EPA
United States
Environmental Protection
Agency
Office of Environmental Sciences Research
Research and Laboratory
Development Research Triangle Park, North Carolina 27711
EPA-600/7-77-104
September 1977
LITERATURE SURVEY OF
EMISSIONS ASSOCIATED WITH
EMERGING ENERGY
TECHNOLOGIES
Interagency
Energy-Environment
Research and Development
Program Report
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RESEARCH REPORTING SERIES
Research reports of the Office of Research and Development, U.S. Environmental
Protection Agency, have been grouped into seven series. These seven broad categories
were established to facilitate further development and application of environmental
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are:
1. Environmental Health Effects Research
2. Environmental Protection Technology
3. Ecological Research
4. Environmental Monitoring
5. Socioeconomic Environmental Studies
6. Scientific and Technical Assessment Reports (STAR)
7. Interagency Energy-Environment Research and Development
This report has been assigned to the INTERAGENCY ENERGY-ENVIRONMENT
RESEARCH AND DEVELOPMENT series. Reports in this series result from the effort
funded under the 17-agency Federal Energy/Environment Research and Development
Program. These studies relate to EPA's mission to protect the public health and welfare
from adverse effects of pollutants associated with energy systems. The goal of the
Program is to assure the rapid development of domestic energy supplies in an environ-
mentally-compatible manner by providing the necessary environmental data and
control technology. Investigations include analyses of the transport of energy-related
pollutants and their health and ecological effects; assessments of, and development
of, control technologies for energy systems; and integrated assessments of a wide
range of energy-related environmental issues.
REVIEW NOTICE
This report has been reviewed by the participating Federal Agencies, and approved
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This document is available to the public through the National Technical Information
Service, Springfield, Virginia 22161.
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EPA-600/7-77-104
September 1977
LITERATURE SURVEY OF EMISSIONS ASSOCIATED WITH
EMERGING ENERGY TECHNOLOGIES
by
J. E. Sickles, II
W. C. Eaton
L. A. Ripperton
R. S. Wright
Research Triangle Institute
Research Triangle Park, North Carolina
EPA Contract 68-02-2258
Joseph J. Bufalini
Environmental Sciences Research Laboratory
U.S. Environmental Protection Agency
Research Triangle Park, North Carolina 27711
ENVIRONMENTAL SCIENCES RESEARCH LABORATORY
OFFICE OF RESEARCH AND DEVELOPMENT
U.S. ENVIRONMENTAL PROTECTION AGENCY
RESEARCH TRIANGLE PARK, NORTH CAROLINA 27711
EPA - RTF LIBRARY
-------
DISCLAIMER
This report has been reviewed by the Environmental Sciences Research
Laboratory, U.S. Environmental Protection Agency, and approved for pub-
lication. Approval does not signify that the contents necessarily re-
flect the views and policies of the U.S. Environmental Protection Agency,
nor does mention of trade names or commercial products constitute
endorsement or recommendation for use.
ii
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ABSTRACT
A literature survey was conducted to address fuel contaminants and atmos-
pheric emissions from the following energy-related operations: coal gasifica-
tion, coal liquefaction, shale oil production, and petroleum refining.
Sulfur and nitrogen found in coal, coal liquid product, shale oil, and
petroleum crude are, for the most part, organically bound. Only coal was
found to have substantial amounts of inorganic contaminants, and this was as
pyrite (FeS-). The sulfur content of most fuels is less than 5 percent and
occurs as thiols (mercaptans), sulfides, disulfides, and thiophenes. Nitrogen
is usually reported at less than 2 percent and occurs as pyridines, pyrroles,
indoles, carbazoles, and benzamides.
Quantitative estimates of criteria air pollutant emissions from energy-
related operations are tabulated. A broad spectrum of sulfur-containing
compounds, nitrogen-containing compounds, and hydrocarbons has been identified
from analyses of intermediate process streams and final products from fuel
conversion processes. The surveyed literature provides a basis for identifying
the major emissions. The same or similar species are expected to be emitted
from each fuel conversion facility. These compounds are listed as follows:
Sulfur-containing compounds will include S02> H2S, thiols,
sulfides, and thiophenes.
Nitrogen-containing compounds will include NO, N0?, NH,, HCN, and
heterocycles.
