEMENTS FROM
ELECTRICITY GENERATION DISTILLATE OIL ENGINES TESTED
Trace
Element
Pb
Ba
*
Sb
Sn
Cd
Mo
Br
Se
*
As
Zn
Cu
Ni
Co
Fe
Mn
Cr
V
Emission Factor,
Site
309
33
4.7
6.4
6.4
< 3.3
33
5.2
0.8
< 2.2
147
644
955
6.0
<488
20.9
33
0.78
Site
310
34
3.0
< 2.2
-------
TABLE 50. (CONTINUED)
Trace
Element
Ca
K
P
Si
Al
Mg
Na
B
Be
Hg
Site
309
<178
<344
< 93
<733
62
< 91
1110
< 33
< 0.052
0.07
Site
310
73
134
133
<191
100
35
511
11
0.031
0.20
Site
311
89
97
100
189
69
< 5
5330
< 5.1
< 0.018
0.16
Emissi
Site
312
133
175
40
229
< 40
44
<287
< 4.2
< 0.009
0.16
on Factor,
Site
313
710
146
120
165
58
37
<889
2.7
0.029
0.09
pg/J
X
237
179
97
301
66
44
1625
11
0.028
0.13
s(x)
120
43
16
108
9.7
15
937
5.7
0.007
0.02
ts(K)
X
1.41
0.67
0.46
1.00
0.41
0.95
1.60
1.41
0.73
0.51
*U
569
-
-
602
-
85
4226
27
0.048
-
*
Sb, As, and Hg emissions were determined by AA.
x - Mean emission factor.
s(x) - Standard deviation of the mean.
ts(x)/x - Variability.
xu = x + ts(x).
-------
TABLE 51. MEAN SOURCE SEVERITY FACTORS FOR TRACE ELEMENT
EMISSIONS FROM DISTILLATE OIL ENGINES
Mean Source Severity Factor
Trace
Element
Cu
Ni
P
Emission
Factor
(pg/J)
453
563
97
TLV3
(mg/m )
0.20
0.10
0.10
Elec. Gen.
Distillate Oil
Engine
0.23
0.60
0.10
Industrial
Distillate Oil
Engine
0.20
0.48
0.082
the emission factors is the result of the similarity between the trace element
content of turbine and diesel fuels.
4.3.4 Emissions of Organics and Polycyclic Organic Matter
Analysis of the organic samples have indicated that organic emissions from
internal combustion sources consist mainly of saturated and unsaturated aliphatic
and aromatic hydrocarbons. The most prevalent organic species present were
straight chain and branched chain saturated hydrocarbons, with MATE values in
3
the 100 to 1000 mg/m range. Substituted benzenes, the second most abundant
organic species emitted, have MATE values greater than 100 mg/m . The mean
source severity factors calculated using these MATE values indicate that emis-
sions of these organic species from internal combustion sources are environ-
mentally insignificant as S < 0.001 in all cases.
POM emissions from the one gas-fueled gas turbine and the five distillate
oil-fueled gas turbines tested could not be differentiated from the blank
values and are therefore considered insignificant. POM emissions data from
the eight distillate oil engines tested are presented in Table 53. Of the
ROM's, the naphthalenes and substituted naphthalenes were emitted in the
largest quantities. POM compounds known to be carcinogenic, such as benzo(a)-
pyrene and dibenz(a ,h)anthracene, were not detected. For the Level II organic
analysis performed, the detection limit has been established at 0.05 yg/m3.
136
-------
TABLE 52. COMPARISON OF TRACE ELEMENT EMISSION FACTORS FOR DISTILLATE
OIL-FUELED GAS TURBINES AND DISTILLATE OIL ENGINES
Trace Element
Aluminum
Antimony
Arsenic
Barium
Beryl! ium
Boron
Bromine
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silicon
Sodium
Tin
Vanadium
Zinc
Mean Emission
Distillate Oil Fueled
Gas Turbine
64
9.4
2.1
8.4
0.14
28
1.8
1.8
330
20
3.9
578
256
25
100
145
0.39
3.6
526
127
185
2.3
575
590
35
1.9
294
Factor, pg/j
Distillate Oil
Reciprocating Engine
66
12
2.2
14
0.03
11
4.0
3.1
237
26
5.7
453
325
26
44
16
0.13
12.5
564
97
179
2.1
301
1625
9.1
0.95
178
137
-------
TABLE 53. SUMMARY OF POM EMISSION FACTOR DATA FROM ELECTRICITY
GENERATION DISTILLATE OIL ENGINES TESTED*
OJ
03
Site
Compound 309
Naphthalene 8.4
Methyl Naphthalene
C2 Substituted Naphthalene 15.6
C3 Substituted Naphthalene 4.2
C. Substituted Naphthalene
Cr Substituted Naphthalene
Biphenyl 1.0
Methyl Biphenyl
C, Biphenyl
Dibenzothiophene 2.6
Methyl Dibenzothiophene
Phenanthrene/Anthracene 4.2
Methyl Phenanthrene ' 10.4
Dimethyl Phenanthrene 2.1
Trimethyl Phenanthrene
Ethyl Fluorene
Site
310
12.7
15.5
8.5
2.8
-
-
4.2
-
-
1 .4
0.57
2.1
5.6
0.6
-
-
Emission
Site Site Site Site
311 312 313 309-2
35.8 - 1.9 124.5
336.2
63.7 - - 369.5
460.7
249.7
87.6
10.0 - 9.5
-
11.7
-
-
68.6
59.7 40.9 95.2 62.8
23.9 24.4 36.8
6.4 9.5
17.5
Factor (pg/J)
Site Site
312-2 313-2
34.5 131.9
339.2 353.7
474.9 653.4
158.3 402.8
16.8
-
21 .6
167.8
-
-
-
22.6 55.1
13. 1
-
-
-
X
43.7
130.6
198.2
128.6
33.3
11.0
5.8
21.0
1.5
0.50
0.071
19.1
36.0
10.8
2.0
2.2
s(x)
19.0
62.3
92.5
69.1
31 .0
11.0
2.7
21.0
1.5
0.35
0.071
9.8
12.1
5.3
1.3
2.2
ts(x)
X
1.03
1.13
1 .10
1 .27
2.20
2.37
1.10
2.37
2.37
1.64
2.37
1 .21
0.80
1.13
1 .59
2.37
X
u
88.8
277.8
417.0
292.0
106.6
36.8
12.2
70.6
4.9
1.3
0.24
42.2
64.6
23.5
5.1
7,4
Emissions below detection limits or cannot be distinguished from blank values are indicated by -. For Site Nos. 309, 310,
311, 312 and 313, detection limits for POM compounds were approximately 0.05 ng/J (0.08 ug/m3). For Site Nos. 309-2,
312-2 and 3-312, detection limits for POM compounds were approximately 0.03 ng/J (0.05 yg/m3).
All phenanthrene compounds could also be anthracenes.
-------
Using this detection limit, the calculated source severity factor for benzo(a)-
pyrene emissions from electricity generation distillate oil engines is less
than 0.2.
The impact of the POM emissions found is assessed in Table 54 by the use
of the MATE values, which are equivalent to TLV's and have been previously dis-
cussed in the evaluation of existing emissions data. The mean source severity
factors calculated using the MATE values indicate that the POM emissions from
distillate oil engines were several orders of magnitude below levels of
concern.
The insignificance of the POM emissions from gas turbines and reciprocat-
ing engines is expected because of the high hydrogen to carbon ratio of the
fuels used and the high oxygen level in the combustion gases. Pyrolytic
conditions, which favor the formation of POM's, are seldom encountered in
these internal combustion systems.
4.3.5 Summary of Status of Emissions Data Base
Based on the analysis of the TRW/GCA test results and the existing
emissions data base, the status of the emissions data base for internal com-
bustion sources can be summarized as follows:
Emissions of criteria pollutants are now adequately characterized.
There is no need for additional tests.
t For distillate oil-fueled gas turbines, the existing data base for $03
emissions is adequate. For distillate oil reciprocating engines, the
data base for SO-? emissions could be improved by additional field tests
Trace element emissions from gas-fueled internal combustion sources
are insignificant. For distillate oil engines, the data base for
trace element emissions is adequate. For distillate oil-fueled gas
turbines, the data base appears to be inadequate for the following
trace elements: nickel, phosphorus, and silicon. However, additional
emissions data for these trace elements may be obtained by analysis
of fuel samples, because trace element emissions from distillate oil-
fueled gas turbines have been calculated primarily from fuel trace
element contents. There is no need for Level II or additional Level I
tests.
Emissions of organics and POM's are either environmentally insignifi-
cant or at levels too low to be detected.
139
-------
TABLE 54. MEAN SOURCE SEVERITY FACTORS FOR POM EMISSIONS FROM
ELECTRICITY GENERATION DISTILLATE OIL ENGINES
Compound
Naphthalene
Methyl Naphthalene
C2 Substituted Naphthalene
Co Substituted Naphthalene
t
C« Substituted Naphthalene'
C5 Substituted Naphthalene1"
Biphenyl
Methyl Biphenyl
C3 Biphenyr
Dibenzothiophene
Methyl Dibenzothiophene**
Phenanthrene/Anthracene
Methyl Phenanthrene/Anthracene
Dimethyl Phenanthrene/Anthracene
Trimethyl Phenanthrene/Anthracene
Ethyl Fluorene^
Mean Emission
Factor
(pg/J)
43.7
130.6
198.2
128.6
33.3
11.0
5.8
21 .0
1.5
0.50
0.071
19.1
36.0
10.8
2.0
2.2
MATE
Value
(mg/m3)
50
230
230
230
230
230
1.0
1 .0
1.0
23
23
1.6
30
30
30
90
Mean Source
Severity
Factor S
<0.0001
<0.0001
<0.0001
<0.0001
<0.0001
<0.0001
0.0006
0.0022
0.0002
<0.0001
<0.0001
0.0013
0.0001
<0.0001
<0.0001
<0.0001
K
MATE values are obtained from Reference 29.
The MATE values for C2, 63, C4 and CB substituted naphthalenes are assumed
to be the same as that for dimethyl naphthalene.
The MATE values for methyl and 03 biphenyl are assumed to be the same as
that for biphenyl,
**
tt
it
*r
The MATE value for methyl dibenzothiophene is assumed to be the same as
that for dibenzothiophene.
The MATE values for dimethyl and trimethyl phenanthrene are assumed to be
the same as that for methyl phenanthrene.
The MATE for ethyl fluorene is assumed to be the same as that for
fluoranthene.
140
-------
5. TOTAL EMISSIONS
Based on the results of current sampling and analysis efforts and the
existing emissions data base, estimates of current national emissions and pro-
jected 1985 national emissions from electricity generation and industrial gas
turbines and reciprocating engines have been made by using current and pre-
dicted future fuel consumption rates.
5.1 CURRENT AND FUTURE FUEL CONSUMPTION
Current fuel consumption data are available for electricity generation
internal combustion sources but not for industrial internal combustion sources.
The Federal Power Commission (FPC) has published data showing that to produce
electric energy in 1976, internal combustion plants owned by utilities burned
6.625 x 106 m3 of oil (259.42 x 1015 J) and 4.132 x 109 m3 of gas (157.48 x
10 J) (Reference 4). For the same year, the National Electric Reliability
C T
Council (NERC) estimated total fuel consumption of 5.827 x 10 m of oil
(228.40 x 1015 J) and 3.466 x 109 m3 of gas (132.09 x 1015 J) for utility
combustion and combined cycle turbines (Reference 5). The fuel consumption
for internal combustion engines can therefore be estimated from the above
figures by difference. The 1976 fuel consumption were 20.79 x 10 J for
electricity generation distillate oil reciprocating engines, and 25.39 x 10 J
for electricity generation gas reciprocating engines.
For 1978, NERC estimated total fuel consumption of 8.598 x 10 m of oil
(337.81 x 1015 J) and 3.927 x 109 m3 of gas (149.52 x 1015 J) for utility
combustion and combined cycle turbines (Reference 5). The 1978 fuel consump-
tion for electricity generation reciprocating engines can be assumed to be
equal to the 1976 figures, as reciprocating engine generating1 capacity for the
two years are about equal.
141
-------
For industrial internal combustion sources, detailed fuel consumption
data for 1971 are available (Reference 15). The major uses of industrial gas
turbines and reciprocating engines are transmission of oil and natural gas in
pipelines, natural gas processing and production, and crude oil prpduction.
The 1978 fuel consumption for these combustion source categories are therefore
estimated from the 1971 fuel consumption and using the ratios of the domestic
natural gas and crude oil production figures for these two years (References
33, 34 and 35). The 1971 estimates by McGowin, however, did not provide fuel
consumption data for industrial distillate oil-fueled gas turbines. Utilizing
data contained in the National Emissions Data System (NEDS), Dykema and Kemp
have estimated the 1976 and 1980 fuel consumption for industrial oil-fueled
gas turbines (Reference 36). The NEDS data base is, in general, incomplete
but nevertheless is useful as a supplementary source of information. Based on
the McGowin and Dykema and Kemp data, the 1978 fuel consumption rates for the
four industrial internal combustion sources are estimated to be: 10.97 x 10 J
for distillate oil-fueled gas turbines, 438.02 x 10 J for gas-fueled gas
turbines, 61.93 x 10 J for distillate oil reciprocating engines, and 1003.92
x 10 J for gas reciprocating engines.
Prediction of fqel use trends by internal combustion sources from present
time to 1985 is subject to many uncertainties. For electricity generation
distillate oil and gas turbines, the National Electric Reliability Council
(NERC) has estimated fossil fuel requirements for the years 1977 - 1986
(Reference 5). According to the NERC estimates, the fossil fuel requirements
for 1985 will be: 8.204 x 106 m3 of oil and 0.641 x 109 m3 of gas for com-
bustion turbines, and 9.657 x 10 m of oil and 1.681 x 1Q9 m3 of gas for
combined cycle turbines. These figures are equivalent to a projected 1985
total fuel consumption of 702.85 x 10 J for oil-fueled electricity generation
turbines and 88.49 x 10 J for gas-fueled electricity generation turbines.
The figures also represent a 108.1 percent increase and 40.8 percent decrease
in fuel consumption for the oil-fueled and gas-fueled gas turbines from 1978
to 1985. The increase in oil consumption will be mostly due to the fuel
requirements for the operation of combined cycle turbines, used for base load
rather than peaking service.
142
-------
For electricity generation reciprocating engines, the Federal Power
Commission reported that as of April 1, 1976, a net of 112,000 KW of diesel
and dual-fuel generating capacity were scheduled to be installed in the
1976 - 1985 period (Reference 10). This added capacity represents only a
2.1 percent increase over the 1976 generating capacity. Assuming that the fuel
requirement would also increase by 2.1 percent during the same period, the
fuel consumption for distillate oil reciprocating engines would increase by
37.2 percent from 1978 to 1985 if the fuel consumption for gas reciprocating
engines would decrease by 40.8 percent, the same as that for gas-fueled tur-
bines during the same period. On this basis, the 1985 fuel consumption would
15 1R
be 42.57 x 10 J for distillate oil reciprocating engines and 15.03 x 10 J
for gas reciprocating engines. The estimated 1978 and 1985 fuel consumption
rates for electricity generation internal combustion sources are summarized
and compared in Table 55.
The projected 1985 fuel consumption rates for industrial internal combus-
tion sources were estimated on the basis of the 1985 domestic natural gas
(including a small percentage of SNG) and crude oil supply rates. The estimates
TABLE 55. 1978 AND PROJECTED 1985 FUEL CONSUMPTION FOR ELECTRICITY
GENERATION INTERNAL COMBUSTION SOURCES
Fuel Consumption, 10 J
Combustion Source Category
Distillate Oil Fueled Gas
Turbines*
Gas Fueled Gas Turbines
Distillate Oil Reciprocating
Engines
Gas Reciprocating Engines
Total
1978
337.81
149.52
31.02
25.39
543.74
1985
702.84
88.49
42.57
15.03
848.94
Percent
Change
1978 - 1985
+1 08 . 1 %
-40.8%
+37.2%
-40.8%
+56.1%
The estimated 1985 fuel consumption for distillate oil turbines includes
approximately 6.6 percent residual oil fuel.
143
-------
discussed in this report are obtained from the two latest studies by the Bureau
of Mines and the Federal Energy Commission (References 34 and 35). The U.S.
Department of the Interior, Bureau of Mines (BOM) has published estimates of
energy use trends to the years 1980, 1985 and 2000. Their projections are
"based essentially on the evaluation of BOM fuels data" and the assumption
that "existing patterns of resource utilization will continue." BOM pro-
jections for domestic natural gas and crude oil production for the year 1985
are presented in Table 56 along with the Federal Energy Administration (FEA)
projections.
The method used by the FEA is briefly described below:
"The Project Independence Evaluation System (PIES) is a model of the
technologies, leadtimes, costs and geographical locations which affect
energy commodities from the point of discovery, through production,
transportation, conversion to more useful forms, and ultimately con-
sumption by all sectors of the economy. Consumption (final demand)
for a particular fuel depends on prices for that fuel, the prices of
substitute fuels, the general level of economic activity, and the
ability of consumers and capital stocks to adjust to these factors.
For each year of analysis, FEA forecasts the demand for refined petro-
leum products, natural gas, electricity, and coal. These fuel demands
are made for each Census region and for each end-use consuming
sector - residential and commercial, industrial, and transportation.
These demand forecasts are based on estimated prices and vary as
prices change.
Energy supply is estimated separately for oil, natural gas, and coal.
For each fuel, many different regions are separately evaluated to
assess the differences between DCS and Alaskan oil or Appalachian and
Western coal. For each region and fuel, reserve estimates are combined
TABLE 56. PROJECTED 1985 DOMESTIC NATURAL GAS
AND CRUDE OIL PRODUCTION
Fuel
Domestic Natural Gas
Domestic Crude Oil
1985 Production, 1015 J
BOM FEA*
20,278 24,248
31,557 29,302
Percent
1974 -
BOM
-9.67%
+42 . 04%
Change
1985
FEA
+8.02%
+31.89%
Based on business as usual supply and demand cases and price of $13 per
barrel for imported oil.
144
-------
with the technologies and costs of finding and producing these fuels
to estimate the cost of increasing supply. Major improvements have
been made in the oil and gas models to estimate drilling patterns,
link finding rates and enhanced recovery directly to revised reserve
estimates, and account for changes in the depletion allowance. The
coal supply estimates distinguish between various sulfur and Btu
contents.
The PIES then attempts to match these energy demands as a function
of fuel, sector, and price with the available supply in the regions
which can supply these needs at the lowest price to find a balance or
equilibrium. If supply is not available to satisfy the specific
demands in an area, the prices are allowed to vary until supply and
demand are brought into balance."
FEA conducted the above analyses for three imported oil prices ($8, $13
and $16 per barrel) and four alternative energy strategies (business as usual,
accelerated supply, accelerated conservation, and a combination of accelerated
supply and conservation). The base case of business as usual supply and
demand and price of $13 per barrel for imported oil is used in this report.
The FEA and BOM estimates differ in two important areas. First with
regard to natural gas production, BOM predicts a 9.7 percent decrease while
FEA predicts an 8.0 percent increase for the 1974 1985 period. The second
major difference is that BOM predicts a higher 1985 domestic crude oil produc-
tion rate than FEA. The total fuel production rate from domestic natural gas
1 5
and crude oil of 51,835 x 10 J as predicted by BOM, however, is only slightly
15
different from the 53,550 x 10 J figure predicted by FEA.
Utilizing the 1985 domestic natural gas and crude oil production figures
predicted by BOM or FEA, the 1985 fuel consumption rates for industrial inter-
nal combustion sources are estimated. The assumptions used are that fuel con-
sumption rates for gas fueled turbines and reciprocating engines are proportional
to domestic natural gas production and that fuel consumption rates for oil
fueled turbines and reciprocating engines are proportional to domestic crude
oil production. An exception is that fuel consumed by gas reciprocating
engines for crude oil production is assumed to be proportional to the domestic
crude oil production rate. The estimated 1985 fuel consumption rates for
industrial internal combustion sources are presented in Table 57, along with
the 1978 figures for comparison.
145
-------
TABLE 57. 1978 AND PROJECTED 1985 FUEL CONSUMPTION FOR
INDUSTRIAL INTERNAL COMBUSTION SOURCES
15 Percent
Fuel Consumption, 10 J 1978 -
Combustion Source
Category 1978
Distillate Oil -Fueled 10.97
Gas Turbines
Gas-Fueled Gas Turbines 438.02
Distillate Oil Reciprocat- 61.93
ing Engines
Gas Reciprocating Engines 1,003.92
Total 1,514.84
1 985 1 985
BOM FEA BOM
13.90 12.91 +26.7%
397.23 475.00 -9.3%
78.46 72.86 +26.7%
926.54 1,092.78 -7.7%
1,416.13 1,653.55 -6.5%
Change
1985
FEA
+17.7%
+8.4%
+17.7%
+8 . 9%
+9.2%
5.2 CURRENT NATIONWIDE EMISSIONS
Total 1978 national emissions from electricity generation and industrial
internal combustion sources were determined based on combined current study and
existing data emission factors and the estimated 1978 fuel consumption rates
discussed in the previous section. Nationwide emission totals for the criteria
pollutants are presented in Table 58. Particulate and SO emissions from
A
internal combustion sources are relatively small and amount to less than
0.5 percent of emissions of these pollutants from all stationary sources.
Emissions of NO hydrocarbons, and CO from internal combustion courses,
A
however, are more significant. NO hydrocarbon, and CO emissions from
X
internal combustion sources account for approximately 20 percent, 9 percent,
and 1 percent of the emissions of these pollutants from all stationary sources.
Of the NOX, hydrocarbon, and CO emissions from internal combustion sources,
more than 80 percent are contributed by the industrial reciprocating gas
engine cateogry.
146
-------
TABLE 58. CURRENT NATIONWIDE EMISSIONS OF CRITERIA POLLUTANTS
FROM ELECTRICITY GENERATION AND INDUSTRIAL
INTERNAL COMBUSTION SOURCES
Emissions, Mg/year
Combustion Source
Category
N0x
HC
CO
Part
SO
X
Electricity Generation
Distillate Oil-Fueled 105,000 5,900 14,800 4,400 11,200
Gas Turbines
Gas-Fueled Gas Turbines 25,200 3,500 9,700 800 40
Distillate Oil Engines 43,200 1,600 8,300 400 3,100
Gas Engines 39,300 13,400 8,600 100 10
Subtotal 212,700 24,400 41,400 5,700 14,350
Industrial
Distillate Oil -Fueled
Gas Turbines
Gas-Fueled Gas Turbines
Distillate Oil Engines
Gas Engines
Subtotal
Total , Internal
Combustion
2,300
56,800
86,200
1,555,000
1,700,300
1,913,000
40
3,800
3,200
530,000
537,040
561 ,400
1,100
21,400
16,500
341 ,300
380,300
421,700
100
2,200
900
5,700
8,900
14,600
400
100
6,300
300
7,100
21,500
Current trace element emissions from internal combustion sources are
summarized in Table 59. Emissions from gas fueled turbines and engines are
negligible relative to oil fueled sources and are not reported. The estimated
trace element emissions represent about 25 to 40 percent of the total particu-
late emissions, indicating the completeness of combustion for these sources
categories. Total quantities of trace elements emitted are less than those
from residential sources and should be negligible when compared with trace
element emissions from coal-fired combustion sources.
147
-------
TABLE 59. CURRENT NATIONWIDE EMISSIONS OF TRACE ELEMENTS
FROM ELECTRICITY GENERATION AND INDUSTRIAL
INTERNAL COMBUSTION SOURCES*
Emissions, Mg/year
Trace
Element
Aluminum
Antimony
Arsenic
Barium
Beryl! ium
Boron
Bromine
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silicon
Sodium
Tin
Vanadium
Zinc
Elec. Gen.
Distillate Oil- Di
Fueled Gas Turbines
22
3.2
0.72
2.8
0.048
9.4
0.61
0.62
no
6.7
1.3
200
87
8.4
34
49
0.13
1.2
180
43
63
0.79
190
200
12
0.66
99
Elec. Gen.
still ate Oil
Engines
2.0
0.36
0.069
0.42
0.0008
0.35
0.12
0.096
7.3
0.80
0.18
14
10
0.81
1.4
0.51
0.0041
0.39
17
3.0
5.6
0.066
9.3
50
0.28
0.029
5.5
Industrial
Distillate Oil-
Fueled Gas Turbines
0.70
0.10
0.023
0.092
0.0016
0.30
0.020
0.020
3.6
0.22
0.043
6.3
2.8
0.27
1.1
1 .6
0.0043
0.039
5.8
1.4
2.0
0.026
6.3
6.5
0.38
0.021
3.2
Industrial
Distillate Oil
Engines
4.1
0.71
0.14
0.84
0.0017
0.69
0.25
0.19
15
1.6
0.35
28
20
1.6
2.7
1.0
0.0082
0.77
35
6.0
n
0.13
19
TOO
0.56
0.059
11
*
All trace elements that showed a potential concentration above 50 yg/m3 at
any site or are particularly hazardous (TLV <1 mg/m3).
148
-------
Emissions of polycyclic organic matter (POM) from oil fueled reciprocatino
engines are summarized in Table 60. POM emissions from gas and oil fueled
turbines were not detected. Total POM emissions from distillate oil engines
were estimated to be 60 Mg (megagrams) per year. As discussed previously,
POM compounds known to be carcinogenic were not detected.
5.3 FUTURE NATIONWIDE EMISSIONS
Based on the porjected 1985 fuel consumption for internal combustion
sources discussed in Section 5.1, future nationwide emissions from these
combustion categories were estimated. Estimated future nationwide emissions
TABLE 60. CURRENT NATIONWIDE EMISSIONS OF POLYCYCLIC ORGANIC
MATTER FROM ELECTRICITY GENERATION AND INDUSTRIAL
INTERNAL COMBUSTION SOURCES
Compound
Naphthalene
Methyl Naphthalene
C2 Substituted Naphthalene
C, Substituted Naphthalene
C^ Substituted Naphthalene
C5 Substituted Naphthalene
Biphenyl
Methyl Biphenyl
C- Biphenyl
Dibenzothiophene
Methyl Dibenzothiophene
Phenanthrene/Anthracene
Methyl Phenanthrene/Anthracene
Dimethyl Phenanthrene/Anthracene
Trimethyl Phenanthrene/Anthracene
Ethyl Fluorene
Emissions
Elec. Gen. Distillate
Oil Engines
1.4
4.1
6.1
4.0
1.0
0.34
0.18
0.65
0.046
0.016
0.002
0.59
1.1
0.34
0.062
0.068
, Mg/year
Industrial Distillate
Oil Engines
2.7
8.1
12.3
8.0
2.1
0.68
0.36
1.3
0.093
0.031
0.0044
1.2
2.2
0.67
0.12
0.14
149
-------
for the criteria pollutants, trace elements, and ROM's are presented in
Tables 61, 62, and 63. For the criteria pollutants, the 1978 and projected
1985 emissions are approximately equal except for S0x. The projected 1985 SOX
emissions from internal combustion sources represent a 69 percent increase
over the 1978 SO emissions, because of the increase in fuel consumption for
electricity generation distillate oil-fueled gas turbines. The total 1985 S0x
emissions, however, will still be insignificant. Total 1985 trace element
emissions from internal combustion sources represent a two-fold increase from
the 1978 trace element emissions. This again will be the result of increased
fuel consumption for electricity generation distillate oil-fueled gas turbines.
TABLE 61. PROJECTED 1985 NATIONWIDE EMISSIONS OF CRITERIA POLLUTANTS
FROM ELECTRICITY GENERATION AND INDUSTRIAL INTERNAL
COMBUSTION SOURCES
Emissions5 Mg/year
Combustion m HC CQ Part SQ
Source Category x x
Electricity Generation
Distillate Oil-Fueled 218,400 12,300 30,800 9,100 23,300
Gas Turbines
Gas-Fueled Gas Turbines 14,900 2,100 5S700 500 20
Distillate Oil Engines 59,300 2,200 11,300 600 4,300
Gas Engines 23,300 7,900 5,100 100 4
Subtotal 315,900 24,500 52,900 10,300 27,600
Industrial
Distillate Oil-Fueled 2,900 50 1,400 200 500
Gas Turbines
Gas-Fueled Gas Turbines 51,500 3,400 19,400 2,000 100
Distillate Oil Engines 109,200 4,100 20,900 1,100 7,900
Gas Engines 1,435,200 489,200 315,000 5,300 200
Subtotal 1,598,800 496,800 356,700 8,600 8,700
Combustion6^1 1,914,700 521,300 467,200 18,900 36,300
150
-------
TABLE 62. PROJECTED 1985 NATIONWIDE EMISSIONS OF TRACE ELEMENTS
FROM ELECTRICITY GENERATION AND INDUSTRIAL INTERNAL
COMBUSTION SOURCES
Trace
Element
Aluminum
Antimony
Arsenic
Barium
Beryllium
Boron
Bromine
Cadmium
Calcium
Chromium
Cobalt
Copper
Iron
Lead
Magnesium
Manganese
Mercury
Molybdenum
Nickel
Phosphorus
Potassium
Selenium
Silicon
Sodium
Tin
Vanadium
Zinc
Emissions, Mg/year
Elec. Gen.
Distillate Oil-
Fueled Gas Turbines
45
6.6
1.5
5.9
0.10
20
1.3
1.3
230
14
2.7
410
180
18
70
100
0.27
2.5
370
89
130
1.6
400
410
24
1.4
210
Elec. Gen.
Distillate Oil
Engines
2.8
0.49
0.094
0.58
0.0012
0.48
0.17
0.13
10
1.1
0.24
19
14
1.1
1.9
0.69
0.0057
0.53
24
4.1
7.6
0.091
13
69
0.39
0.040
7.6
Industrial
Distillate Oil-
Fueled Gas Turbines
0.89
0.13
0.030
0.12
0.0020
0.39
0.025
0.025
4.6
0.27
0.054
8.0
3.6
0.35
1.4
2.0
0.0054
0.050
7.3
1.8
2.6
0.032
8.0
8.2
0.48
0.027
4.1
Industrial
Distillate Oil
Engines
5.2
0.90
0.17
1.1
0.0022
0.88
0.32
0.24
19
2.0
0.45
36
26
2.0
3.4
1 .3
0.010
0.98
44
7.6
14
0.17
24
130
0.71
0.074
14
151
-------
TABLE 63. PROJECTED 1985 NATIONWIDE EMISSIONS OF POLYCYCLIC
ORGANIC MATTER FROM ELECTRICITY GENERATION AND
INDUSTRIAL INTERNAL COMBUSTION SOURCES
Emissions, Mg/year
Compound
Elec. Gen.
Distillate Oil
Engines
Industrial
Distillate Oil
Engines
Naphthalene
Methyl Naphthalene
C2 Substituted Naphthalene
C., Substituted Naphthalene
C4 Substituted Naphthalene
Cg Substituted Naphthalene
Biphenyl
Methyl Biphenyl
C3 Biphenyl
Dibenzothiophene
Methyl Dibenzothiophene
Phenanthrene/Anthracene
Methyl Phenanthrene/Anthracene
Dimethyl Phenanthrene/Anthracene
Tri methyl Phenanthrene/Anthracene
Ethyl Fluorene
1.9
5.6
8.4
5.5
1.4
0.47
0.25
0.89
0.064
0.021
0.003
0.81
1.5
0.46
0.085
0.094
3.4
10
16
10
2.6
0.86
0.46
1.6
0.12
0.039
0.006
1.5
2.8
0.85
0.16
0.17
The total 1985 POM emissions from internal combustion sources will amount to
78 Mg per year, or approximately a 30 percent increase over the 1978 POM
emissions. This will still be a negligible fraction of the total POM emissions
from stationary sources, and the POM's emitted from internal combustion sources
will be relatively harmless compounds, such as naphthalene, alkyl naphthalene,
and alkyl phenanthrenes, with typical MATE values in the 1 to 230 mg/m3 range.
During recent years, fuels of other types have been evaluated for use in
gas turbine power generation. Specifically, methanol has been demonstrated
as a viable replacement fuel for gas turbines, based both on excellent
152
-------
performance and low emissions. In one series of tests, NO emissions from
J\
methanol fuel were found to be 74 percent less than with Mo. 2 oil, and CO
emissions from methanol fuel were only slightly higher compared to No. 2 Oil
(Reference 37). On the negative side, today's methanol production will only
supply a very small fraction of the current gas turbine fuel requirements.
If methanol supply can be increased substantially while at the same time the
methanol cost becomes competitive with No. 2 oil, then methanol can be an
alternative fuel for gas turbines in the future. For the 1978 - 1985 period,
however, gas and oil are expected to remain as the critical fuels for gas
turbines and reciprocating engines (Reference 5).
153
-------
6. REFERENCES
1. Surprenant, N., R. Hall, S. Slater, T. Susa, M. Sussman, and C. Young.
Preliminary Emissions Assessment of Conventional Stationary Combustion
Systems, Volume II - Final Report. Report prepared by GCA/Technology
Division for the U.S. Environmental Protection Agency. EPA-600/2-76-
046b. March 1976. NTIS PB-252 175.
2. Hamersma, J.W., S.L. Reynolds, and R.F. Maddalone. IERL-RTP Procedures
Manual: Level 1 Environmental Assessment Report prepared by TRW, Inc.,
for the U.S. Environmental Protection Agency. EPA-600/2-76-160a.
June 1976.
3. Durkee, K.R., E.A. Noble, and R. Jenkins. Standards Support and Envi-
ronmental Impact Statement - Vol. 1 : Proposed Standards of Performance
for Stationary Gas Turbines. EPA-450/2-77-017a. September 1977. NTIS
PB-272 422.
4. FPC News Release No. 23009. Federal Power commission, Washington, D.C.
March 25, 1977.
5. Fossil and Nuclear Fuel for Electric Utility Generation Requirements and
Constraints. 1977-1986. National Electric Rel iability Council,
Princeton, New Jersey. August 1977-
6. Youngblood, S.B., G.R. Offen, and L. Cooper. Standards Support and
Environmental Impact Statement for Reciprocating Internal Combustion
Engines. Acurex Report TR-78-99. March 1978.
7- Ewing, R.C. Pipeline Economics. Oil and Gas Journal, 73(33): 70.
August 18, 1975.
8. Ewing, R.C. Pipeline Economics. Oil and Gas Journal, 74(34): 89.
August 23, 1976.
9. Congram, G.E. Pipeline Economics. Oil and Gas Journal , 75(34): 78.
August 22, 1977.
10. FPC News Release No. 22673. Federal Power Commission, Washington, D.C.
October 15, 1976.
11. Urban, C.M. and K.J. Springer. Study of Exhaust Emissions from Natural
Gas Pipeline Compressor Engines. Report prepared by the Southwest
Research Institute for the Pipeline Research Committee of the American
Gas Association (Project PR-15-61). February 1975.
154
-------
REFERENCES (Continued)
12. Gas Turbine Electric Plant Construction Cost and Annual Production
Expenses. First Annual Publication. Federal Power Commission. FPC
Publication FPC-S-240. Washington, D.C. 1972.
13. Gas Turbine Electric Plant Construction Cost and Annual Production
Expenses. First Annual Supplement. Federal Power Commission. FPC
Publication FPC-S-254. Washington, D.C. 1973.
14. Utility Cost Study - Part 1. Sawyer's Gas Turbine International,
p. 43-73. March-April, 1977.
15. McGowin, C.R. Stationary Internal Combustion Engines in the United
States. Report prepared by the Shell Development Co. for the U.S.
Environmental Protection Agency. EPA Report No. R2-73-210. April 1973.
120 p. NTIS PB-221 457.
16. Dietzmann, H.E. and K.J. Springer. Exhaust Emissions from Piston and
Gas Turbine Engines used in Natural Gas Transmission. Report prepared by
the Southwest Research Institute for the Pipeline Research Committee of
the American Gas Association (Project PR-15-61), January 1974.
17. Hare, C.T. and K.J. Springer. Exhaust Emissions from Uncontrolled
Vehicles and Related Equipment Using Internal Combustion Engines: Part 6 -
Gas Turbine Electric Utility Power Plants. Report prepared by the South-
west Research Institute for the U.S. Environmental Protection Agency.
EPA Report APTD-1495. February 1974. NTIS PB-235 751.
18. Coppersmith, F.M., R.F. Jastrzebski, D.V. Giovanni and S. Hersh. Con
Edison's Gas Turbine Test Program: A Comprehensive Evaluation of Statio-
nary Gas Turbine Emission Levels. Paper prepared at the 67th Annual
Meeting of the Air Pollution Control Association, Denver, Colorado.
June 9-13, 1974.
19. Lieberstein, M. Summary of Emissions from Consolidated Edison Gas Turbines
Report prepared by the Department of Air Resources, City of New York.
November 5, 1975.
20. Hurley, J.F. and S. Hersh. Effect of Smoke and Corrosion Suppressant
Additives on Particulate and Gaseous Emissions from a Utility Gas Turbine:
Report prepared by KVB Inc. for Electric Power Research Institute. EPRI
FP-398. March 1977.
21. Carl, D.E., E.S. Obidinski and C.A. Jersey. Exhaust Emissions from a
25-MW Gas Turbine Firing Heavy and Light Distillate Fuel Oils and Natural
Gas. Paper presented at the Gas Turbine Conference and Products Show,
Houston, Texas, March 2-6, 1975.
155
-------
REFERENCES (Continued)
22. Crawford, A.R., E.H. Manny, M.W. Gregory and W. Bartok. The Effect of
Combustion Modification on Pollutants and Equipment Performance of Power
Generation Equipment. Jn_ Proceedings of the Stationary Source Combustion
Symposium Vol. Ill - Field Testing and Surveys. EPA-600/2-76-152C.
June 1976. NTIS PB-257 146.
23. Compilation of Air Pollutant Emission Factors. Third edition, including
Supplements 1-7. U.S. Environmental Protection Agency, Publication
No. AP-42. August 1977.
24. Effect of CI-2 on Emissions from a Large Power Generating Gas Turbine.
Ethyl Corporation Research Laboratories, Paper IR 74-IR. Ferndale,
Mississippi. September 1974.
25. Hersh, S. The Effect of a Combustion Additive on Gas Turbine Combustion
Contaminant Emissions. KVB Inc. Scarsdale, New York. Report No. 5200-
231. April 1974.
26. Lipfert, F.W., J. Sanlorenzo and C.E. Blakeslee. The New York Power
Pool Gas Turbine Emissions Test Program. Paper presented at MASS-APCA
Specialty Conference on Air Quality Standards and Measurements.
October 1974.
27. Johnson, R.H. Gas Turbine Environmental Factors - 1973. General Electric
Co. Paper GER-2486B. Schenectady, New York. 1973.
28. Winkler, M. Management of Gas Turbine Fuel Systems. Gas Turbine
International, p. 90-93. March-April 1977.
29. Cleland, J.G. and G.L. Kingsbury. Multimedia Environmental Goals for
Environmental Assessment. Report prepared by the Research Triangle
Institute for the U.S. Environmental Protection Agency. EPA-600/77-136b.
November 1977. NTIS PB-276 920.
30. Hunter, S.C. and P.K. Engel . Sulfur Oxides from Boilers, Turbines and
Industrial Combustion Equipment. ln_ Workshop Proceedings on Primary
Sulfate Emissions from Combustion Sources. Vol 2 - Characterization.
EPA-600/9-78-020b. August 1978.
31. Hamersma, J.W., D.Q. Ackerman, M.M. Yamada, C.A. Zee, C.Y. Ung, K.T. McGregor,
J.F. Clausen, M.L. Kraft, J.S. Shapiro, and E.L. Moon. Emissions Assessment
of Conventional Stationary Combustion Systems - Method and Procedures Manual
for Sampling and Analysis. Report prepared by TRW, Inc. for the U.S. Environ-
mental Protection Agency. EPA-600/7-79-029a. January 1979.
32. Turley, C.D., D.L. Brenchley, and R.R. Landvlt. Barium Additives as
Diesel Smoke Suppressants. Journal of the Air Pollution Control
Association. 23(9): 783-786"! September 1973.
156
-------
REFERENCES (Continued)
33. 1974 Gas Facts. American Gas Association. Arlington, VA. 1975.
34. Dupres, W.G., Jr. and J.S. Corsentino. United States Energy through the
Year 2000 (Revised) Bureau of Mines, U.S. Department of the Interior.
December 1975.
35. National Energy Outlook, Federal Energy Administration. February 1976.
36. Dykema, O.W. and V.E. Kemp. Inventory of Combustion-related Emissions
from Stationary Sources (First Update). Report prepared by the Aerospace
Corporation for the U.S. Environmental Protection Agency. EPA-600/2-77-
066a. March 1977. NTIS PB-266 109.
37. Klapatch, R.D. Gas Turbine Emissions and Performance on Methanol Fuel.
Paper presented at the ASME-IEEE Joint Power Generation Conference,
Portlane, Oregon. September 28 - October 1, 1975.
157
-------
APPENDIX A
158
-------
APPENDIX A
CRITERIA FOR EVALUATING THE ADEQUACY
OF EXISTING EMISSIONS DATA FOR
CONVENTIONAL STATIONARY COMBUSTION SYSTEMS
A major task in the present program was the identification of gaps and
inadequacies in the existing emissions data base for conventional stationary
combustion systems. The output from this effort will be used in the planning
and performance of a combined field and laboratory program as required to com-
plete adequate emissions assessment for each of the combustion source types.
The criteria for assessing the adequacy of emissions data are developed
by considering both the reliability of the data and the variability of the
data. The general approach is to utilize a three-step process as described
below. This approach is applicable to the evaluation of the existing emissions
data as well as emissions data collected during the course of this program.
STEP 1
In the first step of the evaluation process, the emissions data are
screened for adequate definition of process and fuel parameters that may affect
emissions as well as validity and accuracy of sampling and analysis method.
The screening mechanism is devised to reject emissions data that would be of
little or no use. Acceptance of emissions data in this screening step only
indicates the possibility for further analysis, and in no way suggests that
these data are valid or reliable. As such, the data screening criteria are
often expressed in terms of minimum requirements. These screening criteria
are depicted in Figure A-l and discussed in detail below.
The first criterion that will be applied is that only source test data
will be accepted. A significant portion of the data base, and especially those
contained in the National Emissions Data System (NEDS), were developed by the
use of standard emission factors* and not derived from actual test data. The
inclusion of these estimated emissions data in the data base would lead to the
obviously biased conclusion that the actual emissions were the same as those
predicted by the standard emission factors.
The second criterion that will be applied is an adequate description of
the source. In order to further analyze the emissions data, there must be
sufficient information to designate the combustion source according to the
*~
Mostly by the use of emission factors published in the EPA Publication AP-42
"Compilation of Air Pollutant Emissions Factors."
159
-------
EMISSIONS DATA
I
ARE DATA ACQUIRED
BY SOURCE TESTING?
NO
YES
IS THERE SUFFICIENT
INFORMATION TO
DESIGNATE THE
COMBUSTION SOURCE
ACCORDING TO GCA
CLASSIFICATION CODE?
NO
YES
IS THERE INFORMATION
ON FUEL CONSUMPTION
RATE? FOR NOy EMISSIONS
DATA, IS THERE INFORMA-
TION ON OPERATING LOAD?