• Organic compounds will include primarily.volatile hydrocarbons up
to C10. Other organics such as aldehydes, ketones, phenols, and
POM are expected. The carcinogenicity of various POM presents an
additional airborne hazard.
The extent to which any of these species is released to the atmosphere depends
to a large degree on currently undefined processing details.
This report was submitted in fulfillment of Task A of Contract No. 68-02-
2258 by the Research Triangle Institute under the sponsorship of the U.S.
Environmental Protection Agency. This report covers a period from June 30,
1975, to June 30, 1977, and work was completed as of December 31, 1976.
iii
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CONTENTS
Abstract iii
Figures vi
Tables vii
1. Introduction 1
Purpose 1
Organization 1
Background 2
2. Fuel Contaminants 4
Coal 5
Coal liquid 8
Shale oil 11
Petroleum crude 12
Overview 16
3. Emissions From Fuel Conversion Facilities 17
Gasification 17
Liquefaction 31
Shale oil production 39
Petroleum refining 46
Overview 5%
References 62
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FIGURES
Number Page
1 Frequency distribution of sulfur content in crude oils of U.S.
giant oil fields 13
2 Frequency distribution of nitrogen content in crude oils of U.S.
giant oil fields 15
3 Generalized coal gasification scheme ...... 20
4 Lurgi gasifier 21
5 Generalized coal liquefaction scheme 36
6 TOSCO II process 42
7 Generalized shale oil production scheme 44
8 Generalized flow diagram for a representative U.S. petroleum
refinery 49
vi
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TABLES
Number Page
1 Synthetic fuel plants recommended for project independence .... 3
2 Elemental analysis of typical fuels 5
3 Distribution of S and N contaminants in fuels 6
4 Approximate values of some coal properties in different rank
ranges 7
5 Selected organic sulfur compounds present in coal products .... 9
6 Properties of coal liquefaction products and of parent coal ... 10
7 Composition of total .aromatic fraction of liquid coal ...... H
8 Nitrogen, and sulfur in selected crude oils -14
9 Nitrogen compounds in petroleum 16
10 Coal gasification processes IB
11 Gasifier descriptions and operating conditions - 19
12 Estimated synthetic gas and measured natural gas analyses .... 24
j 13 Expected analyses of raw, dry gas from gasifiers (after quenching) 25
14 Reported analyses of raw gas from pilot and commercial gasification
facilities 26
15 Potential pollutants from gasification operations 27
16 Analytical test plan for gaseous emissions from a Lurgi gasifica-
tion facility 29
17 Comparison of emissions estimates for 250 x 10 SCFD Lurgi-based
coal gasification plants 30
18 Summary of estimated hydrocarbon emissions for a 250 x 10 SCFD
gasification plant . 3°
vfi
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Number Page
19 Regulations for coal gasification plants 32
20 Coal liquefaction processes 33
21 Descriptions and operating conditions for four selected lique-
faction processes 34
22 Gas analyses from liquefaction processes 38
23 Analytical test plan for gaseous emissions from a COED coal
processing facility 40
24 Typical gas retort analyses 43
25 Emission rates for 100,000 BPD TOSCO II facility with emissions
controlled with best available technology 45
26 Comparison of emissions estimates for 100,000 BFD TOSCO II
facility 45
27 Maximum hydrocarbon emission estimates (-lb/hr) for 100,000 BPD
TOSCO II facility 47
28 Atmospheric emissions from process modules in a gasoline refinery
and a fuel oil refinery 51
29 Reported composition of product streams from three refinery
operations 53
30 Classes and numbers of components identified in refinery streams 57
31 Potential sources of atmospheric emissions from fuel conversion
facilities 59
32 Estimated atmospheric emissions from fuel extraction and
conversion operations on a basis of 3,0^ Btu/day output .... 60
vlli
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SECTION 1
INTRODUCTION
PURPOSE
The growing demand for energy coupled with the shortage of domestic gas
and liquid fuels has resulted in the emergence of new processes and tech-
nologies aimed at producing energy from domestically available fossil fuels.
The ultimate goal must be to meet the increasing energy demand in environ-
mentally acceptable ways. Operations such as coal gasification and lique-
faction, shale oil production, and petroleum refining will assume an increased
role in future energy production. It is therefore necessary to assess the
potential impact of these processes on air quality.