NO
YES
FOR PARTICULATE
EMISSIONS DATA FROM
COAL BURNING UTILITY
BOILERS, IS THERE IN-
FORMATION ON
PARTICULATE CONTROL
DEVICE PERFORMANCE?
NO
YES
FOR TRACE ELEMENT EMISSIONS DATA FROM
COAL AND OIL COMBUSTION, ARE THERE
CORRESPONDING DATA ON TRACE ELEMENT
CONTENT OF THE FUEL?
FOR SOV EMISSIONS DATA FROM COAL AND
OIL A COMBUSTION, ARE THERE
CORRESPONDING DATA ON SULFUR CONTENT
OF THE FUEL?
NO
YES
IS THERE INFORMATION
ON THE SAMPLING AND
ANALYSIS METHODS
EMPLOYED?
YES
CAN SAMPLING AND
ANALYSIS METHODS
EMPLOYED PRO^DE
EMISSION ESTIMATES WITH
AN ACCURACY BETTER THAN
A FACTOR OF 3?
YES
NO
INCLUDE EMISSIONS DATA IN USABLE DATA BASE FOR FURTHER ANALYSIS
PROCEED TO STEP 2
Figure A-l. Step 1 Screening Mechanism for Emissions Data
160
-------
appropriate GCA classification code. As a minimum, the information provided
should include: the function of the combustion source (electricity generation,
industrial, commercial/institutional, or residential), the type of combustion
(external combustion or internal combustion), the type of fuel used (coal, oil,
gas or refuse), and in the case of coal combustion, the type of furnace (pul-
verized dry bottom, pulverized wet bottom, cyclone, or stoker). For emissions
data that are judged to be valuable* and otherwise acceptable, efforts will be
made to acquire the needed source description information directly from the
investigator or the plant operator.
The third criterion for acceptance of emissions data for further analysis
is an adequate definition of the combustion system operating mode. For example,
operating load has a large effect on NOX emissions from combustion systems. It
is therefore important to have an adequate definition of the test conditions
that may affect emissions. As a minimum, there must be information on the fuel
consumption rate for the emissions data to be accepted. The fuel consumption
rate is necessary for the calculation of emission factors. For NOX emissions
data, field and tests results that do not include information on operating load
will be considered unacceptable because they cannot be used to estimate emis-
sions from a typical combustion system nor could they be used to estimate emis-
sions at any specific load. For other types of emission data, the operating
load information will be considered as a useful parameter for data correlation
but not an absolute requirement for data acceptance.
The fourth criterion for acceptance of emissions data for further analysis
is an adequate definition of the pollution control device performance. Con-
trol device performance will affect not only total emissions but will influence,
for example, the particle size distribution and composition of flue gas emis-
sions. The application of design efficiencies must be approached with caution
in estimating uncontrolled emissions. If a design efficiency of 99 percent is
used and if the control device operating efficiency is only 90 percent, the
calculated uncontrolled emissions would be 10 times larger than the actual case.
Since most coal burning utility boilers are equipped with particulate control
devices, particulate emissions data from the coal burning utility sector will
not be considered acceptable unless accompanied by the particulate control de-
vice performance data. The application of particulate control devices are
lower for the industrial, commercial/institutional and residential sectors,
and also much lower for the oil burning utility sector and nonexistent for the
gas burning utility sector. For these combustion source types, emissions data
will be accepted as uncontrolled emissions data, unless there is information
implying the contrary. As noted in the foregoing discussions, acceptance of
emissions data at this screening step does not suggest that the data are
necessarily valid or reliable. In the second step of the data evaluation pro-
cess, methods for rejecting outlying data points will be defined. Controlled
emissions data that have been mistakenly assumed to be uncontrolled emissions
data due to lack of information will be identified as outlying data points and
be rejected in this second step.
*
In this context, emissions data for trace elements, POM, PCB, and organics
are considered to be more valuable because of the paucity of data.
161
-------
The fifth criterion that will be employed in judging the usefulness of
the emissions data is the availability of fuel analysis data. This is espe-
cially true for emissions of trace elements, and SOX. The trace element con-
tent of coal can vary by one to two orders of magnitude and emissions are
closely related to the trace element content of the coal. No trace elements
are present in appreciable amounts in gaseous hydrocarbons; however, Ni, V and
Na are present in appreciable amounts in some fuel oil. In order to estimate
trace element emission levels from all sources within a given category, the
fraction of each trace element exiting the system in each effluent stream must
be estimated. Thus, trace element emissions data from coal and oil combustion
that are not accompanied by analysis data on the trace element content of the
fuel will not be accepted. Similarly, SOx emissions are directly related to
the sulfur content of the fuel. SOx emissions data from coal and oil combus-
tion that do not include information on the sulfur content of the fuel will
therefore not be accepted.
The last criterion that will be applied is an evaluation of the accuracy
of the sampling and analysis methods employed. In order to determine emissions
from a given site to within a factor of 3, both the sampling and analysis pro-
cedures employed must be capable of providing an accuracy which is better than
a factor of 3. The list of methods available for the sampling and analysis
of general stream types and chemical classes and species is very extensive,
and has been described in detail in two recent TRW reports (References A-l and
A-2). In general, most of the sampling and analysis procedures recommended in
these two references are adaptations of standard EPA, ASTM, API methods, and
have an accuracy and/or precision of ± 10 to 20 percent or better. Emissions
data obtained by these recommended methods or techniques will be considered
acceptable. Emissions data obtained by methods or techniques not listed in
these two references will be subjected to careful review, and rejected if it
is determined that the sampling or analysis method employed would not be able
to provide emission estimates within an accuracy factor of 3 or better. Special
emphasis will be placed on the review of sampling and analysis methods used for
obtaining PCB, POM, particulate sulfate, and trace elements emissions data.
In cases where information on the sampling and analysis methods employed is
unavailable, the date of testing will be used as the criterion for inclusion or
rejection of the emissions data in the usable data base. Emissions data ob-
tained before 1972 will be generally considered as unacceptable due to the
probable use of unreliable sampling or analysis procedures. The 1972 cut-off
date is selected on the basis that the EPA Method 5, which has been more or
less recognized nationally as the standard method for sampling particulates,
was introduced in late 1971. Furthermore, most of the more sophisticated sam-
pling and analysis techniques for obtaining emissions data, and especially
those for measuring pollutants for which data are lacking (such as trace ele-
ments and particulate sulfate), were not introduced and is used before 1972.
STEP 2
In the second step of the data evaluation process, emissions data which
have been identified as usable in the screening step will be subjected to fur-
ther engineering and statistical analysis to determine the internal consis-
tency of the test results and the variability in emissions factors.
162
-------
Emissions data included in the usable data base will first be categorized
according to the 5 column GCA combustion system classification code and the unit
operation from which the pollutants are emitted. For NOX, the emissions data
will be further categorized according to the method of NOx control; no control,
staged firing, low excess air, reduced load, or flue gas recirculation. Emis-
sions factors for individual sites, normally expressed in the form of Ib/MM
Btu or Ib/ton, will then be calculated for each pollutant/unit operating pair.
In the case of trace element stack emissions from coal and oil combustion,
these emission factors will be calculated in the form of the fraction of each
trace element emitted to the atmosphere,
The emission factors calculated for each pollutant/unit operation pair will
be evaluated in terms of consistency of test results among sites. All the data
points that lie outside the upper and lower limits of reasonable data will be
subjected to detailed scrutiny, and discarded unless there is additional in-
formation to reclassify the data into the correct category. The decision
whether an outlier is a reasonable result or whether it may be discarded as
being an improbable member of the group will be based on the method of Dixon.
The method of Dixon is a statistical technique applicable to the rejection of
a single outlying point from a small group of data, and is described in detail
in Attachment A.
The variability of the emission factors will next be calculated. The
variability is defined as
(1)
(x)
where x is the estimated mean value of the emission factor, s(x) is the esti-
mated standard deviation of the mean, ami t is a multiple of the estimated
standard deviation of the mean value s(x"). The value of t depends on the de-
gree of freedom and the confidence level of the interval containing the true
mean y, and is given in standard statistics texts. For the present program,
that t values at 95 percent confidence level will be used in calculating the
variability of emission factors.
The main thrusts in this second step are: (1) to determine the emission
factors for each pollutant/unit operation pair and for each combustion source
category; (2) to discard outlying data points using the method of Dixon; and
(3) to calculate the percent variability of the emission factors. The values
calculated in this step will be used in Step 3.
STEP 3
The final step in the data evaluation process involves a method developed
by the Monsanto Research Corporation (MRC) for the evaluation of data adequacy.
This quantitative method will indicate where additional emissions data are
needed. The method is based on both the potential environmental risks asso-
ciated with the emission of each pollutant and the quality of the existing
emissions data.
163
-------
The potential environmental risks associated with pollutant emissions are
determined by the use of source severity factors S. For emissions to the at-
mosphere, the source severity S is defined as the ratio of the calculated maxi-
mum ground level concentrations of the pollutant species to the level at which
a potential environmental hazard exists. The simple Gaussian Plume equation for
ground level receptors at the plume center!ine is the disperion model used for
determining the ground level concentration. The potential environmental hazard
level is taken to be the Threshold Limit Value (TLV) divided by 300 for non-
criteria pollutants and the ambient air quality standard for the criteria
pollutants. The mean source severity S for noncriteria pollutants is calculated
as follows:
s =
5.5
(TLV)h
(2)
where
Q = emission rate, g/s
3
TLV = threshold limit value, g/m
h = stack height, m
For the five criteria pollutants, the equations for calculating mean source
severity S is given in the following table:
Pollutant Severity equation
Particulate
S°y
X
NO
X
Hydrocarbons
CO
S
s
s
s
s
- 70Qh"2
- 50Qh"2
= 315Qh~2>1
= 162. 5Qh"2
- 0.78Qh~2
(3)
(4)
(5)
(6)
(7)
The emission rate is calculated by the following equation:
Q - fjjp (EF) (GPP) (YPS)
(8)
where TC = total fuel consumption, tons/year
TNP = total number of plants/sites
EF = emission factor, Ib/ton
GPP = 453.6 g/lb
YPS = 3.1688 x 10"8 yr/s
164
-------
For discharges to the water, th.e source severity factor S is calculated
as follows:
Vn C + S f f
_y _ u fa 1 2
VDD
K
3
where VD = discharge flow rate, m /s
CD = discharge concentration, g/m
Sg = Teachable solid waste generation, g/sec
fj = fraction of the solid waste to water
f2 = fraction of the material in the solid waste
3
VR = river flow rate, m /s
D = drinking water standard, g/m
The mean source severity factor S for each pollutant/unit operation pair
will be used in the evaluation of data adequacy. The method for evaluating
data adequacy is outlined below.
Case 1: When Emissions Data Are Available and Usable
1. Determine the mean emission factor x' and the variability of
the emission factor ts(x")/)( for each pollutant/unit operation
pair. (This will be done in Step 2 of the data evaluation
process. )
2. Determine the mean severity factor S for each pollutant/unit
operation pair by using the mean emission factor x.
3. If the variability in emission factor < 70 percent, there
is no need for additional data.
4. If the variability in emission factor > 70 percent and
S > 0.05, the current data base is judged to be inadequate
and there is need for additional data.
5. If the variability in emission factor > 70 percent and
S <_ 0.1, determine the severity factor S by using the
_
emission factor >< :
x" = x + ts(x)
v '
Su is the upper bound for the severity factor S. The
current data base is judged to be adequate if Su <^ 0.05
and inadequate if Su > 0.05.
165
-------
Case 2: When Emissions Data Are Not Available
1. Determine, if possible, from fuel analysis, mass balance
and physico-chemical considerations the upper bound 3cu can be determined by assuming that all the
trace elements present in the fuel are emitted through the
stack.
2. Determine the upper bound Su of the severity factor S for
each pollutant/unit operation pair by using the emission
factor x"u.
3. The current data base is judged to be adequate if Su £ 0.05
and inadequate if Su > 0.05.
As discussed in a recent Monsanto report (Reference A-3), an allowable un-
certainty in emission factor of ± 70 percent (factor of 3) would lead to an
uncertainty of less than 10 in S , , which has been defined as the acceptable
uncertainty factor for S.
As a result, of the aonlication nf the above data evaluation criteria,
pollutant/unit operation pairs that have been inadequately characterized will
be identified to permit the planning of field tests for acquisition of addi-
tional emissions data.
166
-------
ATTACHMENT A
METHOD OF DIXON FOR DISCARDING
OUTLYING DATA*
The method of Dixon provides a test for extreme values using range. If
the observations in the sample are ranked, the individual values can be iden-
tified xi, \2> X3> » xn-i, xn- It is immaterial whether the ranking pro-
ceeds from high values to low or from low values to high. The Dixon extreme-
value test gives the maximum ratio of differences between extreme-ranking ob-
servations to be expected at various probability levels and for different sam-
ple sizes. Table A-l gives the test ratios and maximum expected values. For
samples less than about eight observations, the ratio of the difference between
the extreme and the next-to-extreme value to the total range is compared with
the tabulated values for the same sample size. If the observed ratio exceeds
the tabulated maximum expected ratio, the extreme value may be rejected with
the risk of error set by the probability level. For samples between about
9 and 14, test the ratio of the difference between the first and third ranking
observations to the difference between the first and next to last. For samples
of 15 or more, use the ratio of the difference between the first and third
ranking observations to the difference between the first-and the second-from
last observation.
In the evaluation of the emissions data, the 0.05 probability level will
be used as the basis for discarding outlying data.
Volk, W. Applied Statistics for Engineers. New York McGraw-Hill, Inc.
2nd ed. p. 387-388. 1969.
167
-------
TABLE A-l. MAXIMUM RATIO OF EXTREME RANKING OBSERVATIONS
Maximum ratio
Recommended Rank Sample
for difference size, Probability level
sample size ratio n
0.10 0.05 0.01
n - ° ?
n < o o
n ~ 1
n 1 4
5
6
7
^O ~ 1 O
1 - n - IS 3 * 8
y - x
Xn-l Xl 9
10
11
12
13
14
V V
n ~ 15
xn-2 " Xl 16
17
18
19
20
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
886
679
557
482
434
650
594
551
517
490
467
448
472
454
438
424
412
401
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
0.
941
765
642
560
507
710
657
612
576
546
521
501
525
507
490
475
462
450
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
.988
.889
.780
.698
.637
.829
.776
.726
.679
.642
.615
.593
.616
.595
.577
.561
.547
.535
168
-------
REFERENCES
A-l. Hamersma, J.W., S.C. Reynolds, and R.F. Maddalone. IERL-RTP Procedures
Manual: Level 1 Environmental Assessment. EPA-600/2-76-160a. p. 131.
June 1976.
A-2. Maddalone, R.F. and S.C. Quinlivan. Technical Manual for Inorganic
Sampling and Analysis. Report prepared by TRVI, Inc. for the U.S.
Environmental Protection Agency. EPA-600/2-77-024. January 1977.
A-3. Eimutis, E.G. Source Assessment: Prioritization of Stationary Air
Pollution SourcesModel Description. Report prepared by Monsanto
Research Corporation for the U.S. Environmental Protection Agency.
EPA-600/2-76-032a. February 1976.
169
-------
APPENDIX B
170
-------
APPENDIX B
PLUME RISES FOR INTERNAL COMBUSTION SOURCES
The source severity factor, as used in the current study, is the ratio
of the calculated maximum ground level concentration of the pollutant species
for an isolated typical source to the level at which a potential environmental
hazard exists (Reference B-l). In general, the potential environmental hazard
level is taken to be the Threshold Limit Value (TLV) divided by 300 for non-
criteria pollutants and the primary ambient air quality standard for the
criteria pollutants.
In the calculation of maximum ground level concentrations as proposed in
Reference B-l, physical stack heights are always used and plume rises have not
been taken into account. This appears to present a special problem in the cal-
culation of severity factors for internal combustion sources, which are typically
characterized by short stacks (6 m), and high exhaust gas temperatures and
velocities. The effective emission height for internal combustion sources
could be 2 to 30 times the physical stack height. The overall result is that
ambient concentrations and source severity factors calculated using physical
stack heights could lead to values overestimated by a factor of 4 to 900.
To correct for this deficiency, it was proposed to use Holland's formula
to estimate plume rise from internal combustion sources (Reference B-2):
V / -
Ah = -Q- M.5 + 2.68 x 10" p - 2. d
where Ah = plume rise, m
V = stack gas exit velocity, m/sec
d = inside diameter of study, m
U = wind speed at source height, m/sec
p = atmospheric pressure, mb
171
-------
T = stack gas temperature, °K
T = air temperature, °K.
a
Estimated plume rises for internal combustion sources, using field data
acquired during this program and Holland's formula, are given in Table B-l.
With an average physical stack height of 6.1 m (20 ft), the average effective
emission height should, therefore, be 159 m for electricity generation gas
turbines and 16.9 m for electricity generation reciprocating engines.
Average plume rises for industrial gas turbines could be estimated from
the field data for electricity generation gas turbines. The assumptions used
in the calculation included:
1) exhaust gases from industrial and electricity generation gas
turbines have similar temperatures and exit velocities;
2) exhaust stacks for industrial and electricity generation gas
turbines are sized such that the cross sectional areas of
stacks are proportional to their rated capacities.
Utilizing this approach, the average plume rise and the average effective
emission height for industrial gas turbines were estimated to be 17.9 m and
24.0 m, respectively.
For reciprocating engines, the average sizes for the electricity gener-
ation and industrial sectors are similar. The average effective emission
height for industrial reciprocating engines could, therefore, be assumed to
be 16.9 m, the same as that estimated for electricity generation reciprocating
engines .
172
-------
TABLE B-l . ESTIMATED PLUME RISES FOR
INTERNAL COMBUSTION SOURCES
Combustion
Source Type
Gas Fueled
Gas Turbine
Distillate Oil
Fueled Gas
Turbine
Average Plume
Diesel
Engine
Average Plume
Site
No.
#110
#111
#112
#306
#307
#308
Rise
#309
#310
#311
#312
#313
Rise
Stack
Diameter
(m)
2.74
2.74
ND*
4.10
4.10
3.61
for Gas Turbine
0.86
0.84
0.84
0.71
0.71
for Reciprocating
Exhaust Gas
Temperature
(°K)
732
753
718
527
649
689
640
631
612
537
552
Engines
Exhaust Gas
Velocity
(m/sec)
37.8
37.8
ND*
24.7
27.9
27.8
23.0
21.5
34.3
20.6
17.0
Plume
Rise
(m)
136
138
143
191
158
153
12.2
10.8
17.0
7.7
6.4
10.8
ND - Not Determined.
173
-------
REFERENCES
3-1. Eimutis, E.G. Source Assessment: Prioritization of Stationary Air
Pollution SourcesModel Description. Report prepared by Monsanto
Research Corporation for the U.S. Environmental Protection Agency.
EPA-600/2-76-032a. February 1976.
3-2. Turner, D.B. Workbook of Atmospheric Dispersion Estimates. U.S.
Environmental Protection Agency, Publication Mo. AP-42. 1970.
174
-------
APPENDIX C
175
-------
APPENDIX C
DATA REDUCTION PROCEDURE
Stack emissions data reported from field measurements or laboratory
analyses are often expressed in terms of volume concentration (ppmv) or mass
O O
concentration (mg/m , yg/m ). To convert these emissions data to the emission
factor form, the following data reduction procedure, adopted from Reference
B-l , is used.
The number of gm moles of flue gas per gm of fuel can be computed using
the fuel composition analysis and effluent 02 concentration:
4.762 (nc + n$) + .9405 nH - 3.762 nQ F
n _ -
hb 1 - 4.762 (02/100) 1 - 4.762 (02/100)
where: npp = gm moles of dry effluent/gm of fuel under
actual operating conditions.
n. = gm moles of element j in fuel per gm of fuel.
J
Op = volumetric 0~ concentration in percent.
F = gm moles of dry effluent/gm of fuel under
stoichiometric combustion.
The average values of F for natural gas and various liquid fuels are given
in Table B-l. The value of F for coal must be computed on an individual basis
because of the variation in the elemental composition of different coals.
For emission species measured on a volumetric concentration basis (ppmv),
the emission factor expressed as ng/J can be computed using the following
equation :
176
-------
/Volumetric ) ,
/Emission) , ... \Concentration/
-------
TABLE C-1. ELEMENTAL COMPOSITION AND
HIGHER HEATING VALUE OF FUELS
Fuel
nc
ns
nH
no
F
Heating
Value
Natural
Gas
0.06221
0
0.23116
0.00040
0.51215
53,310 kJ/kg
No. 2
Distillate
Oil
0.06994
0.00006
0.13889
0.001125
0.45983
45,040 kJ/kg
Kerosene
0.06994
0
0.15873
0
0.48234
47,710 kJ/kg
Res id
Oil
0.07160
0.00031
0.10913
0.00125
0.44037
43,760 kJ/kg
The composition and heating value data are obtained from Reference C-2.
178
-------
REFERENCES
C-l. Coppersmith, F. M., R. F. Jastrzebski, D. V. Giovanni and S. Hersh.
Con Edison's Gas Turbine Test Program: A Comprehensive Evaluation of
Stationary Gas Turbine Emission Levels. Paper presented at the 67th
Annual Meeting of the Air Pollution Control Association, Denver,
Colorado, June 9-13, 1974.
C-2. Steam/Its Generation and Use. Revised 38th Edition. The Babcock and
Wilcox Company, New York, New York. 1975.