The purpose of this task is to perform a literature survey to gather
information on the composition and rates of emissions of organic, nitrogen-
containing and sulfur-containing constituents from the following types of
energy-related operations:
1. Coal gasification,
2. Coal liquefaction,
3. Shale oil production, and
4. Petroleum refining.
ORGANIZATION
This report is organized into three sections. The first section is an
overall introduction to the report.
The second section deals with fuel contaminants in coal, coal liquefaction
products, stiale oil, and petroleum. A discussion is presented on the relative
amounts and the chemical form of sulfur and nitrogen in each type of fuel.
The third section provides a brief description of each of the four classes
of conversion processes. Emissions estimates are summarized and, as the
literature permits, the identities and concentrations of compounds associated
with the various processes are tabulated.
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BACKGROUND
The United States depends on coal, petroleum liquids, petroleum gases,
hydroelectric!ty, and nuclear power for 99 percent of its energy (ref. 1).
Petroleum and natural gas supply approximately 75 percent of this requirement.
These fuels are in short supply and are projected to decline rapidly in the
face of a growing demand, which has pushed U.S. dependence on foreign oil
from 25 percent of the domestic oil consumption in 1973 during the peak of the
"energy crisis" to 40 percent by mid-1976. Fortunately, the United States has
an abundant supply of coal, which is in excess of 600 billion tons of remaining
mineable reserves and over 3,200 billion tons of total coal resources. Domes-
tic coal reserves, compared to reserves of other fuels, are five times the
shale reserves, over 13 times the oil reserves, and almost 19 times the
natural gas reserves (ref. 2). It is, therefore, understandable that new
emphasis is being placed on the development of technologies for the
environmentally acceptable utilization of coal. These technologies include
improved mining techniques, coal gasification, coal liquefaction, shale oil
production, and improved techniques for fuel combustion and power generation.
Coal utilization is expected to double between 1975 and 1985. The Federal
Power Commission estimates that coal gasification plants will supply 0.3 x 10
Btu by 1980 and approximately 3.2 x 10 Btu by 1990 (ref. 3). This translates
into 36 coal gasification plants producing 250 x 10 CFD of high Btu substitute
natural gas (SNG) by 1990. In addition, if the goals of Project Independence
are to be met, the 41 energy facilities listed in Table 1 must be built
immediately, and as many as 165 synthetic fuel plants will be required by 1985
to compensate for decreasing domestic natural gas supplies and to reduce the
dependence on imported oil. The resulting environmental impact of this number
of facilities could be substantial, even with environmental controls.
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TABLE 1. SYNTHETIC FUEL PLANTS RECOMMENDED FOR
PROJECT INDEPENDENCE (REF. 3)
Number of plants Product Quantity (per plant)
16 Low-Btu gas from coal as fuel 800-1,000 MW
for power generation of electricity
12 High-Btu gas from coal 250 x 106 CFDa
6 Syn-crude, motor fuel, clean 100,000 BPD
distillate fuel oils, and/
or deashed coal from coal
5 Shale oil 100,000 BPD
2 Fuel grade methyl alcohol 20,000 TPD
™* from coal
Total 41
c
fcED « cubic feet per day.
BPD = barrels per day.
TPD = tons per day.
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SECTION 2
FUEL CONTAMINANTS
The technology for coal liquefaction and shale oil production is poorly
defined. Although commercial coal gaaifiers are in operation outside this
country, no large-scale commercial domestic facilities are operating at
present. The identity and rates of gaseous emissions from these processes are
often based on pilot or demonstration plant operations and are all too
frequently based on no more than engineering estimates. While petroleum-
refining technology is well defined, reported emissions rates and compositions
are limited. The literature has, at best, revealed pollutant emissions
estimates for five of the criteria pollutants: particulates, SO., CO, hydro-
carbons, and NO . In view of this significant data gap, the literature was
3C
further examined for information on the molecular form of sulfur and nitrogen
contaminants in various raw and refined fuels. An understanding of the
chemical form of fuel contaminants may provide a better basis for gaining
insight into the transformations of the contaminants and the form of the
resulting emissions from various conversion processes.
Coal, liquid coal product, shale oil, and petroleum crude oil contain
three types of contaminants: sulfur, nitrogen, and trace elements. This
discussion will be limited to the sulfur and nitrogen compounds. The primary
source for the information in this section is a review of fuel contaminant
literature by Mezey et al. (ref. 4).
Table 2 illustrates typical elemental analyses of eight selected fuels
and allows a comparison of their sulfur and -nitrogen content. Table 3 provides
a breakdown of the qualitative distribution of sulfur and nitrogen in fuels
and allows a comparison with other fuels. This suggests that a portion of the
sulfur and most of the nitrogen originate from organic sulfur and nitrogen
compounds common to all fuels.
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TABLE 2. ELEMENTAL ANALYSIS OF TYPICAL FUELS (EEF. 4)
Coal (mf)
Subb it uminous
(Big Horn)
Bituminous
(Pittsburgh)
Coal liquids
(Big Horn)
(Pittsburgh)
Shale oil
Petroleum crude
(Pennsylvania)
Residual oil3
Distillate oila
C
69.2
78.7
89.2
89.1
80.3
85-
86.8
86.9
H
4.7
5.0
8.9
8.2
10.4
14
12.5
13.1
Weight
0-
17.8
6.3
1.03
1.5
5.9
1
0
0
percent
N
1.2
1.6
0.4
0.8
2.3
1
0.22
0.02
S
0.7
1.7
0.04
0.2
1.1
1
0.89
0.10
Ash (atomic)
6.5 0.81
6.9 0.76
>1 1.20
>1 1.10
1.55
<1 1.98
0.03 1.76
<0.002 1.81
*Ref. 5
COAL
Complex hypothetical molecular structures have been proposed for coal
(ref. 4). These models illustrate the predominantly aromatic character of
coal. Table 4 summarizes selected typical chemical and physical properties
for the major rank classes of coal. The aromatic character of coal increases
with rank. Other parameters such as sulfur, nitrogen, and mineral-matter
contents, and type of mineral matter do not vary systematically with rank.
Coal is a complex material and may be viewed as a warehouse for myriad
organic species. Lowry (ref. 9) has listed 348 compounds, and Anderson and Wu
(ref. 10) have provided data on 832 compounds identified in the products of
coal carbonization. More recently (ref. 11) 133 compounds consisting of
t
paraffins, olefins, and neutral heterocycles were identified in low-temperature
bituminous coal tar.
Sulfur is present in coal as both organic and inorganic species. The
inorganic sulfur occurs as pyritic or sulfide sulfur and as sulfate sulfur.
Although these figures are highly variable, approximately half the total sulfur
in coal occurs as pyritic sulfur while sulfate typically accounts for only
0.1 percent.
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TABLE 3. DISTRIBUTION OF S AND N CONTAMINANTS IN FUELS (REF. 4)
Contaminant
Type and source
Sulfur, total
Inorganic
Pyrites
Organic
Thiole (mercaptaha)
Sulfldes
Thlophenes
Benzo thiophene a
Mitrogen. total
Basic
PyrldineB
Qulnollnea
Acridlnes
Nonbaslc
Pyrroles
Indolea
Carbazolee
Benzamidea
Parent
structure Coal
0.4-13%
FeS2 X C'd
R-SH* X£
R-S-Re X£
X£
x£
1-2.1%
xf
x£
x£
x£
x£
x£
x£
Fuel
Coal
liquids
primary
<1%
X
X
X
>1X
X
X
X
X
X
X
X
Shale
0.6-1. IX
Xb
Xb
X
X
1.1-2.3*
xb
X
X
X
X
X
Petrolem
crude
0.1-5%
X
X
X
X
«1%
X
X
X
X
X
X
^Colorado shale oil and fractions.
bKefa. 4,6. and 7.
C4B percent of total sulfur, a mean
value for U.S. coals.
''Represents the presence of the
contaminant in the fuels.
eR Is an alkyl or aryl group.
'inferred from studies on coal tar,
depolymerized coal, and liquefied coal.