179
-------
APPENDIX D
180
-------
TABLE D-l. SASS TRAIN DISTRIBUTION FOR SPECIFIC INORGANICS,
GAS-FUELED GAS TURBINE (SITE 110)
CO
Impingers
Species Participate* X,AD'2 Compositet APS* Total Catch
(mg) (mg) (mg) (mg)
Hg - .29 <. 00032 - .29
As - ** <.044 - <.044
Sb - <.037 <.015 - <.052
S04 - 120 - - 120
F * *
Cl - 23 5.9 - 29
Found
Mass
Emissions
(mg/DSCM)
.0091
<.0014
<.0016
3.8
-
.89
There was no participate sample for Site 110.
Composite of HNO-, module wash, condensate, and the H^O^ impinger.
The second impinger containing ammonium persulfate (APS) and silver nitrate
and the third impinger containing APS.
**
Blank values equal to or slightly higher than sample concentrations.
-------
SITt 110!
VOLHMf
= 3^.0
TABLE D-2. SSMS DATA FOR GAS-FUELED GAS TURBINE
.{.WENT XAI) C
P F. S I N
(MO)
RU
MfJ
MB
ZR
Y
SW
RB
HR
SE
AS
GE
GA
ZN
CU
NI
CO
FE
MM
CR
V
TI
CA
K
S
P
S!
AL
MG
MA
6
R£
LI
< 0
< 0
0
< 0
< 0
c. 0
0
< 0
< 0
< 0
< 0
< 0
< 2
2
< 2
< 0
< 4
< 0
< 0
t 0
c 0
< 7
< 5
< 1R
< 1
< 3
« 1
< 6
< 2
< 0
< 0
< 0
.030 <
. 08'J
.0010 <
.02?
. 02 1 <
. 16
.011
. 1 7
.034 <
. 0 3 H c
.022 <
.021 <
. 4
. 2 <
.5
.027
.9
.24
. 35
.016
, 19
.3
. 0
.
. 7
.7
Q <
.0
. 8 <
.011
.0027 e
.0071 <
fl"pnSI I F
SAMPLF
(Mf,)
0
0
0
0
0
0
0
n
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
9
0
0
0
0
2
0
0
0
.0060
.011
.0055
.0006
.0052
.0053
.0009
.041
.0095
.0044
. 0 n t i
.0041
. 1 H
.32
.15
.0022
. 5 7
.otic;
. OH9
.0019
.0061
. 4 3
.50
ft
.084
.28
.12
.28
.6
.1 1
.0001
.0006
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
< 0
Tin AL
3 ft S S
<
.011
.0010
. C 0 0 b
<
.(1053
.041
<
<
c
<
» 1 8
. 15
.0022
.57
.u82
. 089
.0019
,0061
.43
.50
. 0«4
.28
<
.28
<
.0001
<
0 . 0 3t>
1 0
TO
TO
0.0. ',2
1 0
0.012
TO
0.044
0.043
0 . 0,J6
0.025
Til
2.2
TO
TO
ro
TO
TO
TO
TO
TO
TO
9.6
TCi
TO
1.5
TO
5.3
0.11
TO
0.0077
o.
o .
0,
0.
11.
2.
2.
0 .
4 .
0.
0.
f).
0.
7.
5.
1 .
3.
6.
0.
n«4
0055
027
1 6
1 7
4
5
027
9
24
35
016
1 9
3
0
7
7
0
0027
0
< 0
< 0
0
0
0
0
< 0
0
0
0
< 0
0
0
0
0
0
0
< 0
f- 0
(Mr,/
C II
.0110 i
. 0 0 1) t
.0001
< 0
.0002
0
.0013
< 0
< 0
< 0
< 0
.0055
0
. 0(l'4h
.0001
.018
. 0026
.0028
. 0 0 0 1
. 0 002
.013
.016
0
.0026
. 0 0 8 V
< 0
.0086
< 0
0
.0001
< 0
SSI ON
oso>)
.0011
TO
HI
1 11
.0010
Til
. 01)04
rn
.0014
.00)3
.0008
.0008
10
.069
TO
10
TO
Til
TO
T 0
10
TO
TO
.30
TO
TO
.048
TO
.17
.0035
TO
,0002
0.0026
0.0002
0.0008
0.0049
0.0054
0.075
0.078
0.0009
0.15
0.0076
0 . 0 1 t
0.0005
0 .0060 ""
0.21
0.16
0.053
0.11
0.19
0,0001
- Continued -
-------
SITE 110:
VOL.UMF SAMPLtO =
OS CM
TABLE D-2 (Continued)
ELEMENT
U <
| TH <
B I <
PB <
TL <
AU <
IR <
ns <
1 RE <
w <
, HF <
' L U <
YB <
TM <
ER <
HO <
OY <
" TB <
GO <
EU <
S^ <
no r'J'-> *
: S PR <
~~ CE
LA <
BA <
I cs ~"
I <
Tf. <
SB <
SN <
CD <
PD <
RH <
XAI) C
RFSIN
(
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
" 0
0
0
0
0
2
0
0
0
0
0
0
0
0
MG)
.071 <
.070 <
.063 <
. 46
.061 <
.059 <
,059 <
.05; <
.056 " <
.055 <
. 054 <
.052 <
.052 <
.051 <
.050 <
.049 <
.049 c
.OU8 < .
.047 <
.046 <
.045 ~'~ <
.043 <
.042 <
.0073
.042
. 6
.0006 <
.03H <
,038 <
.067
.13
.012
.032 <
.031 <
MAPI'S I TF.
SflMPLh
(T,
0.
0.
0.
0.
0.
0.
0.
0.
0.
o.
0.
o .
0.
0.
0.
0.
0.
0 .
0.
o.
0.
0.
0.
0.
0.
0.
0.
0.
0.
o.
0.
0.
" 0.
0,
5 A 5 S
LMt SSIMN
FOUNn
) (M(. ) (Mi;/OSCM)
01 4
0)4
012
051
01,2
012
01 1
01 1
01 ]
01 !
01 1
0 1 00
01 00
0099
0099
0097
0096
0094
0093
0090
0089
OOH5
0083
0009
0014
030
0078
0075
0075
0042
0 1 4
015
00t>3
0061
< 0
< 0
< 0
0.051
c 0
< 0
< i)
< 0
< 0
< U
< 0
< 0
c 0
< 0
< 0
< 0
< 0
< 0
< (I
< 0
< 0
< U
< 0
(}
0.0014
0.030
0.0006
< 0
< 0
L
,
.
1
.
,
.
.
,
4
*
,
«
f
085
085
075
11 0.46
073
071
089
068
067
(166
064
063
062
Obi
060
059
058
057
05n
055
054
052
05)
0082
TO 0 . 'J 4 2
T
0 2.6
TO 0 . 0 0 7 B
.
,
04h
046
0.00«2 TO 0.067
0.014
0
< 0
< 0
T 0 0.13
,
.
.
015
osa
037
< o .
< o.
< 0.
0.0016
< 0 .
< o .
< 0.
< o.
< o.
< o.
< o.
< (t .
< n ,
< o.
< 0.
< o.
< o.
< 0.
< o.
< o.
< o .
< o.
< 0.
0.
< 0.0001
0.0009
< 0,0001
< 0.
< 0.
0.0001
0.0004
o.
< 0.
< o.
0 0 2 7
0026
(Ml 2 3
to o.oi«
0023
0022
0022
0021
0021 "" " " " "
0021
0020
0020
0019
0 0 1 9
DO IV
0018
0018
00 1 H
0 0 1 P
0017
0017 ~"
001 6
0016
(Hi 03
TO O.fl013
TO n.0fl3
TO 0.0002
001 4
0014
Til 0.0021
TO 0.0042
0005
0012
or1. 2
-------
TABLE D-3. SASS TRAIN DISTRIBUTION FOR SPECIFIC INORGANICS,
DISTILLATE OIL-FUELED GAS TURBINE (SITES 111, 112)
co
.£»
Impingers
Site Species Particulat
(mg)
111 Hg
As
Sb
S04
F
Cl
N03
112 Hg
As
Sb
so4
F
Cl
N03
<0.0003
<0.019
<0.023
**
**
1.0
0.87
0.0002
**
<0. 00098
7.6
**
1.1
0.59
e XAD-2
(mg)
0.0031
<0.11
<0.037
60.
**
150.
-
0.042
0.060
0.40
90.
0.75
45.
-
Compos Itet APS* Total Catch
(mg) (mg) (mg)
0
<0
<0
0
<0
0
<0
0
0
36
.0025
.023
.076
-
.31
.76
-
.0019
.031
.010
-
.84
.
-
0.001 0.
0.018 0.
0.0064 0.
60.
0.
150.
0.
0.00085 0.
<0.018 0.
<0.006 0.
98.
1.
<0.62 82.
0.
0057
018-0.17
0064-0.14
31
87
045
06-0.11
41
6
59
0.
0.
0.
2.
0.
4.
0.
0.
0.
0.
3.
0.
2.
0.
Found
Mass
Emissions
(mg/DSCM)
00018
00059-0.0056
00021-0.0046
0*
010
9
029
0014
0018-0.0033
013
0*
049
5
018
Calculated
Fuel Feed Mass
(yg/g) Emissions
(mg/m^)
.04
<.015
<.025
2049
20
100
-
.48
<.015
<.25
2199
20
50
-
0
<0
<0
14
0
0
0
<0
<0
32
0
0
.00026
.000099
.0016
.50
.66
-
.0069
.00022
.0036
.29
.72
-
S04 values do not represent total sulfur in the SASS train.
^Composite of HNCU module wash, condensate, and the H-Op impinger.
The second impinger containing ammonium persulfate (APS) and silver nitrate
and the third impinger containing APS.
**
Blank values equal to or slightly higher than sample concentrations.
-------
TABLE D-4. SASS TRAIN DISTRIBUTION FOR SPECIFIC INORGANICS,
DISTILLATE OIL-FUELED GAS TURBINE (SITES 306, 307, 308)
co
c_n
Impingers
Site Species
306 Hg
As
Sb
so4
307 Hg
As
Sb
S04
308 Hg
As
Sb
so4
Participate
(mg)
<. 00002*
<. 00013
<.00013
1.29
<. 00001*
<. OOOOl
.0054
2.3
<. 00003*
.0012
<.0002
2.05
XAD-2
(mg)
<.0056*
<.0013
.058
31.7
<.0054*
<.0012
.055
128.
<.00012
<.0024
<.0024
9.6
Compos itet
(mg)
<. 00092
<. 00092
<. 00092
-
<.024
<.0012
<.0012
-
<.0023
<.oon
<.oon
-
APS*
(mg)
<.02
<. 00098
<. 00098
-
<.021
<.0010
<.0010
-
<.022
<.oon
<.oon
-
Total Catch
(mg)
<.027
<.0033
.060
33.
<.050
<.0034
.063
130.
<.025
.0012
<.0048
12.
Found
Mass
Emissions
(mg/DSCM)
<. 00074
<. 00009
.0017
0.91**
<.0016
<. 00011
.0019
4.2**
<. 00083
.0004
<.00016
0.40**
Fuel Feed
(yg/g)
.024
.097
.0097
1200.
.007
.099
.099
700.
.003
.099
.69
690.
Calculated
Mass
Emissions
(mg/DSCM)
. 00062
.0025
.0025
29.8
.00016
.0025
.0025
92.1
.00016
.0056
.039
38.8
**
Blank values equal to or higher than samples.
Composite of HNO^ module wash, condensate, and the H202 impinger.
The second impinger containing ammonium persulfate (APS) and silver nitrate
and the third impinger containing APS.
SO, values do not represent total sulfur in the SASS train.
-------
31ft lilt VOLUME SAMPLED s 40..I t)Si.M
TABLE D-5. SSMS DATA FOR DISTILLATE OIL-FUELED
GAS TURBINES (SITE 111)
CD
LtMtMT Pwijlit
SOL IDS
0
TH
HI
PH
TL
AU
I»
US
PL
A
HF
LU
VI
IM
EH
HO
or
Irt
Gu
KU
SM
HO
PW
L't
LA
HA
ca
I
Th
SB
SiM
to
PO
RH
""< 0
< 0
< 0
0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
« 0
< 0
< 0
t 0
< 0
< n
< 0
0
< 0
< 0
< 0
0
< 0
< (.
< 0
< 0
MG)
.0005"" <
.0005 *
.1)004 <
.017
.0004 <
. 0 0 0 4
.0004 <
.0004 <
.0004 <
,0004 <
.0004 <
. ouO 4 <
. 0 :.) It S <
,0001 <
.0004 <
. 0 't 0 i <
.0004 <
.0004 <
. 0 0 0 J <
.i)i) 04 <
.0004 <
.0004 <
. 0 0 .) 4 <
. n ii 0 1 <
. 0 i.i !) 1 <
. 0 0 [ M
.0001 <
.0002 <
,0005 <
, 0 0 o a <
. 0 0 0 o <
.00i)l
.0002 <
,0002 <
F ILTLH
CATCH
AAU COMPOSITE TOTAL
IU. SIN SAMPLE SASS
f MISSION
r OIJMO
CMC) (MG) (,-G) 0
0.0084
0 . 0 0 ^ 8
O.H086
0 , 0 0 8 .
< o.
< It.
< I) .
< o.
< o.
< o.
0,0001
0,0001
0.00 4H
0.0001
< o.
< o.
0,0001
0.
0.00 0 1
< o.
< o.
0040 "" <"
0029 <
0026 <
TO 0.025
0026 <
0014 <
0024 <
0024 <
0024 <
0024 <
0024 <
0022 <
0022 <
0021 <
0021 <
0021 <
0021 <
0020 <
0020 <
0019 <
0019 <
0019 <
0 0 1 H <
TO o.ooia
TO 0.0018 <
1 0 0.027
Tl) 0.0015 <
0016 <
0016 <
TO 0,0015
0049
TO 0.0024
0014 <
0014 <
FUEL EMISSION
CALCULATt.D_
(PPM) (MG/OSCM)
0.40 <
0.46 <
0,42 .. e
1.4
0.41 <
0.49 <
0.4ft <
0.4H <
0,47 <
0.47 <
0.46 <
0.45 <
0.45 ' <
0.44 <
0,44 <
0.44 <
0.54 <
0.42 <
0, 51 <
0.40 «
0.40 <
0,29 <
0.28 <
0.0098 <
0.28 <
1.4
0.27 <
0.25 <
0.26 <
0.054
0.14
0.14
0.21 <
0,21 <
0,0041
0. 0040
0,0027
0.0085
0.0027
0,0026
0,0025
0.0025
0,0024
0,0024
0,0024
0,0024
0.0024
0.0022
0,0022
0.0022
0.00?l
0.0021
0,0021
0 . 0 0 1 0
0,0020
O.OOH
0,0019
0,0001
0 , 0 0 1 H
0.0090
0,0017
0,0017
0.0017
0.0004
0,0009
0.0009
0.0014
0.0014
- Continued -
-------
SITE 11 1 I
VOLUME SAMPLED = iO.it DSCM
TABLE D-5 (Continued)
ELEMENT PMIBE
SOLIDS
RU
MO
MB
ZR
V
SR
RB
dR
SE
AS
GE
GA
CU
C'J
Ft
MM
C rt
-. TI
CO ' CA
"^ K
S
p
51
A I.
MI;
N A
6
lit
LI
< 0.0002
0 . 0 0 0 7
< 0,0001
< 0.0015
0.0003
0.0006
< 0.0001
0.0005
0. 0024
~ 0.0009 "~"
0.0005
< 0.0001
0 . 0 0 2 H
0.0065
0.056
0 . u 0 2 3
0.55
1 . 4
0.021
0.0017
0.0026
0 . 0 5 6
0 , "26
o.5
II . 0041
0 , 1 4
0.0^8
0.015
0,0090
0.036
< 0.0001
< 0,0001
F1L1ER
CATCH
(MG)
< 0.0048
0.05!
< 0,0044
< 0.0088
< 0.0042
< 0.0064
< 0.0031
0.05o
0.0063
< 0 . 0060
< 0.0033
< 0.11
< 0,14
1 .S
f . d 4 4
'. 1
0.025
< 0 . Ou 1 3
< 0.060
< 0.78
15.
0.13
< 2.7
< (1 , /4
< 0.94
10.
< 0.075
<" o.oooi
< 0.0022
XAO COMPOSITE
Rt SIN SAMPLE
< 0.030 <
0.064
0.0022
< 0 .
< 0 .
< 0 .
~"o.
< 0.
< 0.
< 0.
< o .
( 0 .
< 4.
< '1.
1 .
0.
< 5.
0 ,
0 .
< 0 .
0.
' 12.
5.
< 50 .
< 2.
44,
< 1 .
< 6 .
8 .
1 .
" o .
< 0.
027 <
027 <
1 4
0088
29
024
063
022 <
021 <
7
8 <
4
024
2
26
12
0 1 9
056
0
2 <
6
0
4 <
6 <
0 0 0"! <
066
0.0044
0,012
0.0010
0.0033
0.0042
0,012
0.0007
0.0100
0,040
0.0044
0.0026
0.0025
0.048
0.089
0.041
0.0018
0.23
0.27
0,14
0.0028
0.0065
2.0
0.23
3.3
0,094"
0.23
0.061
0.11
1 .8
0.018
'0.0003
0.0011
0.
0.
o.
0,
o.
0.
0.
o.
2.
o.
25.
0.
0.
o .
o.
0.
TOTAL
SASS
(l»'G)
< 0.040
0.13
. 0.0033
< 0.041
0003 10
012 TO
0.0095
067 T 0
0,041
0043 10
0005 TO
< 0.027
051 TO
0065 TO
5.0
0,073
52.
9.5
0.31
0045 TO
0,066
1 TO 1
26 TO
TO 5
1 3 TO
49,
099 TO
12 TO
19.
1.6
0002 TO
00)1 TO
0.034 <
0.14
0.29
0.069
0,028 <
4.8
5.0
0.021
3.
5.8
0.
2.5"
2.3
6.9
0,0003 "" <~
0.068 <
EMISSION
FUUNI)
(MG/DSCM)
t 0.0013
0.0042
0.0001
< 0.0013
0.0001 TO
0.0004 TO
0.0003
0.0022 TU
0,001 5
0,0001 TO
0.0001 TO
< 0.0009
0.0017 TO
0.0002 TO
0,097
0 .0024
1 . /
0.31
0,0100
0.0001 TO
0.0022
0.069 TO
0.0086 TO
0.83 TO
0,0044 TO
1 .6
0.0044 TO
0,0039 TO
0.61
0.053
0.0001 TO
0.0001 TO
*
FUEL
(PPM)
: 0.20
0.093
0.19.
< 0.18
0.0011 < 0.18
0.0047 0.33
0.0094 <
0.0023 ~ <
0,0009 <
0.16
0.16
0.0007
0.44
0.19
1.7
0,075
0,076
0.23 <
o.oooi v
0,0022 e
0.023
0,55
0^082 ~
0.15
0.14
12.
3.1
3.2
0.053
18.
71.
0. '3
0.062
0.20
15.
16.
490.
8.8
60,
11.'
33.
5.9
0.0021
0.021
EMISSION
CALCULATED.
(MG/OSCM)
< 0,0013
0,0006
< 0,0012
< 0,0012
< 0.0012
0.0021
0.0001
< 0.0036
0,0007 _
< 0,0005
< 0.0009
< 0.0009
O.OR2
0.020
0.021
0,0003
0.12
0.46
0,0009
0,0000
< 0.0013
0.100
0.11
3.2
0. 058
0.39
0,010
< 0,073
0.21
0.026
< 0.0001 '
< 0,0001
-------
SITE 112! VOLUME SAMPLED = 33.6 DSCM
TABLE D-6. SSMS DATA FOR DISTILLATE OIL-FUELED
GAS TURBINES (SITE 112}
ELEMENT
FILTER
CATCH
(MG)
XAD
RESIN
(MG)
COMPOSITE
SAMPLE
(MG)
TOTAL
SASS
(MCO
EMISSION
FOUND
(MG/OSCM)
FUEL
(PPM)
t^ISSIOM
CALCULATED
(MG/DSCM)
u
TH
P8
TL
AU
IR
OS
RE
HF
Y8
TM
ER
HO
DY
TB
GO
OT SM
NO
PR
CE
LA
BA
CS
I
TE
SB
SN
CD
PO
RH
< 0.0008
< 0.0006
O"to83
< 0.0001
0.0008
< 0.0038
< 0.0038
< 0.0037
0.0003
< 0.0036
< 0.0035
< 0.0035
< 0.0030
< 0,0033
< 0.0033
< 0.0032
< 0.0032
< 0.0031
< 0.0030
< 0.0030
< 0.0029
e 0 .0028
< 0.0002
< 0.0001
< 0.023
< 0.000 1
0.0003
< 0.0026
0.016
< 0 .0089
0.011
< 0^0021
< 0.0021
< 0.071
0.10
< 0.063
2.0
< 0.061
< 0.059
< 0.080
< 0.087
< 0.056
< 0.070
< 0.092
< 0,052
< 0.052
< 0.051
< 0.056
< 0.009
< 0.009
< 0.008
< 0.007
< 0.006
< 0.056
< 0.070
< 0.002
< 0.002
< 0.002
20.
< 0.000
0.20
< 0.000
< 0.038
0.11
0.072
< 0.000
< 0.031
< o.
< 0.
< 0.
0.
< o.
< 0,
< 0.
< 0.
< 0.
< 0.
< 0.
< o.
< 0.
< 0.
< 0.
< o.
< o.
< 0.
< o,
< 0.
< o.
< o.
< 0.
< o.
< 0.
0.
< o.
< o.
< o.
< o.
0.
< 0.
< o.
< o.
021
031
0096
030
012
016
020
027
017
023
028
0080
0096
0078
017
0076
0098
0073
0098
0070
017
02!
0065
0060
0060
030
0061
015
012
0086
021
01S
012
0007
<
<
0.097
0.10
0.076
2.1
< 0.077
0.0008 TO 0.075
<
<
<
0.0003
<
<
<
<
<
<
<
<
<
<
<
<
<
<
0.11
0. 12
0.076
TO 0.096
0.12
0.060
0.065
0.062
0.077
0.060
0.062
0.058
0.060
0.056
0.076
0.090
0.052
0.009
< 0.0001 TO 0.008
20.
< 0.0001 TO 0.006
<
0.016
<
<
0.20
0.055
TO 0.006
0.13
0.083
0.050
0.038
<
<
0.0030
0.0000
0.0023
0.060
< 0 .0020
< 0.0001 10 0.0023
<
<
<
< 0.0001
<
<
<
<
<
<
<
<
<
<
<
<
<
<
< 0.0001
< 0.0001
<
0.0005
<
<
0.0033
0.0036
0.0023
ro 0.0030
0.0038
0.0020
0.0020
0.0019
0.0020
0.0019
0.0019
0.001 H
0.0018
0.0017
0.0023
0.0029
0.0016
0.0015
10 0.0015
0.72
TO 0.0010
0 .(1061
0.0017
TO 0.0010
0.0001
0 ,00?6
0.0017
0.0012
< 0.65
< 0.90
< 0.02
0.3
< 0.01
< 0.08
< 0.70
< 0.81
< 0.51
< 0.69
< O.S6
< 0.35
< 0.35
< 0 . 3 '1
< 0.52
< 0.33
< 0.33
< 0.32
< 0.31
< 0.30
< 0.52
< 0.65
< 0.28
< 0.28
< 0.28
10.
< 0.27
< 0.05
< 0.38
< 0.26
2.0
< 0.06
< 0.37
< 0.21
< 0.0093
< 0.013
< 0.0060
0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0.
< 0 .
< 0.
< 0.
< o.
< o.
< o.
< 0.
< 0.
0.
< o.
< o.
< o.
< o.
0.
< 0.
< o.
< o.
062
0059
0069
01 1
012
0070
1)099
012
0050
0050
0009
0075
0007
0007
0006
0005
0000
0075
0093
0000
0000
0000
21
0038
0060
0050
0038
029
0067
0050
0030
- Continued -
-------
SITE 112: VOLUME SAMPLtO = 32.6 DSCM
TABLE D-6 (Continued)
ELEMENT
FILTER
CATCH
(MG)
XAD
RFSIN
(MG)
COMPOSI TE
SAMPLE
(MG)
TOTAL
SASS
(MG)
EMISSION
FOUND
(MG/DSCM)
FUEL
(PPM)
EMISSIC1M
CALCULATED
(MG/DSCM)
RU
MO
, NB
ZR
Y
SR
RB
BR
SE
AS
GE
GA
ZN
CU
NI
CO
FE
MN
00 V
UD TI
CA
K
S
P
SI
AL
MG
NA
B
BE
< 0.0020
0.0029
< 0.0037
0.0002
< 0.0053
< 0.0009
0.0010
0.0019
< 0.0098
< 0.0015
< 0,0014
0.038
< 0.031
0.026
0.011
t 0.48
0.097
0.016
< 0.0022
< 0,025
< 1.0
< 0.61
11.
< 0.021
< 0.13
< 0.31
< 0.22
< 6.1
< 0.0084
< 0,0001
< 0.051
< 0.048
< 0.028
< 0.027
< 0.027
0.29
0.0088
< 0.14
< 0.027
0.047
< 0.022
< 0.021
< 4.7
< 3.0
< 2.1
< 0.032
< 3.1
< 0. t 1
< 0.22
< 0.027
0.17
< 10!
< 34.
< 3.1
< 4.3
< 9.4
3.0
10.
< 6.4
0.0001
< 0.016
< 0.015
< 0.0043
< 0.0069
< 0.0041
0.0071
< 0.0039
< U.021
< 0,22
< 0.013
< 0.0059
< 0.0032
< 0.19
< 0.043
0.035
0.0047
3.5
0.013
0.049
0.0013
< 0.0022
0.96
< 0.22
3.8
< 0.022
0.14
0.046
0.20
< 0.67
0.0085
0.0002
< 0.069
0.0029 TO 0.062
< 0.0001 TO 0.032
< 0.038
0.0002 TO 0.031
0.30
O.OOBB
0.0010 TO 0.16
0.0019 TU 0.24
0,047
< 0.029
< 0,026
0.038 TO 4.9
< 3.1
0.061 TO 2.1
0.016
3.5
0.11
0.065 TO 0.22
0.0013 TO 0.030
0.17
13.
< 11.
15. TO 34.
< 3.2
0.14 TO 4.4
0.046 TO 9.7
3.2
10.
0.0085 TO 6.4
0.0004
< 0.0021
< 0.0001 TO 0.0019
< 0.0001 TO 0.0010
< 0.001?
< 0.0001 TO 0.0009
0.0091
0.0003
< 0.0001 TU 0.0049
< 0.0001 TO 0.0075
0.0015
< 0.0009
< 0.0008
0.0012 TO 0.15
< 0.094
0,0019 TO 0.064
0.0005
0.11
0.0034
0.0020 TO 0.0068
< 0.0001 TO 0.0009
0.0052
0.38
< 0.33
0.47 T u 1.0
< 0.097
0.0044 TO 0.13
0.0014 TO 0.30
0.098
0.31
0.0003 TO 0.20
< 0.0001
< 0.48
< 0.44
< 0.19
< 0.21
< 0.18
0.18
0.069
< 0.64
< 0.25
< 0.14
< 0.18
< 0,14
29.
31.
4.5
0.076
17.
0.4 1
1.8
0.08]
0.51
22.
1 1 .
140.
4 . 4
0.53 (X)
14.
51 .
300.
180,
0.0050
< 0.0069
e 0.0064
< 0.0027
< 0.0030
< 0.0026
0.0026
0.0010
< 0.0092
< 0.0037
< 0.0020
< 0.0026
< 0,0020
0.42
0.45
0.064
O.ODl 1
0.24
0.0060
0.026
0.0012
0.0073
0.32
0.16
2.1
0.063
76.
0.20
0.73
4.3
2.5
< 0.0001
-------
Silt 4 0 o :
r 30.28 DSC'-'
TABLE D-7. SSMS DATA FOR DISTILLATE OIL-FUELED
GAS TURBINES (SITE 306)
ELEME'
U
TH
HI
PB
TL
AD
03
HE
HF
Id
r ^
fcW
MO
OY
TB
_i G0
5 tu
0 3.."
'iO
Prt
CE
LA
BA
cs
I
TE
SB
CO
PO
Kri
'4 T F I L 1 E K
C A I C H
(
< 0 .
< 0.
< 0 .
< 0 .
< 0 .
< I)
< 0.
< 0 .
< o.
< o.
< o.
< 0 .
< o.
< 0.
c 0 ,
< o .
< 0 .
< 0 .
< 0 .
< o .
< (J .
0 .
< 0 ,
< o .
0.
< o.
< o .
0 .
< o.
< 0.
< o.
^ Ij )
00 49
(10 48
00 44
80
0034
0042
0032
0041
o 0 3 1
0 0 b 4
0029
0028
0028
0028
0 J27
"027
002t>
0025
0025
0024
0023
0009
0011
31
00 J9
oo21
oO 43
028
0 0 '4 5
0 0 1 8
0017
XAi)
k K S I 4
(-.1,1
< 0.087
< 0.078
0.47
< 0.076
< 0 . 0 7 '4
< (..071
< 0.070
< 0 . 0 o 9
< 0 , 06 /
< 0 . 0 o 5
< 0.00-5
< 0 . 0 h 4
< 0 . '1 o 4
< 0.062
< 0 . 0 S 1
< 0.059
< 0.059
< 0,o57
< 0,o5o
< 0 . 0 5 '4
< 0,053
0.01 /
0,0087
0,49
0 . 0 " 1 4
0 . 0 1 il U
< 0 . 0 '4 8
0.013
0.20
1.031
< 0 , 040
< 0 , o3fl
CM'-'
Stt
(
< 0
c 0
0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
0
< 0
0
< 0
0
< 1)
0
< 0
< 0
< 2
0
< 0
< 0
PUSlTfc
'PLE
f'GJ
.019
.039
.on
.0)8
.018
. O'l8
.017
.017
.016
.016
.016
.016
.015
.015
.015
.015
.014
.014
.014
.0015
,014
.039
. li 0 0 8
.HO I 8
.012
.0066
.0
.011
.0098
.0095
1 nTAl
SA.iS
( -"(,
< 0.
< o .
< o.
0.
< 0.
< 0 ,
< 0.
< 0.
< o.
< o.
< o.
< c.
< o.
< 0.
< o .
< 0.
< o.
< o
< 0.
< o.
< 0 .
>
1 1
1 1
i oo
099
045
093
092
090
086
084
084
U82
08 1
080
078
077
0 /6
07 3
073
0.0022 TU 0.056
c 0. 068
0.019
0.
0.
o .
0.
< 0.
0.
0.23 f
0.
< 0.
< o.
0087
53
0014
01 3
062
01 3
n 2.0
042
051
050
EM]
FU
(Hi.,
< 0
< ')
< 0
0
< 0
< 0
< 0
< I)
< 0
< H
< 0
< 0
< 0
< <>
< 0
< 0
< (I
< 0
< 0
< 0
< 0
< 0.0001
< 0
0
0
0
< 0
0
c 0
0
0.0063
0
< 0
< 0
SSIOIv
/OS CM)
.0032
.0031
.0028
.011
. 0 0 2 /
.0026
.0025
.0025
.002 5
.002 4
.0023
.0022
.0022
.0022
.0022
.0021
.0021
.0020
. 0 0 2 0
I U 0.0016
,0019
.0005
.015
.0001
. (i 0 0 '4
.001 7
.000 4
T 1 J 0.054
,0012
.0014
.0014
FUEL
(PPM)
< 0.48
< 0.46
< 0.42
2.8
< 0.41
< 0,49
< 0.48
< 0. 38
< 0.37
< 0.37
< 0. 46
< 0.35
< 0. 35
< 0.44
< 0.43
< 0.33
e 0.43
< 0.32
< 0.31
< 0.30
< 0.30
< 0.29
< 0.28
< 0.28
< 0.28
< 0 . 'J 9
< 0.27
0.040
< 0.2o
< 0 . 090
5.5
< 0.22
< 0.21
<" 0.21
CALCULATED
(MG/DSCM)
< 0.012
< 0.011
< 0.0100
0.069
< 0.0100
< 0,0098
< 0.0095
< 0.0 0 9 '1
< 0.0092
< 0.0091
< 0 . 0 0 H 8
< 0 . 0 0 H 7
< 0.0086
< 0.0084
< 0.0084
< 0.0082
< 0.0080
< 0.0079
< 0.00/8
< 0.0075
< 0.00/4
< 0.0071
< 0.00/0
< 0.0069
< 0.0069
< 0,012
< 0.0066
0.0010
< 0.0063
< 0.0022
0.14
c 0 . 0 0 S 6
< 0.0053
< 0.0051
- Continued -
-------
Si TE 306:
TABLE D-7 (Continued)
tLF,F..
RU
MIJ
y
liH
3E
AS
GE
CU
CU
FE
2 T?
K
5
P
SI
AL
MG
LI
i r F : L TEK
C At C H
( '' Ij )
< 0 .1)0 1 7
< (1,0 0 0 1
0.015
0 .0006
i) , (1 n ii
n . n 0 ij 4
0,05 '-i
0.0054
< 0.0011
0.074
0.0057
3.6
1 . 0
0.25
0,0009
< 0 . 0 o 7
1 . f>
2.0
Ib.
12.
< 0.82
4.7
< 4.6
7 . 7
< 0.0025
< 0.0082
X AL)
R K S 1 1
1
< 0
1)
()
0
0
0
0
0
0
0
< 0
< 0
I
4
4
0
3
0
0
0
5
1 1 n
1
1 0
< 23
1
< 9
< (I
< 0
1)
*
-------
STTE 3072 VOLUME SAMPLED = 30.89 OSCM
TABLE D-8. SSMS DATA FOR DISTILLATE OIL-FUELED
GAS TURBINES (SITE 307)
ELEMENT FILTER
U
TH
BI
P8
TL
AU
IR
OS
W
HF
LU
YS
TM
HO
DY
^ GO
tv> EU
SM
NO
PR
CE
LA
HA
CS
I
TE
SR
SN
CD
PD
RH
CATCH
(MG)
< 0.0033
< 0.0032
< 0.0029
0.59
< 0.0028
< 0.0027
< 0,0027
< 0. 0026
< 0.0026
< 0.0002
< 0.0025
< 0.0024
< 0.0024
< 0.0023
< 0.0025
< 0,0023
< 0.0022
< 0. 0022
< 0.0022
< 0.0021
< 0.0021
e 0.0020
< 0.0019
< 0.0002
< 0.0002
< 0.026
< 0.0001
0.0003
< 0.0018
< 0.0006
0.0054
0.0082
< O.OU15
< 0.0014
XAD
RESIN
(MG)
< 0.063 <
< 0.062 <
< 0.056 <
0.0030
< 0 . 054 <
< 0.053 <
< 0.051 <
< 0.051 <
< 0.050 <
< 0.049 <
< 0.048 <
< 0.047 <
< 0.046 <
< 0,045 <
< 0.045 <
< 0.044 <
< 0.043 <
< 0.042 <
< 0.042 <
< 0.041 <
< 0.040 <
< 0. 038 <
< 0.038 <
< 0.037 <
< 0.037 <
< 0.0034
< 0.035
< 0.034 e
< 0.034 <
< 0.0003 <
< 0.0017 <
< 0.030 <
( 0.028 <
e 0.027 <
COMPOS1 TE
SAMPLE
0.029
0.028
O.U25
0.11
0,025
0.024
0,023
0.023
0.024
0.022
0.022
0.021
0.021
0.020
0 . 0 2 U
0 .020
0.020
0.019
0.019
0.01H
U. 0 1 8
0.017
0.017
0 . 1) 0 3 4
0.017
0.016
U . 0 0 0 1
0.015
0,015
U . 0 () i 6
0.73
0.032
0.013
0.012
TOTAL
SASS
(MG)
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
<
0.0001
0.0003
<
<
0.0054
0.0082
<
<
0.096
0.093
0.084
0.71
0.082
0.079
0.077
0.076
0.075
0.1)72
0.072
0 . U 7 0
0.069
0.068
0.067
0.066
0.065
0.064
0.063
0.061
0. 06(1
0.058
0.057
0.041
0.054
0.016
TO 0.035
TO 0.049
0.051
0 . 0 (1 4 6
TCI 0.73
10 0.062
U.043
0.041
EMI
SSION
FOUND
<
<
<
<
<
<
<
<
c
<
<
<
<
<
<
c
<
<
<
<
<
<
<
<
< 0.0001
< 0.0001
<
<
0.0002
0.0003
<
<
0
0
'6
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
.0031
.0050
.002?
.023
.0027
. 0026
.0025
.0025
.0024
.0023
.0023
.0023
.0022
.0022
.0022
.0021
.0021
.0021
.0020
.002 (1
.0020
.0019
.0018
.0014
.0018
.0005
10 0.0011
1 (.1 0.0016
.0017
.0001
TO 0.024
TO 0.0020
.0014" '
.0013
FUEL
(PPM)
< 0
< 0
< 0
< 2
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
<" "'0
< 0
< 0
< "0
< 0
< 0
< 0
< 0
<""0
< 0
< 0
< 0
0
< 0
0
< 0
< 0
< 0
< 0
.48
.46
.42
.2
.4 1
.39
.38
.38
.37
.37
.36
. 35
.35
.34
.43
.33
.33
.32
.31
.30
.30
.29
.28
,2'8
.28
.21
.27
.40
.26
. ! 2
.45
.22
.21
.21
EMISSION
CALCULATED
(MG/DSCM)
< 0.01S
< 0.014
< 0.013
< 0 .068
< 0.013
< 0.012
< 0.012
< 0.012
< 0.012
< C.01 1
< n.oi 1
< U . 0 1 1
< 0.011
< 0.0100
< 0.0100
< o.oioo
< 0.0100
< 0.0(144
e 0.0098
< 0 . 0 fl 9 4
< 0 . 0 0 4 3
< 0.0089
< 0.0087
< o . o o a /
< 0.0086
< 0.0065
< 0.0(162
0.013
< 0.0079
0.0038
< o . o i a
< 0.00/0
< 0.0066
< 0,0064
- Continued -
-------
SITE 307:
VOLUME SAMPLED = 30.89 DSTM
TABLE D-8 (Continued)
ELEMENT FILTER
CATCH
(MG)
BU
MO
N6
ZR
Y
SR
R8
BW
SE
AS
GE
GA
CU
CO
FE
OJ V
T I
CA
K
5
P
SI
AL
MG
NA
B
BE
LI
< 0
0
< 0
0
< 0
0
< 0
< 0
0
0
< 0
< 0
0
< 0
" < 0
< 0
< 1
" 0
0
0
< 0
< 0
< 0
<"" 0
0
< 0
<- "0
< 0
< 0
-<- o
< 0
< 0
.0010
.023
.000!
.0044
,0001
.0020
.0005
.0035
.032 '""
.0100
.0010
.0010 ""
.29
. 066
.017
.0040
,4
. 14
.086
.0004
.040
. 60
. 34
.ai
. 19
.071
.0019"
.025
. 0 J8
.22 "
.0001
.0002
XAD
~RFS1N~
0.027
0.0004
0.025"
0.024
0.024
0.0016
0.0001
0.0021
0.021
0.0010
0.019
0.019 -
0 .26
I,.26
0.0023"
o.oooo
0.12
0,0100
o.oioo
0.0005
0.0008
0.50
0,93
7.3
O.ol
1 . 1
16.
"0.60
0.037
0.0022
COMPOS! TE
SAMPLE
: 0,012
0.096
: " 0.011
: 0.0030
0.0006
" 0.0089"
0.0034
: 0.0093
0.022"
: 0.048
: 0.0088
: "~ D . 0034 '
: 0.3b
0 , 08b
"" 1 . 1
0,020
1 ,0
: 0,21"
Q.15
: 0.015
0.017
: 2.5
c 0.05
: " 4.6
0.097
: 4.6
-- o.i /
: 0,16
: 3,6
"" 0.014
c 0.0001
: 0,0027
TOTAL
SASS
(MG)
< 0.041
0.12
< 0.036
0.0040 TO 0.027
0.0007 TO 0.024
0.011
0.0034
< 0.015
0.054
0.0100 TO 0.049
< 0.029
< 0.028
0.29 TO 0.62
0.088 TO 0.33
I.I
o.o^o
l.o
0. 1 4
0.23
0.0004 TO 0.015
0.018 Id 0.040
< 3.7
< 1.7
< 13.
0.29 TO 0,61
< 6.2
14.
< 1.3
16.
"0.014"- TO" 0.82
< 0.000) TO 0.037
0.0022
EMISSION
FOUND
< 0.0013
0 . 0039
< 0.0012
0.0001 111 0.0009
< 0.0001 TO 0.0008
0.0003
0,0001
< 0.0 0 0 5
0.0018
0.0003 TO 0.0016
C 0,0009
< 0.0009
0.0094 TO 0.020
0.0028 TO 0.011
0 , 0 J 4
0.0006
0.033
0.0046
0.0075
< 0.0001 TO 0.0005
0.0006 TO 0.0013
< 0,12
< 0, 056
< 0.41
0.0093 TO 0.0-20
< 0,20
0 , O1}
< 0.042
0.51
0.0005 TO 0.02/
< 0.000! TO 0.0012
< 0.0001
FUEL
(PPM)
< 0.20
0.14
0.020
< 0.18
< 0.18
< 0.14
< 0.024
< 0.29
< 0.16
< 0.13
< 0.15
" ~ < " 0.14
< 9.6
31.
22.
0.18
< 1 7.
16.
0.72
0.13
< 0.32
< 5. 1
< 5.1
Zl 0. -
< 2.2
< 69.
< 2.4
< 3,0
< 22.
< 0 . ] 1
< 0.0067
< 0.023
EMISSION
LALLULATt D
(MG/DSCM)
< 0.0063
0.0043
0.0006
< 0.0057
< 0.0055
"- < 0.0043
< 0.0007
< 0.0090
< 0 . 0 049
< 0. 0040
< 0.0005
< 0.0043
< 0.30
0.95
0.68
0.0057
< 0.52
0.022
0.0001
< n.oioo
< 0,16
< 0.16
6.5
< 0.069-
< 2.2
< 0.0/6
< 0.090
< 0.68
< (1.0034
< 0.0002
< 0.0007
-------
SITE 308: VOLUME SAMPLED = 30.0? DSCM
TABLE D-9. SSMS DATA FOR DISTILLATE OIL-FUELED
GAS TURBINES (SITE 308)
ELEMENT FILTER
u
TH
HI
P8
TL
Alt
IR
OS
RE
W
HF
LU
YH
TM
HO
DY
TH
-p. EU
NO
PR
CE
LA
BA
CS
I
TE
SB
SN
CD
FU
RH
CATCH
(MG)
< 0.0040
< 0.0039
0.0018
< 0.80
< 0.0035
< 0.0033
< 0.0033
< 0.0032
<" 0.0032
< 0.0007
< 0.0030
< 0.0030
< 0.0029
< 0.0029
< 0.0028
< 0.0028
< 0.0028
< 0 .0027
< 0.0027
< 0.0026
< 0.0026
< 0.0025
< 0.0024
< 0.0024
< 0.0024
< 0.27
<~ 0 .0001
0.0019
< 0.0022
< 0.0030
2.1
< 0.0089
< o.uoie
< 0.0017
XAD
RtSIN
(MG)
< 0.048
< 0.047
"< 0.042
0.51
< 0.041
< 0.040
< 0.039
< 0.041
< 0.038
< 0.037
< 0.043
< 0.035
< 0.035
< 0.034
< 0.034
< 0.033
< 0.033
< 0.032
< 0.032
< 0.031
< 0 . OiO
< 0.033
< 0.028
< 0. 028
< 0.028
< 0.39
< 0, 027
< 0,026
< 0,026
< 0,025
< 0.050
0.023
< 0 . 02T
< 0.021
COMPOSI TE
SAMPLE
CMC)
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< "0
< 0
< 0
< 0
< 0
< 0
f. 0
< 0
< 0
< 0
< 0
< 0
f 0
< 0
< 0
< V
< 0
< u
< 0
< 0
< 0
< 0
< 0
0
< 0
.027
.026
.024
.057
.023
.022
.022
.022
.021
.021
.020
.020
.020
.019
,019
.019
.018
.018
.018
.017
.017
.016
.0003
.0021
.016
.013
.0003
.013
.014
. o u 3 3
.47
.13
.012
.012
TOTAL
SASS
(MG )
< 0
< 0
0.0018
0
< 0
< 0
c 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
0.0019
< 0
< 0
0
< 0
< 0
.079
.077
Tfl 0.066
.51
.068
.065
.066
.062
.059
. 066
.058
.057
.056
.056
.055
.054
.053
.052
.050
.050
.052
.031
.033
.046
.67
TO 0.038
.042
.031
!l5
.035
.034
EMISSION
FOUND
(MG/OSCM)
< 0
< 0
< 0.0001
0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< u
< 0
< 0
< 0
< 0
< 0
<: o
< 0.0001
< 0
< 0
0
0
< 0
< 0
.0026
.0026
TO 0.0022
.017
.0023
.0022
.0021
.on??