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TABLE 4. APPROXIMATE VALUES OF SOME COAL PROPERTIES IN DIFFERENT RANK RANGES (REF. 8)
% C (min. matter free)
% 0
% 0 as COOH
% 0 as OH
Aromatic C atoms
% of total C
Avg. no. benzene rings/
layer
Volatile matter, %
Reflectance, %
(vitrlnite)
Density
% N (ref. 4)
Lignite
65-72
30
13-10
15-10
50
1-2
40-50
0.2-0.3
1.0
Subbitu-
minous
72-76
18
5-2
12-10
65
?
35-50
0.3-0.4
1.2-1.7
High vol. bituminous
C
76-78
13
0
9
?
ta*_—i
35-45
0.5
1.6-2.1
B
78-80
10
0
?
,
?
2-3
., ?
A
80-87
10-4
0
7-3
75
M«t-W
31-40
0.6 0.6-1.0
Medium
volatile
89
3-4
0
1-2
80-85
_«.
31-20
1.4
Low
volatile
90
3
0
0-1
85-90
5?
20-10
1.8
Anthra-
cite
93
2
0
0
90-95
>25?
<10
4
1.7 1.6-1.9
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Organic sulfur in coal occurs in four forms: mercaptans, sulfides,
disulfides, and thiophene-based compounds. These same four classes of com-
pounds have been found in crude oils. Selected examples of sulfur compounds
with boiling points less than 200° C are presented in Table 5 from analyses of
coal products. The fractional distribution of these compounds in coal itself
is poorly defined.
Nitrogen contaminants in fuels have not been as well characterized as
sulfur compounds. Nitrogen is present in coal as an integral part of its
aromatic chemical structure. Indirect evidence suggests that nitrogen occurs
as pyridines, quinolines, acridines, pyrroles, indoles, carbazoles, and
porphyrins (ref. 4). The fractional distribution of the nitrogen compounds in
coal is largely unknown.
COAL LIQUID
Coal is liquefied by processes utilizing pyrolysis, solvent extraction,
and catalytic or noncatalytic hydrogenation. The liquid product may contain
organic nitrogen and sulfur originally present as organic contaminants of coal.
The inorganic sulfur in the parent coal, primarily sulfides, is converted to
hydrogen sulfide during liquefaction. The contaminant level in the liquid
product depends on the severity of the product-upgrading processes (hydro-
treating) .
Elemental analyses of parent coal and liquid products from pilot opera-
tions are presented for comparison in Table 6. Table 3 allows a comparison of
the qualitative distribution of sulfur and nitrogen contaminants in coal
liquids with that of other fuels. The liquid product typically contains less
than 1% sulfur. Thirteen thiophene derivatives and one disulfide were
identified in a sample of noncatalytically hydrogenated liquid product (ref.
4). In addition, 8 organosulfur compounds and over 40 sulfur compounds have
been observed in respective GLC profiles of COED oil and Synthoil oil (ref.
12).
The nitrogen contaminants of liquid coal product are anticipated to be
similar to those previously listed for coal and coal tars.* Indole and skatole
have been recently identified in Synthoil oil (ref. 12). •
*The expected nitrogen coiffipotuads include pyridines, quinolines, acridines,
pyrroles, indoles, carbazoles, and benzamides.
8
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TABLE 5. SELECTED ORGANIC SULFUR COMPOUNDS
PRESENT IN COAL PRODUCTS
Formula
B.2., Occurrence in
Name Structure "C coal product
Thiolg (mercaptans)
Hethanethlol
Ethanethiol
(RSH)
CH.SH
C-H.
SH
6 Coal gas
35 Tar, benzole
W
Benzethiol
Anthrathiol
169.1 H.T. tara
Coal oil
Alkyl aulfidea
^ (thioethera)
Bisulfides
36S2
C2HS
Methyl aulfide
Ethyl aulfide
(RSR1)
p-Dithinin.
(RSSR1)
37.3 Benzole
93.1 Benzole
Methyl dl- CH--S-S-CH, 122 Coal gas
aulfide 3 *
77 Tar
Thiophene and
derivatives
W
W
G4Has
Thiophene
2-Methylthio- (|~"]L
phene S CHj
2-3 Dimethyl (["J 3
thiophene s CH3
x--Trisuithyl (T~3-3 CH
thiophene s
tetramethyl
thiophene
Tetrahydro- P~1
thiophene VS'
84.2 Tar, benzene,
coal oil
112.5 Crude toluene
141.6 Tar
172.6 Tar, light
oil, benzole
182- L.T. tar
184
121
L.I. tar,
pyridine
fa.!. • High -tenperature.