.0021
.0020
. 0 0 f f
.00 9
.00 9
.00 9
.00 9
.00 8
.00 8
.00 H
.00 7
.001 /
.001 /
.0017
.00)0
.0011
.0015
.022
. 0009
TO 0 . 0 0 1 J
.0014
. 0 0 1 0
.071
.0051
.0012
.0011
FUFL
CA
(PPM)
< 0.48
< 0.46
< 0 . iJ 2
4.0
< 0.41
< 0.39
e 0.38
< 0. 38
< 0.37
< 0.37
< 0.36
< 0. 35
< 0.35
< 0.34
< 0^33
< 0.33
< 0 . 1 r1
< 0.31
< 0.30
< 0.30
< 0,29
< 0.28
< 0.28
c 0.28
< O.«0
< 0.27
< 0.25
< 0.2t>
6.4
0.46
< 0.22
< -0.21
< 0.21
EM1SSIOM
LCULAT EU
(MG/DSCM)
< 0.
< 0.
< f>.
0.
< 1.
< 0.
< 0.
< 0.
< o.
< o.
< o.
< o .
< II.
< 0.
< 0.
< 0.
< o.
- < o.
< 0.
< 0.
< o.
< 0.
c 0.
< 0.
< 0.
< 0 ,
< 0.
< 0 .
< 0.
0.
0.
< o.
< o.
< 0.
0088
0086
0078
075
0076
0073
0071
0071
0069
0068
0066
0065
0 0 6 4
0063
0062
0061
0060
0059
0058
0056
0056
0053
0052
0052
0052
0074
0049
0047
0047
12
0085
0042
UU3V
0038
- Continued -
-------
SITE 308S VOLUME SAMPLED = 30.02 OSC*
TABLE D-9 (Continued)
ELEMENT
RU
MO
N8
ZR
Y
SR
RB
RR
SE
AS
GE
ZN
CU
CO
FE
MM
tn V
ri
CA
K
S
P
SI
AL
MG
MA
B
BE
LI
FILTER
CATCH
(MG)
< 0.0017
0.013
< 0.0001
< 0.014
0.0001
0.014
0.0009
< 0.0079
0.052
0,0081
< 0.0012
< 0.0012
0.42
< 0.13
< 0 .29
< 0.0023
< 0.45
0.0 Ib
0.031
< 0,0020
< 0,066
< 1.3
< 0.48
7 , 6
< 0,070
< 5.5
< 0.34
5.0
< 0 ,062
< 0.0001
< 0.0004
XAO
RESIN
(MG)
< 0
< 0
< 0
< 0
< 0
< 0
< 0
0
< 0
0
< 0
< 0
< 2
1
< 2
< 0
< 3
0
< 0
0
< 0
< 23
3
4 1
c 2
< 5
< 4
2
14
1
< 0
0
.024
.Ob4
.019
.018
.018
.13
.0078
.048
.016
.027
.015
,014
. "
.0
.0
.030
. o
. 1 2
.39
.37
.036"
'.5
.1
.7
.4
.5
.0007
.087
COMPOSITE
SAMPLE
< 0
< 0
0
< 0
< 0
< 0
U
< 0
< 0
0
< 0
< U
< 0
< 0
0
< 0
0
< 0
< 0
< U
0
< 1
< 0
M
0
< 3
< 0
< 0
1
< 0
< 0
0
.011
.042
.0003
.0006
.0100
. 0 1 U 0
.0009
.0018
.0047
.024
. 0 0 B 2
.00/9
.50
. 1 1
. 1 1
.021
.46
. 1 3
. 12
.0018
.0051 ' '
.5
.39
.3
.077
.0
.25
.15
.6
.0012
.0001
.001 7
0.013
TOTAL
SASS
(MG)
0.037
TO 0.11
0.0003 TO 0.019
< 0.033
0.0001 TO 0.028
0.014
0.001
<
0.42
0.11
0.46
0.031
TO 0.14
R TO 0.0078
0.048
0.052
0.060
0.024
0.023
TO 2.5
1 .0
in t.t
0.053
Til 3.4
0. 1 3
TO 0.5,0
0.37
0.0051 TO 0.100
< 26.
3.5
0.077
<
53.
TO 2. i
14.
5. 1
2.5
21.
1 .4
0.0008
0.089
EMI
SSION
FOUND
(M(,/DSCM)
< 0
0.0004
< 0.0001
< 0
< 0.0001
0.0005
< 0.0001
0
0
0
< 0
< 0
0.014
0
0.0037
< 0
0.015
0
0.0010
0
0 , 0 0 0 2
< 0
0
1
0.0026
< 0
< 0
0
0
{)
< 0
0
.0012
TO 0.0035
TO 0.0006
.0011
TO O.OU09
Til 0.0046
10 0.0003
.0016
.0017"
.0020
.0008
.OOOB
TH 0.084
.034
TO 0.0/5
.0018
TO 0.11
.0043
TO 0.017
.012
10 0.0034
.86
. 12
.8
TO 0.071
.47
. 1 7
.083
.68
,U4 7
.0001
.0030
FUEL
CA
(PPM)
< O.?0
0.32
0.028
0.11
< 0.18
0.066
< 0.032
< 0.57
< 0.16
< 0. 35
< U. 15
4.6
42.
43,
0.27
< 22.
< 0.40
1.5
< 0.053
< 11.21
9.8
< 6.8
1 30.
< 4.3 '
< 23.
< 4.3
< 2.9
< 50.
< 0.58
< 0.018
< 0.022
EMISSION
LCULAT ED
(MG/DSCM)
< 0.0038
0.0059
0.0005
0.0021
< 0.0033
0.0012 - , -
< 0.0006
< o.nt i
< 0.002V
< 0.0065
< 0.0027
< 0.0026
0 . 085
0 .78
0./9
0.0049
< 0.42
< 0.0(1/5
0.029
< 0.0010
< 0.0039
0.18
<: 0.13
2.4
< 0.079
< 0.43
< 0.079
< 0.053
< 0.93
< 0 . i) i i
< 0.0003
< 0.0004
-------
TABLE D-10. SASS TRAIN DISTRIBUTION FOR SPECIFIC INORGANICS, DISTILLATE
OIL RECIPROCATING ENGINE (SITES 309, 310, 311, 312, 313)
cn
Impingers
Site
309
310
311
312
313
Species
Hg
As
Sb
SO,
Hg
As
Sb
S04
Hg
As
Sb
S04
Hg
As
Sb
S04
Hg
As
Sb
S04
Particulate
(mg)
<. 00004
<.0009
<.0009
21.2
<. 00001
<. 00063
<. 00035
20.8
<. 00005
<. 00073
<. 00073
28.5
<. 00001
<. 00056
.0039
15.
<. 00001
<. 00071
.0017
22.1
XAD-2
(mg)
.0047
<-0025
<.0025
10.5
.0022
<.0024
<.051
44.0
<. 00053
<.0032
<.0032
82.4
.00098
<.oon
<.oon
104.
<. 00042
<.oon
<.oon
122
Composite t
(mg)
<.0013
-
<.0013
-
<.0066
<.0017
<.0017
-
<.0018
<.0018
<.0018
-
<.0016
<,0016
<.0016
-
<.0048
<.0016
<.0016
-
APS*
(mg)
<.022
*
<.oon
-
<.022
*
<.oon
-
<.024
*
<.0012
-
<.0021
*
<.oon
-
<.027
*
<.0014
-
Total Catch
(mg)
.0047
<.0034
<.0058
31.7
.0022
<.0047
<.054
65.
<.027
<.0057
<.0069
111.
.00098
<.0033
<.0077
119.
<.032
<.0034
.0017
144
Found
Mass
Emissions
(mg/DSCM)
.00016
<. 00012
<. 00020
1.1**
.00077
<. 00017
<.0019
2.3**
c. 00091
<. 00020
<. 00024
3.8**
.00003
<. 00011
<. 00030
4. **
<.oon
<. 00011
.00006
4.8**
Fuel Feed
(ug/g)
.003
<.098
.29
7000.
.009
<.10
<.10
7400.
.007
<.10
oo
7700.
.007
<.10
<.10
4500.
.004
<.10
2.0
5000.
Calculated
Mass
Emissions
(mg/DSCM)
.00013
<.0040
.013
302.
.00028
<.0032
< . 0032
227.
.00015
<.0022
<.0022
162.
.00029
<.004
<.004
190.
.00012
<.003
.0057
151.
Not determined due to interference of isopropanol.
Composite of HNO, module wash, condensate, and the H202 impinger.
'''The second impinger containing ammonium persulfate (APS) and silver nitrate
and the third impinger containing APS.
SO. values do not represent total sulfur in the SASS train.
-------
SIT£ 309:
VOLUMfc SA-IPLtD =
DSCM
TABLE D-11. SSMS DATA FOR DISTILLATE OIL
RECIPROCATING ENGINE (SITE 309)
ELEMENT
U
TH
61
TL
AU
IH
OS
RE
w
HF
LU
YH
IV
EH
HO
OY
ru
GO
to tu
ML)
Prt
CE
LA
BA
CS
I
TE
cn
PD
FILTER
CATCH
C-'G)
< 0.015
< 0,019
< 0.0057
< 0.28
< 0.0 0 i 2
< 0,015
< 0.016
< 0,0100
0,0074
< 0.017
< 0 , 0 0 4 0
< 0.0058
< 0.0055
< (1 . 0 1 0 0
< 0.0054
< 0.0059
< 0. u 02 2
< 0.0059
< 0.002/
< 0.0 loo
< 0.014
< 0.0023
< 0.0051
< 0.0033
0.47
0 ni ri
< 0 . 0 0 8 8
< 0,0074
0,013
< ".0092
< 0.0074
< U . 0 026
X
(
< 0
«. 0
< 0
0
< 0
< n
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< n
< 0
< n
< 0
< 0
< i)
< 0
0
0
< 0
< 0
I)
0
< 0
< 0
,' I)
SIN
Mll)
.100
.098
.089
.81
.087
, ortu
.081
. OM 1
.079
.0/8
.0/6
. 0 7 '4
.074
,072
,071
.0/0
.069
.067
.067
. 0 o U
.061
,060
.027
. 0099
.2 5
,0014
. 1 1
. 0 40
.052
. 1 1
, 0 UJ
CUMP03I IE
SAN'PLE
(
< 0
< 0
< 0
0
< 0
< 0
< 0
< 0
< 0
< u
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< n
< 0
< 0
0
< 0
< 0
< 0
< 0
< 0
0
< 0
< 0
^G )
.051
.040
.027
,068
.027
.026
,024
.024
.023
.025
.025
.022
.022
.U22
.021
."21
.021
.020
.020
.019
.0)8
,0022
.018
. 0 1 8
.017
.017
.017
. 00(1 9
,R8
,068
,0(4
.015
HUAL
SASS
(10)
< o.
< 0.
< 0.
0.
< o,
< 0.
< 0.
< 0.
< 0.
0.0074 1
c 0.
< 0 .
< o.
< o .
< 0.
< 0.
< 0.
< o .
< o.
< 0.
< o.
< 0.
< o.
: 0.
< o.
0.
0.
15
12
88
12
12
12
12
1 1
U 0,100
12
1 00
1 00
09 7
100
095
09(3
090
094
087
094
09 5
060
0 52
041
49
0 1 9
0,11
< 0.078
0.014 TIJ 0.035
n.lj TO .0,88
0.18
< 0,006
< 0,
060
EMISSION
FOUND
(MG/f)SCM)
< 0
< 0
< 0
0
< 0
< 0
< 0
< 0
< 0
0.0004
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
0
0
0
< 0
0.0004
0,0046
0
< 0
< 0
.0051
.0052
.0043
.041
.0042
.0042
.0045
.0043
. 0 0 '1 0
f 0 0.0046
. 0 0 'I 1
.0056
.0044
. 0 0 5 h
.004 5
.00 54
.0052
.0054
.0051
. 0 0 3 5
.0045
. 0028
.0011
.0011
.017
.0007
.00 59
.0027
10 0,0012
TO 0,041
.0064
.0023
,0021
FUEL
(PPM)
< 0 . 0 H
< 0.46
< 0.'J2
l.S
< 0.41
< 0. 39
< 0,48
< 0.48
< 0.47
< 0.37,
< 0.46
< 0. 45
< 0.45
< 0.44
< 0.33
< 0.34
< 0.44
< 0. 52
< 0.4!
< 0.40
< 0.40
< 0.29
< 0.28
0.012
< 0.28
0,21
0.016
0. 0 52
< 0.26
0.27
0.29
< 0.15
< 0.21
< 0.21
tMISSIOM
CALCULATED
(MG/DSCM)
< n.020
< 0,020
< 0.018
0.062
< 0.017
< 0.017 ,
< 0.016 '
< O.Oltf
< 0.016
< 0,016
< 0.015
< 0.015
< 0.015
< 0.014
< 0.014
< 0.014
< 0.014
< 0.014
< 0.013
< 0.013
< 0,013
< 0.012
< 0.012
0.0005
< 0,012
0.0090
0.0007
0.0014
< 0,011
0.011
0.012
< 0,0063
.< 0,0091
< 0.0088
-Continued-
-------
SITE 409:
vrn
= 2fl.5o OSCM
TABLE D-ll (Continued)
ELE'Mt'NT F IL FtH
C A I CH
XAD
h F S I n
C U f' P U SITE
SAMPLE
TOTAL
SASS
( /*(* ) ( N G ) t 'G ) ( MG )
RU
MO
z«
Y
P,B
BR
St
AS
GE
GA
CU
NI
CO
FE
MIJ
_, "
OT ri
CA
K
S
P
SI
AL
MG
NA
ti
HE
< 0
0
< 0
0
0
0
0
n
0
0
< 0
< 0
< 0
0
3
0
40
0
0
0
0
7
1
31
4
1 00
2
1
1
< 0
.0095
. is
.00)6
.065
.0008
.096
.0 42
.012
.046
. Oo5
.0035
.0014
.23
. 9
.041
! ?o
.47
. 0046
.100
. 4
, 7
.0
.6
.5
\f>
,0001
< C> , :) 4 i
< 0.054
< 0.0066
< n , o i 8
< 0 , ii iri
< 0,11
0.28
< 0.1133
< 0.041
< 0 . 0 4 0
1 . 7
2. 4
< 4.8
0 . 28
< 0.54
0 ,071
< 0.062
1>'.H
140.
1 ,3
< 2.6
16.
O.o J
0.0018
< 0
0
< 0
< 0
< 0
0
< 0
< 1.
< 0
< 0
< 0
< 0
0
0
1 3
0
0
< 0
0
23
0
44
0
< 2
0
0
1
0
< 0
.014
,087
.012
.012
.012
.27
.0011
.0100
.0084
.0045
. 0 0 9 1
. 0
.094
.71
. 1
.081
.0072
,0100
.22
. t 1
.2
. 79
. 15
. 7
.024
.0001
< 0
0
< 0
0
0.0008
0
0
0
0
0
< 0
< 0
3
2
4
1 4
48
1
1
0
0
34
5
210
5
120
4
19
33
2
0
. 066
.2 4
.020
. 065
Til 0 . 049
. 36
. 038
.24
.046
. 1 1
,044
. OUQ
. 7
, 6
. 1
.1
,076
. 1 1
.' 7
.7
.4
, 4
,0019
EMISSION
FOUMD
t^i;
< 0
0
< 0
0
< 0.0001
n
0
0
0
0
< 0
< 0
0
0
0
1
0
0
0
0
1
0
7
0
4
0
0
1
0
< 0
/USCM)
.0023
.0082
.0007
,0023
TO 0.0017
.013
.0011
.0100
.0016
.0048
.0015
.0014
. 13
.091
.44
.7
.019
.0 49
.0027
.0040
.2
.20
.4
.20
.1
.12
.68
.2
.086
.0001
FUEL
(PPM)
< 0.20
0.063
< 0.18
< 0.18
< 0,092
< 0.045
< 0.19
< 0.67
< 0.17
< 0,15
< 0.14
6.6
29.
43.
0.27
< 22.
0 .94
l.S
0.0 55
< 0.43
< 8.0
< 24.
280.
< 4.2
< 33.
2.8
< 4.1
SO,
< l.S
< 0.048
EMISSIOM
CALCULATED
(MG/OSCM)
< 0.0086
0". 062
0.0027
< 0,0078
< 0.0076
< 0,0039
< 0,0019
< 0.016
< 0.029
< 0.0071
< 0.0062
< 0.0059
0.28
1.2
1.8
0.011
< 0.94
0.040
0.064
0.0015
< 0.018
< 0.34
< 1.0
12.
< 0.18
< 1.4
0.12
< 0.17
2.1
< 0.065
< 0.0020
-------
sire no:
SAMPLKD = 28.bi OSCM
TABLE D-12. SSMS DATA FOR DISTILLATE OIL
RECIPROCATING ENGINE (SITE 310)
ELEMENT
u
TH
fll
PB
TL
AiJ
OS
Rt
HF
LU
Yl?
T 1
ER
H'J
Of
GO
1X5 S J
PK
Ct
LA
riA
CS
I
TE
38
S'l
CL)
PL)
Kn i
FILTER
CATCH
(f-'G)
< 0,0040 <
< 0.0039 <
0.23
< 0.0043 <
< o.o 03 a <
< 0.0052 <
< 0.0031 <
< 0.0041 <
< 0.0040 <
< o . o o a 9 <
< 0.0029 <
< 0.0028 <
< o , oo a / <
< o . o o a 7 <
< 0.0026 «
< 0.0028 <
< 0.0025 <
< 0.0025 <
< 0,1024 *
< 0.0125 <
< o.o 0 o0
< ij.uoO/ <
< 0.044
< 0.0001 <
0,1007
0.0018 <
0.0071
< 0 . (; 0 1 9
< 0.0018 <
< 0,0017 <
XAO
RESU
(
0
0
0
0
: 0
0
: 0
: 0
: u
: 0
: 0
0
(i
0
0
0
0
n
0
1 1
i)
0
0
0
0
0
0
0
0
u
0
0
0
""G)
,'158
,o5b
.050
.87
. 0 4 9
.048
. I4b
.IIU6
.045
.044
.043
.042
.042
. 0 '! 1
. 040
.040
. u 59
.058
. 0 58
1 ' 3 /
.0 5o
,045
. 134
. o 1 4 7
. I) 44
.090
.05!
. 0 ^ b
. o59
. 02b
.025
SAMPLE
(Mb)
< 0
< 0
< 0
c 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
l
0
< 0
< 0
.039
.058
.050
. 0 4 a
.044
. o 51
.04)
.040
.040
. 029
.028
.028
.027
!
< 0. 45
< 0.45
< 0. 3<4
< 0.53
< 0.35
< 0.33
< 0,32
< 0.31
< 0.30
< 0.30
< 0,29
< 0.28
0 . OUfa
< 0.28
< 0.70
0.0099
< 0,25
< 0.0b4
< 0.51
< 0.22
< 0.21
< 0.21
EMISSION!
CALCULATED
(MG/DSCM)
< 0.015
< 0 . 0 1 S
< 0,013
< 0.16
< 0.013
< 0.012
< 0.012
< 0.012
< 0,012
< 0.012
< 0.011
< 0.011
< 0 . 0 1 i
< 0.011
< 0.011
< 0.0100
< 0.0100
< 0.0100
< 0.0099
< 0.0095
< 0.0094
< 0.0091
< 0,0089
0.0014
< 0,0087
< 0.022
0.0003
< 0.0080
< 0.0080
< 0.0020
< 0 . 0 1 b
< 0.0071
< 0.0067
< 0.0065
- Continued -
-------
SITE '> I i) :
bA.-'.PLF.I'
TABLE D-12 (Continued)
ILLE 'IF NT F 1L 1 1«
CA ICH
HU
MJ
NB
y
SR
HR
St
AS
G£
GA
Z'J
CM
NI
CD
Ft
wrg
CH
\l
TI
rsi Ci
0 *
o 3
P
SI
AL
MG
NA
rt
BE
LI
('S"J)
< 0.0017
0.0096
< 0.0015
0 , 0 0 5 ft
o.ooo?
0.014
0 . D 0 1 6
< 0.0013
0 . 0 0 d 5
< 0.0012
< 0.001?
0 . uu
-.043
o.a 5
< O.OU36
< 0.3?
< 0.0080
0.0 52
< 0 . 0 s 1 5
< 0,050
i.'-l
< 0.65
0 . 39
< 3.5
< 0,79
12.
< 0.42
< 0.0007
< 0.0037
XAI}
H E 3 I N
C-'G)
< 0.024
0,056
< 0,022
< 0.02?
< 0.021
0.059
0.0071
0.066
< 0.019
< 0.051
< 0 . 0 1 rt
< 0,017
O
0 . B 4
0. ,)OH5
1.2
0.019
0.25
0.081
0. 06 a
< 10.
< 41 .
< 1.3
0.79
13.
0. 52
0.000?
0.012
cn-^m
("'GJ
< 0.017
< 0.057
< 0,015
< 0.015
< 0.015
< 0 . 0 0 b 4
< 0 . 00 l! '4
< 0.015
< 0.033
< 0.0010
-------
SITE 311!
VOLUME SAMPLtD
£8.90 DSCM
TABLE D-13. SSMS DATA FOR DISTILLATE OIL
RECIPROCATING ENGINE (SITE 311)
ELEMENT
U
TH
BI
PB
TL
IP.
ns
HF
Y8
TM
ER
HO
0V
GO
EU
O ND
' PR
CE
LA
BA
CS
I
TE
SN
cn
PD
RH
FILTEK
CATCH
(MG)
< 0.0032
< 0.0031
< 0.0028
< 0.25
< 0.0028
< 0.0027
< 0.0026
< 0.002o
~< 0.0025
< 0.0025
< 0.0024
< 0. 0024
< 0.0023
< 0.0023
< 0.0023
< 0.0022
< 0.0022
< 0.0021
< 0.0021
< 0.0021
< 0 .0020
< 0.0019
< 0.0019
< 0.0019
< 0.0019
< 0.070
< 0.0018
< 0.0017
< 0.0017
0.0040
< 0,0100
< 0.0018
< 0.0014
< 0.0014
XflO
RESIN
(MG)
< 0.051
< 0.050
< 0.045
0.097
< 0.044
< 0.043
< 0.042
< 0.041
< 0.040
< 0.040
< 0.039
< 0.038
< 0.037
< 0.036
< 0.036
< 0.036
< 0.035
< 0.034
< 0.034
< 0.033
< 0.032
< 0.031
< 0.030
< 0.030
< 0.030
< 1.1
< 0.029
< 0 . (' 2 7
< 0.028
< 0.054
< 0.055
< 0.100
< 0.023
< 0.022
COMPOSITE
SAMPLE
< 0.044
< 0.043
< 0.038
< O.lb
< 0.038
< U.036
< U.035
< 0.035
< 0.034
< 0.034
< 0.033
< 0.03d
< 0.032
< 0.031
< U.Oil
< 0.030
< 0.030
< 0 .029
< 0.028
< 0,020
< 0.026
< 0.026
0.0009
< 0.026
< 0.021
< 0.024
< 0.0071
< 0.023
< U , 00 /»
< 2.0
0.017
< U . 0 2 U
< 0.019
TOTAL
SASS
(Mi;)
< 0.098
< 0.096
< O.OHb
0.097 1 U 0.41
< 0.084
< 0.081
< 0.079
< 0.079
< 0.077
< 0.076
< 0.074
< 0.072
< 0.071
< 0.070
< 0.064
< 0.068
< 0.067
< 0.066
< 0.065
< 0.063
< 0 . 0 6 2
< 0.058
0.0009 HI 0.032
< 0.057
< 1.2
< 0.055
< 0.036
< 0.053
0.0040 TO 0.062
< 2. 1
0.017 TO 0.11
< 0.044
< 0.043
EMISSION
FOUND.
(MG/DSCM)
e 0.0034
< 0.0033
< 0.0030
0.0033 TO 0.014
< 0.0029
< 0.0028
< 0.0027
< 0.0027
< 0.0027
< 0.0026
< 0.0026
< 0.0025
< 0.0025
< 0.0024
< 0.0024
< 0.0024
< 0.0025
< 0.0023
< 0.0022
« 0.0022
< 0.0022
<. 0.0021
< 0.0020
< 0.0001 TO 0.001 1 ""
< 0.0020
< 0.042
< 0.0014
< 0.0013
< 0.0018
0.0001 TO 0.0021
< 0.071
0.0006 10 0.0037
< 0.0015
< 0.0015
FUEL
(PPM)
< 0.48
< 0.46
< 0.42
< 1.6
< 0.41
< 0.39
< 0.38
< 0.38
< 0 . 3 /
< 0.37
< 0.36
< 0.35
< 0.35
< 0.34
< 0.33
< 0.33
< 0.33
< 0. i^
< 0.31
< 0.30
< 0. 30
< 0.29
< 0.28
< 0.035
0.0095
< 0.62
0 . 0 U i ]
0.100
< 0.26
0.44
0.32
< 0.085
< U.21
< 0.21
F.MISSIOM
CALCULATED
(MG/DSCM)
< 0.011
< 0,0100
< 0.0093
< 0.036
< 0.0091
< 0.0088
< 0.0086
< 0.0085
< 0 . 0 0 H 3
< 0.0082
< 0.0080
< U . 0 0 / 8
< 0.0077
< 0.0075
< 0 . () 0 / 5
< 0.0074
< 0.0073
< II.OU/1
< 0.0070
< 0.0068
< 0.0067
< 0.0064
< O.OU63
< 0,00(18
0.0002
< 0.014
< U.OOO!
0.0023
< 0.0057
0.0(148
0.0071
< 0.0019
< 0 . 0 0 4 /
< O.OOU6
- Continued -
-------
SITE 11 1 I
VOLUME SAMPLED = 28.90 DSCM
TABLE D-13 (Continued)
CLEMENT
PU
MO
"NH "
ZR
y
"Sft
PB
BR
SE
AS
GE
"GA
7N
CU
CO
FE
MfJ '
CR
V
~" S
P
SI
"AL~
MG
NA
" FT
Eif
LI
FILTER
CATCH
XAD
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
3
0
2
0
0
1
0
0
0
.0014 <
.0043 <
.0003 f
.0082 c
.0012 <
. o 0 S 2 <
. 00
-------
SITE 312:
VOLUME SAMPLED = 29.95 OSCM
Eie^fcNT
f- ILTCR
CATCH
(MG)
U <
TH <
Bl <
PB
TL <
AU <
OS <
HI <
W <
HF c
LU <
YB <
TM <
ER <
HO <
OY <
TB <
GO <
EU <
0 NO <
00 PR <
CF
LA <
BA
CS <
I
TE <
SB
SM
CO
RH <
0.003b
0.0035
"0.0032"
0.0051
0.0030
0.0029
0. 0029
0 , 0 0 2 ri"
0.0028
0.0027
0.0027
0. 002o
0.0026
0.0026
0.0025
0.0025
0.0021
0,0021
0.0023
"0.0023
0.0022
0 . 0022
0.0012
0.0018
0.53
"0.0001
0.0012
0.0019
0.015
0.11
0.016
"0.001 b
0. OOlb
TABLE D-14. SSMS DATA FOR DISTILLATE OIL
RECIPROCATING ENGINE (SITE 312)
XAD
*ESIN" "
(MG)
0. 069
0.0b7
0 . 0 b 0
0.52
0.059
0.057
0,055
0.055
0.051
0.053
0.051
0.050
0.050
0.019
0.018
0.017
0.017
0.016
0.045
0,014
0.013
0.012
0.011
0.010
0.010
0 .56
0.038
0.037
0.037
0.025
0.071
0.070
0.031
0.030
COMPOSITE
SAMPLE "
IMG)
c 0.038
< 0.037
< 0.034
0 . 058
< 0.033
< 0.032
< 0.031
< 0.031
< 0 . 0 3 0
< 0.030
c 0 .029
< 0 . 0 2 H
< 0 .028
< 0 . 0 2 /
< 0.027
< 0.026
< 0.026
< 0.026
< 0 .025
< 0.021
< O.o^i
< 0.023
< 0.023
< u . 02 5
< 0 .022
c O.U59
0.018
< 0.020
0.019
c 0.96
0.016
< 0.017
TOTAL
SASS
< 0.11
< 0.11
< 0.097
1 .5
< 0.095
< 0.091
< 0.089
< (..088
< 0 . 0 8 b
< 0.085
< 0 . 0 H 3
< 0,081
< (1,080
< 0.078
< 0.078
< 0.07b
< 0.075
< 0.071
< 0.073
< 0.071
< 0.070
< 0.06 /
< 0. Ob5
0.0012 10
< 1) . Ool
0.33
0.0005 TO
0.020
< 0.059
0.033
0.11 TO
0.13
< 0.019
< 0.018
EMI SSION
FOUND
(MG/OSCM)
< 0.0037
< 0 . 0(i36
< 0 . 00 i2
0.050
<: 0.0032
< U.0031
< 0.0030
< 0.0029
-------
SITE 312;
VOLUME SAMPLED = 29.95 OSCM
TABLE D-H (Continued)
ELEMENT
RU <
MO
N8 <
ZR
Y
SR
RB
BR
SE
AS
GE <
Z.N
CD
NI
CO
FE
MN
CR
V
g^K
S
P
SI
AL <
MG
NA <
8
BE <
LI <
FILTER
CA TCH
(MG)
0.0015
0,027
0.0014
0.015
0.0007
"6.15 " "
0.0014
0.014
0.011
0.048
0.0011
0.0011
1 .5
0.21
3.3
O.Olb
30.
0.40
0.043
0.0048
0.0o8
16.
0.55
0.52
13.
0.80
0.71
2.3
'"0.62
0.0001
0.011
XAD
RESIN
(MG)
< 0.029
0.067
< 0.027
< 0.026
< 0.02b
< 0.18
< 0.011
< 0,094
0. ObO
< 0.030
< 0.021
< 0.020
0, 4b
< 1.1
< 2.9
< 0.031
5.2
""< 0.78"
< 0.24
< 0.0063
0.037"
< 12.
< 9. fa
< 2,'l
< 2.1
< ~ 0 . 63
< 2.0
< 1 1 .
< "0.21
< 0.0026
< 0.063
COMPOSI TE
SAMPLE
< 0
0
0
< 0
< 0
" 0
0
< 0
" 0
0
< 0
< 0
0
< 0
< 0
0
< 1
< 0
0
0
< 0
< 2
< 0
130
< 0
< 0
< 0
< 0
< 3
li
0
0
.016
.022
.0032
.015
.014
.0100
.0007
.018
. 1 4
.0032
.012
.011
.90
.28
.21
.0098
,7
,22
,098
.0018
. 1 7
.2
.33
, 15
.61
.84
.40
.3
.IB
.0001
.0005
TOTAL EMI SSIOM
SASS
(MG)
< 0
0
0.0032
0.015
0.0007
0
0.0022
0.014
0
0
< 0
< 0
2
0.21
3
0
35
0.40"
0
0
0
16
0.55
230
0.52
13
< 2
0.71
< 16
0
0.0001
0.0005
.047
. 12
TO 0.028
TO 0.041
TO 0.040
. 16
TO 0.011
TO 0.11
.21
.051
.034
.032"
.8
TO 1.4
.3
.026
TO 1.0
. 14
. 0 0 b 6
. 1 1
TO 9.9
TO 2.3
.3
TO 2.5
.80
TO 0.0026
TO 0.074
' FOUND
(MCi/OSCM)
<
0.0001
0.0005
< 0.0001
< 0.0001
0.0005
<
<
0.0069
o.otu
0.019
0.017
<
0.024
<
< 0.0001
< o.oooi
0.0016
0.0039
TO 0.
TO 0.
Til 0 .
0.0052
TO 0.
TO 0 .
0.0070
0.0017
0.0011
0.001 T"
0,094
TO 0.
o.n "
0.0008
1 .2
TO 0.
0.0047
0.0002
0.0035 '
0.54
TO 0.
7.7
TO 0.
0.43
0 . 076
TO 0.
0.54
0.027 "
TO 0.
TO 0.
OOD9"
0014
0013
0004
0038
048
033
33
075
082
0001
0025
FUEL
(PPM)
< 0.20
0.46
0.060
< 0.04]
< 0.18
< 0.12
0.047
«: 0.18
< 0.16
< 0.15
< 0.15
< 0.14
17.
1 1 .
20.
0.16
< 15.
0 . 89
1 .4
0.034
b. 0
< 9.1
600 .
< 4.0
< 16,
< 'J. 0
< 3.9
< 67,
< 0.19
< 0,0004
. 0.033
EMISSION
CAl CfJL A 1 EU
(MG/DSCM)
< 0.0084
0.019
0.0025
< 0.0017
<: 0.0074
< 0.0052
0.0020
< 0.0075
< 0.0066
< 0.0063
< O.OOfal
0.71
0.47
0.83
0 . 0 0 o 9
< 0.63
0.037
0 .ObO
0.0014
< 0.035
0.25
< 0.38
< 0.17
< 0.65
< 0.21
< 0 , 1 b
< 2.8
< 0.0081
< 0.0001
0.0014
-------
SITE ? 1 3 : WJ L U >i fc SA-IPLtD = 5O.1O DSC''
TABLE D-15.
SSMS DATA FOR DISTILLATE OIL
RECIPROCATING ENGINE (SITE 313)
ELtME.M
U
TH
bl
PH
TL
AU
IH
OS
Rt
ri
HF
LU
YH
EH
HlJ
T4
Gi)
E"J
MO
<-" CE
LA
riA
CS
I
TE
SN
CO
PO
HH
T FILTER
C A F C H
C'-'G)
< 0,0049
< 0.0047
0.0015
0.5 7
< 0.0042
< 0.0040
< 0 . Ou 4 )
< 0.0149
< 0 . ')': 48
< 1 1 . u 0 " 7
< 0 . 0 ij i o
< 0.0051
< 0.0045
< 0 . 0 0 4 4
< 0.0044
< 0.0044
< 0.0055
< 0.1/042
< u . 0 0 5 1
< 0.0041
H.ODIJ2
< 0.0001
< 0.0009
< 0.0004
< 0.28
< 0.00 'U
0.0005
^ < 0,0026
0 .0027
0.054
< 0.0025
< 0.0022
< U.0021
X Ail
K E S I N
< 0
< 0
< 0
0
< 0
< 0
< 0
< '.
< 0
< 0
< 0
< 1
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
< 0
0
c 0
0
n
0
< 0
< 0
MU)
.059
.058
. 05 1
.047
. 0 -to
in .4 3
.045
.041
.040
. il 49
.058
. 0 5 7
. 0 56
. 0 45
.044
. 4n
.045
. 0 1; 7 0
,011
. 02 7
. 1 9
.,26
CO"
SA
(
t 0
<: 0
< 0
0
c 0
c 0
c 0
c 0
c 0
c 0
< (J
c 0
< 0
c 0
c: 0
c o
c 0
< u
e: U
< 0
< 0
< 0
< 0
<: o
< 0
c 0
0
0
c 0
0
1
0
: 0
C 0
poar FE
<
-------
SITE Ji 3;
SA'-iPLh.!) - 30.10 DSCM
TABLE D-15 (Continued)
ELE.«E
HLI
MH
y
SR
se
AS
GE
G4
7 ;*l
cu
NI
cu
FE
M N
r i
TTS~
ro
0 *
CT> S
p
SI
AL
'IG
8
BE
LI
: M T f- [ L f F. R
CA I LM
(-IG)
< 0.0021 <
0.0081
< 0.0001 <
0.00/4 <
o . ouo i <
0 . (1 oO
i.i . 0008
< 0.011
< 0 . 0 U 1 1 <
0.012 <
< 0.0015 <
< 0.0010 <
1.8 <
0 . I 0 <
0 . 78
< 0 . U 0 6 5
3.5
< 0.057
0.030 <
0 . 'lOuH
< 0,0 oS
12. <
0.31 e
1 3.
"0.19 <
< 6 . 0 <
< 0.96 <
< 0.0005 <
< 3.8 <
< 0.13
< 0 . 0 0 0 1 <
< 0.0011 <
XAD
hESI «!
f-'G)
0.025
0.041
0,025
0.023
0. '122
0 , 00^8
0.18
0,074
0.057
0.018
0.017
1 . 3
2. '4
0.71
'i':**
0.085
0.0 ) 00
"1 0 .
( ; s
1 .8
0 . o5
1 .8
37.
0. 039
0. 00(12
0.014
COMPMSI Tfc
(MG)
< 0.016
0.052
< 0,015
< 0 . 0 1 0
< 0 .0 1 4
0,012
0 , 0 i.i 1 6
0.017
0.06
0.0033
< 0.011
< 0.011
1 .2
0.25
0,60
0.*2 5
0,0066
0 .0007
1 .5
0 . 45
310.
0.?7
0.05
1 . 1
< 1.7
0.042
< 0.0001
0,0018
tUTAL
SASS
C*G)
< 0.003
0.100
< 0.058
0.0079 TU 0.037
0.0001 TO 0.03&
0.12
0.012
0.19
0.46
0.015 I U 0.037
< 0.031
< 0.050
3. 1
0.39 10 2.4
2.1
0.053
260.
0.01
0.26
0.011
0,038
13.
0.66 T U 6.9
360 ,
0.06 TO 1.8
0.05 TO /.S
1,1
0,32 TO 1.8
<
-------
TABLE D-16. LEVEL II ORGANIC ANALYSIS RESULTS -
COMPOUNDS FOUND IN SAMPLE 309-2-XRPF-MRPR
Compound
Toluene
Xyl ene
Xyl ene
Xyl ene
C3 Cyclohexane
n-Cg Hydrocarbon
(Nonane)
Benzaldehyde
C3 Benzene
C3 Benzene
C3 Benzene
C,Q Branched
(Hydrocarbon)
C3 Benzene
C,0 Unsaturated
(Hydrocarbon)
n-C,n Hydrocarbon
iu (Decane)
C3 Benzene
Methyl Styrene
C,-, Branched
(Hydrocarbon)
C,, Branched
(Hydrocarbon)
C5 Cyclohexane
C3 Benzene
C3 Benzene
C. Benzene
Amount (pg/m )
*
14 f
56 f
30 f
54
38
48
24
110
100
46
320
78
220
86
20
16
34
12
96
100
140 f
- Continued -
Scan No.
5
45
50
65
69
78
111
118
127
136
154
169
179
199
209
226
233
240
247
267
274
282
Equal to or less than amount found in blank.
Corrected for blank concentration, amount actually present in
sample rather questionable due to blank level variations.
207
-------
TABLE D-16. (Continued)
Compound
C. Benzene
C. Benzene
C. Benzene
Methyl Benzoate
C,, Branched
(Hydrocarbon) .
C. Benzene
n-C,, Hydrocarbon
(Undecane)
C. Unsaturated
(Benzene)
Cg Benzene
Co Benzene
Cg Benzene
C- Benzene
C Benzene
D
Cg Benzene
Cg Benzene
Naphthalene
Cr- Benzene
O
C,p Branched
(Hydrocarbon)
C,p Branched
(Hydrocarbon)
C,2 Branched
(Hydrocarbon)
Cg Benzene
C,2 Unsaturated
Hydrocarbon
Amount (pg/m )
18 1
31Qt
loot
*
110
260 f
780
86
110
30
410
100
20
52
8
170 f
84
54
280
140
84
240
- Continued -
Scan No.
296
322
341
344
346
394
440
480
492
147
522
542
554
570
584
596
610
623
639
657
682
711
*
Equal to or less than amount found in blank.
Corrected for blank concentration, amount actually present in
sample rather questionable due to blank level variations.
208
-------
TABLE D-16. (Continued)
Compound Amount (yg/m3) Scan No.
h-Cj2 Hydrocarbon
(Dodecane)
Methyl Tetrahydronaphthalene
Cj3 Branched
(Hydrocarbon)
C,3 Unsaturated
Hydrocarbon
C,o Branched
Hydrocarbon
Cg Benzene
Cg Benzene
Cg Benzene
C,o Branched
Hydrocarbon
Methyl Naphthalene
C*3 Branched
Hydrocarbon
C,3 Branched
Hydrocarbon
Methyl Naphthalene
Unknown Substituted
Cyclohexane
Unknown
C,3 Unsaturated
Hydrocarbon
n-C,3 Hydrocarbon
(Tridecane)
C,, Branched
Hydrocarbon
Co Tetrahydronaphthalene
C.. Branched
1 Hydrocarbon
780
42
160
62
62
8
56
32
46
300
130
36
160
10
14
140
1000
12
28
68
752
763
789
798
807
817
825
852
891
906
918
932
939
957
964
973
1007
1024
1030
1041
- Continued -
209
-------
TABLE D-16. (Continued)
Compound
Unknown
Unknown
C3 Tetrahydronaphthalene
Unknown Substituted
Cyclohexane
Chloronaphthalene
Biphenyl
C-. , Branched
Hydrocarbon
C,. Unsaturated
Hydrocarbon
Cp Naphthalene
C,. Branched
Hydrocarbon
C, . Branched
Hydrocarbon
C2 Naphthalene
C,, Branched
Hydrocarbon
Cp Naphthalene
&2 Naphthalene
n-Cj, Hydrocarbon
(Tetradecane)
Unknown aromatic
Cp Naphthalene
Unknown Acid Ester
C15 Branched
Hydrocarbon
Cp Naphthalene
Unknown Aromatic
3
Amount (yg/m )
2
14
20
82
Internal Standard
Trace
74
18.
10
36
130
290
120
24
130
980
100
20
32
40
32
32
Scan No.