T..T. » Low tenperature.
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TABLE 6. PROPERTIES OF COAL LIQUEFACTION PRODUCTS*
AND OF PARENT COAL
Weight % >
Fuel
COED ayncrude
COED char
Illionois
no. 6 coal
Garrett tar
Garret t char
Big Horn coal
Gulf
Big Horn coal
Syncrude (NS)
Big Horn coal
Syncrude (NS)
Pittsburgi coal
H-COAL
syncrude
H-COAL
fuel oil
Illinois
no. 6
BOM-synthoil
Kentucky
BOM-synthoil
Middle Kittan-
ing no. 6
PAMCO-SRC
Kentucky coal
Exxon— EDS
(Naphtha)
Exson-EDS
(Fuel oil)
Illinois
no. 6
C
87.1
73.4
67.0
92.7
74.0
68.8
90.6
69.3
89.2
69.2
89.1
78.7
NS
NS
70.7
89.0
NS
at. 4
NS
88.0
71.6
86.8
90.8
69.6
H
10.9
0.8
4.8
4.3
1.9
4.3
8.2
4.6
8,9
4.7
8.7
5.0
9.5
8.4
5.4
9.1
NS
7.5
NS
5.9
5.0
12.9
8.6
5.1
0
1.6
1.0
10.5
0.8
3.9
15.2
0.8
.19.. 9
1.0
17.8
1.5
6.3
-
NS
NS
8.1
NS
NS
1.6
NS
3.1
8.8
0.2
0.3
9.5
N
0.3
1.0
1.3
1.6
1.0
1.0
0.4
1.2
0.4
1.2-
0.8
1.6
0.7
1.1
1.0
0.6
NS
0.9
NS
2.2
1.4
0.06
0.2
1.8
S
0.1
3.4
4.1
0.6
0.6
0.8
<0.05
0.5
0.04
0.7
0.2
1.7
0.2
0.4
5.0
0.2
4.6
0.3
3.0
0.7
3.8
0,005
0.04
4.2
Ash
<0.01
20.3
12.1
NS
18.6
9.9
NS
4.4
71.0
6.5
71.0
6.9
NS
NS
9.9
1.0
NS
1.3
NS
0.2
9.1
NS
NS
9.6
Higher heating
i value
HHV(Btu/lb)
..... us
11,040
12,150
NS
11,700
9,200
NS
8,730
NS'
NS
NS
NS
18,290
NS
NS
17,700
.NS
16,840
8,000
'• 16,250
12,900
19,300
18,100
12,814
Ref
14
16
17
4
4
18
19
19
20
21
properties depend on severity of hydrotreating.
NS - Not specified.
10
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TABLE 7. COMPOSITION OF TOTAL AROMATIC FRACTION
OF LIQUID COAL (KEF. 13)
Compound type Volume %
Tetrahydrophenanthrenes 18.3
Pyrenes/fluoranthenes 16.1
Hexahydropyrenes 15.3
Dihydropyrenes 10.3
Octahydrophenanthrenes 9.6
Decahydropyrenes 7.9
Phenan.thren.es 6.2
Tetralins 4.9
Tetrahydrofluoranthenes 4.6
Chrysenes 3.9
Benzopyrenes 2.0
Tetrahydroacenaphthenes 0.7
Benzenes 0.2
The results from mass spectral analysis of the total aromatic fraction of
a coal liquid is presented in Table 7. The liquid was produced by
catalytic hydrogenation of Big Horn subbituminous coal. Complete resolution
of the various fractions of the liquid were not reported; however, synthetic
crude derived from the pyrolysis (COED) of coal yielded 49% (vol) aromatics,
41% iiaphthenes, 10% paraffins, and 0% olefins (ref. 14). In addition to these
results, polynuclear aromatic hydrocarbons (PAH) have also been identified and
quantified in various liquid products from pilot COED and Synthoil operations
(ref. 12).