1047
1052
1064
1075
1083
1092
1113
1120
1126
1130
1142
1156
1171
1181
1186
1221
1229
1249
1260
1275
1291
1300
- Continued -
210
-------
TABLE D-16. (Continued)
Compound
C,5 Branched
Hydrocarbon
C,5 Branched
Hydrocarbon
C,5 Branched
Hydrocarbon
C^ Naphthalene -
C- Naphthalene
C., Naphthalene
Co Naphthalene
n-C,c Hydrocarbon
(Pentadecane)
Co Naphthalene
C3 Naphthalene
C3 Naphthalene
C,g Unsaturated Hydrocarbon
-C, Naphthalene
C,c Unsaturated Hydrocarbon
ID
C,,. Unsaturated Hydrocarbon
ID
C, Naphthalene
C,c Branched Hydrocarbon
lb
C. Naphthalene
C* Naphthalene
n-C,/- Hydrocarbon
lb (Hexadecane)
C17 Unsaturated Hydrocarbon
C, Naphthalene
n-C17 Branched Hydrocarbon
Methoxybiphenyl
r. Naohthalene
0
Amount (yg/m )
180
84
310
120
40
52
110
1000
38
130
140
68
120
40
70
82
96
40
110
990
90
78
58
48
32
Scan No.
1318
1334
1347
1357
1363
1379
1394
1420
1432
1439
1467
1483
1502
1513
1525
1534
1545
1571
1586
1604
1615
1630
1645
1663
1682
- Continued -
211
-------
TABLE D-16. (Continued)
Compound Amount (yg/m )
C,7 Branched Hydrocarbon
C,7 Branched Hydrocarbon
C-7 Branched Hydrocarbon
C,7 Branched Hydrocarbon
Cg Naphthalene
Cg Naphthalene
Cg Naphthalene
n-C17 Hydrocarbon
11 (Heptadecane)
C10 Branched Hydrocarbon
lo
C3 Biphenyl
Phenanthrene (or Isomer)
Unknown
' C Naphthalene
Unknown Substituted
Cyclohexane
C,g Branched Hydrocarbon
C,g Branched Hydrocarbon
C,g Branched Hydrocarbon
Ethyl Fluorene (or Isomer)
n-C,o Hydrocarbon
10 (Octadecane)
C,g Unsaturated
Hydrocarbon
Methyl phenanthrene (or Isomer)
C,g Branched Hydrocarbon
n~C1Q Hydrocarbon
190
26
62
100
34
20
52
820
400
16
94
16
14
76
46
48
56
24
650
170
86
66
490
Scan No.
1695
1709
1720
1735
1749
1763
1778
1806
1822
1837
1852
1867
1881
1901
1911
1930
1945
1955
2007
2028
2088
2123
2192
(Nonadecane)
Branched Hydrocarbon
42
2263
- Continued -
212
-------
TABLE D-16. (Continued)
Compound
Pyrene (or Isomer)
n-C9n Hydrocarbon
^u (Eicosane)
n-C21 Hydrocarbon
(Heneicosane)
n-Coo Hydrocarbon
(Docosane)
Dioctylphthalate
Amount (yg/m )
Trace
310
130
76
(a)
Scan No.
2301
2360
2524
2677
3080
*
Equal to or less than amount found in blank,
213
-------
TABLE D-17. LEVEL II ORGANIC ANALYSIS RESULTS -
COMPOUNDS FOUND IN SAMPLE #309-2-CD-LE
Compound
Benzene
n-Cy Hydrocarbon (Heptane)
Methyl Cyclohexane
Toluene
Unknown Unsat. Hydrocarbon
Silicone
Naphthalene
Silicone
n-C-|2 Hydrocarbon (Dodecane)
Methyl Naphthalene
Methyl Naphthalene
n-C,o Hydrocarbon (Tridecane)
Chloronaphthalene
Silicone
H-C,, Hydrocarbon (Tetradecane)
n-C,r Hydrocarbon (Pentadecane)
Dichloronaphthalene
Trimethyl naphthalene
Silicone
n-C,g Hydrocarbon (Hexadecane)
C,y Branched Hydrocarbon
n-C,y Hydrocarbon (Heptadecane)
C,g Branched Hydrocarbon
Silicone
o
Amount (yg/m )
*
1
*
*
0 .5
1
0 .5
3
0 .2
0 .2
0 .2
0 .6
Internal Standard
15
2
2
I.S. Impurity
1
38
3
1
16
2
2
- Continued
Scan No.
20
32
44
68
395
517
841
894
944
1078
1115
1178
1278
1307
1418
1628
1649
1656
1683
1818
1911
1994
2012
2090
-
*
Equal to or less than amount found in blank.
214
-------
TABLE D-17. (Continued)
Compound Amount (yg/m )
n-C18 Hydrocarbon (Octadecane)
C,g Branched Hydrocarbon
Sili cone
n-C,g Hydrocarbon (Nonadecane)
Dibutylphthalate
n-C?Q Hydrocarbon (Eicosane)
Sili cone
Sili cone
n-Cp-i Hydrocarbon (Heneicosane)
Sili cone
Sili cone
Sili cone
Dioctylphthalate
Sili cone
Sili cone
Sili cone
4
1
10
2
1
1
5
6
0.5
6
5
6
3
11
9
19
Scan No.
2158
2179
2261
2314
2337
2465
2486
2501
2610
' 2727
2935
3132
3154
3321
3400
3445
215
-------
TABLE D-18. LEVEL II ORGANIC ANALYSIS RESULTS -
COMPOUNDS FOUND IN SAMPLE #312-2-XRPF-MRPR
Compound
Benzene
Methyl cycl ohexane
Toluene
Xylene
Xylene
Xylene
Cyclohexane
Cg Unsat. Hydrocarbon
n-Cg Hydrocarbon CNonane)
GO Benzene
Cyclohexane
Benzaldehyde
C,Q Branched Hydrocarbon
C,Q Branched Hydrocarbon
C3 Benzene
C3 Benzene
C3 Benzene
C-JQ Branched Hydrocarbon
C,Q Branched Hydrocarbon
C3 Benzene
C,Q Unsat. Hydrocarbon
C^Q Unsat. Hydrocarbon
C» Benzene
H-C-.Q Hydrocarbon (Decane)
C. Benzene
Dihydroindene
Amount (pg/m )
*
*
*
24
54
26
26
24
66
18
26
12
38
4
80
42
44
30
32
120
62
60
18
250
22
15
- Continued
Scan No.
20
40
64
163
175
207
216
226
245
261
285
299
306
318
325
341
357
362
374
386
392
409
420
437
445
459
-
Equal to or less than amount found in blank.
216
-------
TABLE D-18. (Continued)
Compound -
Unknown
C,.j Branched Hydrocarbon
C-|.j Unsat. Hydrocarbon
C. Benzene
C^ Benzene
C. Benzene
C. Benzene
C,.| Branched Hydrocarbon
Methyl Benzoate
C,, Unsat. Hydrocarbon
C,-, Branched Hydrocarbon
0,-j Branched Hydrocarbon
C-,-, Branched Hydrocarbon
C, , Unsat. Hydrocarbon
/n-C,-, Hydrocarbon (Undecane)
Decahydronaphthalene, 2-Methyl
Cg Benzene
Cr Benzene
Cj- Benzene
Cc Benzene
D
Naphthalene
C,? Branched Hydrocarbon
C,2 Branched Hydrocarbon
C-,2 Branched Hydrocarbon
C12 Branched Hydrocarbon
Amount (yg/m
12
72
18
48f
62 f
28 1
25-*-
12
*
80
110
160
80
160
570
44
38
180
14
22
58 t
86
34
162
64
3) Scan No.
467
484
495
506
515
521
534
542
547
557
560
570
581
616
647
671
681
702
716
734
752
761
769
781
792
Continued -
* Equal to or less than amount found in blank.
"*" Corrected for blank concentration. Amount actually present
in sample rather questionable due to blank level variations
217
-------
TABLE D-18. (Continued)
Compound Amount (yg/m )
C5 Benzene
Cg Benzene
n-C-|p Hydrocarbon (Dodecane)
Cc Benzene
b
Cg Benzene
C,3 Branched Hydrocarbon
Methyl Tetrahydronaphthalene
C,3 Branched Hydrocarbon
Methylnaphthalene
Methyl naphthalene
n-C,3 Hydrocarbon (Tridecane)
36
no
400
10
12
114
96
62
330
240
470
Chloronaphthalene Internal Standard
Cp Unsat. Naphthalene
Cp Naphthalene
C2 Naphthalene
Cp Naphthalene
Cp Naphthalene
H-C,» Hydrocarbon (Tetradecane)
Cp Naphthalene
Cp Naphthalene
C3 Unsat. Naphthalene
C,5 Unsat. Hydrocarbon
.n-C-,r Hydrocarbon (Pentadecane)
C3 Naphthalene
C3 Naphthalene
C,g Branched Hydrocarbon
C3 Naphthalene
20
22
130
82
350
440
140
54
78
170
490
44
72
60
72
Scan No.
810
831
859
870
881
888
939
970
989
1015
1071
1152
1158
1190
1219
1227
1247
1274
1279
1305
1366
1392
1459
1484
1544
1560
1575
- Continued -
218
-------
TABLE D-18. (Continued)
o
Compound Amount (yg/m )
C16 Branched Hydrocarbon
n-C16 Hydrocarbon (Hexadecane)
C,y Branched Hydrocarbon
C-.-J Branched Hydrocarbon
n-C-jy Hydrocarbon (Heptadecane)
C,,, Unsat. Hydrocarbon
Phenanthrene (or isomer)
Phenanthrene (or isomer)
n-C-,0 Hydrocarbon (Octadecane)
lo
C,g Branched Hydrocarbon
Methyl phenanthrene (or isomer)
n-C,g Hydrocarbon (Nonadecane)
n-C2Q Hydrocarbon (Eicosane)
n-Cp-, Hydrocarbon (Heneicosane)
Dioctylphthalate
120
350
48
190
260
200
28
10
220
100
22
200
100
66
42 +
Scan No.
1619
1634
1663
1723
1809
1825
1862
1867
1973
1993
2062
2135
2288
2435
2948
219
-------
TABLE D-19. LEVEL II ORGANIC ANALYSIS RESULTS -
COMPOUNDS FOUND IN SAMPLE 312^2-CD-LE
Compound
o
Amount (yg/m )
Scan No.
Benzene
Methyl Cyclohexane
Toluene
Chloronaphthalene
H-C,4 Hydrocarbon
(Tetradecane)
n-C15 Hydrocarbon
(Pentadecane)
n-C1fi Hydrocarbon
iD (Hexadecane)
C,7 Branched Hydrocarbon
n~C17 Hydrocarbon
(Heptadecane)
C,g Branched Hydrocarbon
n-C,g Hydrocarbon
(Octadecane)
C,Q Branched Hydrocarbon
n-Cig Hydrocarbon
(Nonadecane)
n"C20 Hydrocarbon
(Eicosane)
n"C21 Hydrocar^on
(Heneicosane)
n-Cpo Hydrocarbon
(Docosane)
Dioctylphthalate
*
*
*
Internal Standard
1
2
4
1
6
2
6
2
4
2
2
Trace
6
23
42
58
111
1247
1451
1636
1731
1811
1828
1977
1997
2133
2288
2438
2582
2983
K
Equal to or less than amount found in blank.
Trace - Detected but too low to quantitate (0.05 - 1.0 ng/m )
220
-------
TABLE D-20.
LEVEL II ORGANIC ANALYSIS RESULTS -
COMPOUNDS FOUND IN SAMPLE #313-2-XRPF-MRPR
Compound
Benzene
Methyl cyclohexane
Toluene
Cg Unsat. Hydrocarbon
C~ Benzene
^2 Benzene
Cg Branched Hydrocarbon
&2 Benzene
C3 Cyclohexane
Cg Unsat. Hydrocarbon
n-Cg Hydrocarbon (Nonane)
Cn Benzene
C. Cyclohexane
C,Q Branched Hydrocarbon
C,0 Branched Hydrocarbon
Co Benzene
Co Benzene
C-|0 Unsat. Hydrocarbon
C3 Benzene
C,Q Unsat. Hydrocarbon
Co Benzene
n-C,Q Hydrocarbon (Decane)
Co Benzene
C. Benzene
C-,-, Branched Hydrocarbon
C,., Unsat. Hydrocarbon
Amount (yg/m )
*
*
*
16
38
110
12
56
62
64
170
38
48
240
200
76
66
44
320
T50
34
250
30
40
140
40
- Conti
Scan No.
23
43
69
100
172
184
198
215
224
234
253
271
294
315
339
351
370
387
399
423
435
450
454
458
499
510
nued -
Equal to or less than amount found in blank,
221
-------
TABLE D-20. (Continued)
Compound Amount (yg/m ) Scan No.
C. Benzene
C. Benzene
C. Benzene
C. Benzene
Methyl benzoate
C. Benzene
C. Benzene
C, , Unsat. Hydrocarbon
C,-, Branched Hydrocarbon
C, ^ Unsat. Hydrocarbon
n-C,-, Hydrocarbon (.Undecane)
C-J2 Branched Hydrocarbon
Cg Benzene
C5 Benzene
Cg Benzene
Naphthalene
C,2 Unsat. Hydrocarbon
Cp Indene
C? Indene
C-J2 Unsat. Hydrocarbon
n-C, 2 Hydrocarbon (Dodecane)
C-,., Unsat. Hydrocarbon
C, ., Branched Hydrocarbon
E *3
Unknown Substituted Cyclohexane
Tetrahydromethyl Naphthalene
"C,, Branched Hydrocarbon
*
Equal to or less than amount found
t
78 f
128f
40 f
34 f
*
lot
190
290
120
630
950
140
22
42
68
220 1
66
150
66
340
680
200
66
80
150
120
-
in blank.
522
531
538
552
556
559
578
589
601
638
668
704
725
736
766
778
793
803
814
853
881
910
925
940
955
991
Continued -
in sample rather questionable due to blank level variations
222
-------
TABLE D-20. (Continued)
Compound Amount (yg/m )
Methylnaphthalene
C-|3 Unsat. Hydrocarbon
C-|3 Unsat. Hydrocarbon
Methylnaphthalene
C-|3 Unsat. Hydrocarbon
&2 Tetrahydronaphthalene
n-C13 Hydrocarbon (Tridecane)
450
120
328
140
48
82
810
Chloronaphthalene Internal Standard
Biphenyl
C.J4 Branched Hydrocarbon
C2 Naphthalene
C,. Branched Hydrocarbon
Cp Naphthalene
C,. Branched Hydrocarbon
Cp Naphthalene
n-C,. Hydrocarbon (Tetradecane)
C2 Naphthalene
Unknown
C~ Naphthalene
C,5 Branched Hydrocarbon
C,g Branched Hydrocarbon
Methyl Biphenyl
Methyl Biphenyl
C,r Branched Hydrocarbon
1 0
C3 Naphthalene
C3 Naphthalene
n-C,5 Hyorocarbon (Pentadecane)
36
130
150
160
210
150
560
840
20
76
150
54
140
120
30
350
180
150
1000
Scan No.
1011
1027
1036
1042
1061
1072
1088
1170
1174
1190
1207
1216
1234
1246
1263
1291
1298
1307
1322
1353
1366
1383
1399
1411
1424
1468
1483
- Continued -
223
-------
TABLE D-20. (Continued)
. O
Compound Amount (yg/m )
C3 Naphthalene
Co Naphthalene
C3 Naphthalene
C,g Branched Hydrocarbon
Methyl Biphenyl
Unknown
Alkyl Subst. Cyclopentanedione
n-C,r Hydrocarbon (Hexadecane)
C. Naphthalene
C,7 Hydrocarbon Branched
,C,7 Hydrocarbon Branched
C,7 Unsat. Hydrocarbon
n-C,7 Hydrocarbon (Heptadecane)
C,g Unsat. Hydrocarbon
* Phenanthrene (or Isomer)
n-C,o Hydrocarbon (Octadecane)
C,Q Branched Hydrocarbon
Methylphenanthrene (or isomer)
n~C19 Hydrocarbon (Nonadecane)
n-CpQ Hydrocarbon (Eicosane)
Pyrene (or isomer)
n-C?1 Hydrocarbon (Heneicosane)
n-Cp2 Hydrocarbon (Doeicosane)
Dioctylphthalate
130
120
92
140
130
100
160
690
28
410
98
100
540
500
92
580
260
Trace
490
360
Trace
210
no
1200 t
Scan No.
1512
1533
1571
1586
1600
1630
1645
1665
1746
1758
1775
1821
1834
1855
1893
2009
2028
2088
2169
2321
2410
2470
2616
3013
Corrected for blank concentration. Amount actually present
in sample rather questionable due to blank level variations.
2
Trace - Detected but too low to quantitate (0.05 - 1.0 yg/m ).
224
-------
TABLE D-21. LEVEL II ORGANIC ANALYSIS RESULTS -
COMPOUNDS FOUND IN SAMPLE 313-2-CD-LE
Compound Amount ((ug/m ) Scan No.
Benzene * 27
Methylcyclohexane * 45
Toluene * 92
Chloronaphthalene Internal Standard 1259
C 14 Branched Hydrocarbon 2 1541
n-C ,. Hydrocarbon 2 1582
(Tetradecane)
n-C 15 Hydrocarbon 2 1765
(Pentadecane)
n-C ,6 Hydrocarbon 2 1938
(Hexadecane)
C ,7 Branched Hydrocarbon 2 1957
n-C 1? Hydrocarbon 1 2107
(Heptadecane)
n-C ,8 Hydrocarbon 2 2270
(Octadecane)
Dioctylphthalate 22 ' 3188
Equal to or less than amount found in blank.
225
-------
METRIC CONVERSION FACTORS AND PREFIXES
To convert from
Degrees Celsius (°C)
Joule (J)
Kilogram (kg)
Kilojoule/kilogram (kj/kg)
Megagram (Mg)
Megawatt (MW)
Meter (m)
Meter3 (m3)
Meter3 (m3)
Meter (m )
Nanogram/joule (ng/J)
Picogram/joule (pg/J)
CONVERSION FACTORS
To
Degrees Fahrenheit (°F)
Btu
Pound-mass (avoirdupois)
Btu/lbm
Ton (2000 IbJ
Horsepower (HP)
Foot (ft)
Barrel (bbl)
O -3
Foot"
Gallon (gal)
lbm/million Btu
Ib /million Btu
Multiply by
,-1
t(°F) = 1.8 t(°C) + 32
9.478 x 10"4
2.205
4.299 x 10"
1.102
1.341 x
3.281
6.290
3.531 x 10
2.642 x 10'
2.326 x 10
2.326 x 10
1
-3
-6
Prefix
Peta
Tera
Giga
Mega
Kilo
Mil 11
Micro
Nano
Pico
P
T
G
M
k
m
y
n
P
Symbol
PREFIXES
Multiplication
Factor
Example
1
1
1
1
1
0
0
0
0
0
10
1
1
1
0
0
0
15
12
9
6
3
-3
-6
-9
-12
1
1
1
1
1
1
1
1
1
Pm =
Tm =
Gm =
Mm =
km =
mm =
ym =
nm =
pm =
1
1
1
1
1
1
1
1
1
x
x
X
X
X
X
X
X
X
10
10
10
10
10
10
10
10
ro
15 .
meters
12
1 t_
9
6
3
meters
meters
meters
meters
meter
-6
-9
-1
meter
meter -
meter
226
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
HEPORT NO '
EPA-600/7-79-029c
3. RECIPIENT'S ACCESSION NO.
4 T1TLE AND SUBTITLEEmissions Assessment of Conventional
Stationary Combustion Systems; Volume II. Internal
Combustion Sources
5. REPORT DATE
February 1979
|6. PERFORMING ORGANIZATION CODE
C.C.Shih, J.W.Hamersma, D.G. Ackerman,
R.G.Beimer, M.L.Kraft, and M.M.Yamada
8. PERFORMING ORGANIZATION REPORT NO.
7 . . **.j. c*j. t, , CCiiVl A»JL . -LV.
ORMING ORGANIZATION NAME AND ADDRESS
TRW, Inc.
One Space Park
Redondo Beach, CA 90278
10. PROGRAM ELEMENT NO.
EHE624A
11. CONTRACT/GRANT NO.
68-02-2197
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Final; 9/76 - 1/79
14. SPONSORING AGENCY CODE
EPA/600/13
15 SUPPLEMENTARY NOTES JERL-RTP project officer is Ronald'A. Venezia, MD-62, 919/541-
2547.
16. ABSTRACT
The report gives results of an assessment of emissions from gas- and oil-
fueled gas turbines and reciprocating engines for electricity generation and indus-
trial applications. The assessment involved a critical examination of existing emis-
sions data, followed by a measurement program to fill data gaps based on a phased
sampling and analysis strategy. In the first phase of the measurement program, a
gas-fueled gas turbine, five distillate-oil-fueled gas turbines, and five diesel eng-
ines were tested. Evaluation of test results led to the recommendation for additional
tests to determine SOS and organic emissions from diesel engines which were subse-
quently conducted on three of the diesel engines previously tested. Assessment re-
sults indicate that internal combustion (1C) sources contribute significantly to the
national emissions burden. NOx, hydrocarbon, and CO emissions from 1C sources
account for approximately 20, 9, and 1%, respectively, of the emissions of these
pollutants from all stationary sources. The sources severity factor (the ratio of the
calculated maximum ground level concentration of the pollutant species to the level
at which a potential environmental hazard exists) was used to identify pollutants of
environmental concern.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b. IDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Pollution Measurement
Gas Turbines Nitrogen Oxides
Diesel Engines Hydrocarbons
Reciprocating Engines
Electric Power Generation
Industrial Plants Carbon Monoxide
Trioxide Organic Compounds
Pollution Control
Stationary Sources
13B
13G
21G
10A
131
14 B
07B
07C
R I EfUTION STATEMENT
Unlimited
19. SECURITY CLASS (This Report)
Unclassified
21. NO. OF PAGES
239
20. SECURITY CLASS (This page)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
227
------- |