SHALE OIL
Oil shale is a type of sedimentary rock that is rich in organics. Con-
siderable quantities of oil (shale oil) are released on subjecting this shale
to destructive distillation in a closed retort system. Table 2 may be used to
compare a typical elemental analysis of shale oil with analyses of other fuels.
Crude shale oil from the retort typically has 0.6 to 1.1% (wt) sulfur and
1.1 to 2.3% (wt) nitrogen (refs. 7, 4). Table 2 allows a comparison of the
'qualitative, distribution of sulfur and nitrogen contaminants in shale,oil with
that of other fuels. Shale oil generally has higher concentrations of nitro-
11
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gen contaminants than petroleum crudes; in addition, the ratio of olefins to
paraffins is also higher.
Analysis of the naphtha fraction of Colorado shale oil for sulfur com-
pounds revealed 75% thiophenes, 19% sulfides, 2% disulfides, and 4% thiols
(ref. 6). The literature provides qualitative identification of 22 thiophenes,
3 thiols, 2 disulfides, 1 trisulfide, and 2 cyclic sulfides. Sulfur analysis
of the gas oil fraction of Colorado shale oil has indicated the presence of
thiophenes, benzothiophenes, and more complex compounds.
Analysis of the naphtha fraction of Colorado shale oil for nitrogen com-
pounds revealed 31 pyridines, 5 pyrroles, and 6 nitriles (ref. 6). In the gas
oil fraction 35 percent of the nitrogen occurs as single-ring compounds,
mainly pyridines; 25 percent occurs as double-ring compounds, e.g., indoles,
quinolines, and tetrahydroquinolines; and the remaining 40 percent as multi-
ring compounds. In addition, several porphyrins have also been identified..
PETROLEUM CRUDE
Petroleum crude oil contains primarily hydrocarbons and has relatively
uniform contents of carbon (82-85 percent wt) and hydrogen (10-14 percent wt)
(ref. 4). Crude oils are mixtures of paraffinic, naphthenic, and aromatic
hydrocarbons. Sulfur, nitrogen, and oxygen impurities- typically range from
1 to 5 percent. Table 2 may be used to compare an elemental analysis of
petroleum crude with those of other fuels.
The location and history of the petroleum formation affect the quality
of the petroleum crude. Pennsylvania crudes are principally paraffinic,
whereas California crudes are naphthenic in nature. Pennsylvania and mid-
continent crudes may contain less sulfur than the heavier southern and western
crudes. Within a given crude, both sulfur and nitrogen compounds are concen-
trated in the heavier fractions, principally in the resins and asphaltenes.
Table 3 allows a comparison of the qualitative distribution of sulfur and
nitrogen contaminants in petroleum crude with that of other fuels.
The sulfur content of most crudes ranges from 0.1 to 5 percent. The
frequency distribution of sulfur content of U.S. crudes from 251 fields is
presented in Figure 1. Sulfur has been identified in crude oils as thiols
(mercaptans)', alkyl sulfides, and heterocycles. Table 8 depicts the
fractional distribution of sulfur in variouis crude oils. Alkyl thiols and
alkyl sulfides with-both •normal and branched alkyl groups have been identified
12
-------
60
50
S 40
ec.
UJ
CO
30
20
10
DO
,-.1 In
I I I I I I I 1 1 I I I I I 1 I I I I I I I I I I I I I \
<.l .1 .5 1.0 1.5 . 2,0 2.5 >2.7
WEIGHT PERCENT SULFUR
Figure 1. Frequency distribution of sulfur content
in crude oils of U.S. giant oil fields (ref. 15).
in petroleum crudes (ref. 4). Cycloalkyl thiols with cyclopentane or cyclo-
hexane rings are found. Cyclic sulfides with at least four or five carbons
in the ring structure are also present. The heterocyclic sulfur compounds
found in the heavier fractions of crudes have thiophenes, thiaindans, and
thienothiophenes as basic building blocks. Analysis of a narrow cut (200-
250° C) of Wasson crude has revealed 22 benzo[B]thiophenes, 18 thiaindans, 2
thienothiophenes, and 4 alkyl sulfides.
Nitrogen contamination of petroleum is typically less than 1 percent.
Figure 2 illustrates the frequency distribution of nitrogen content of U.S.
crudes from 229 fields. Table 8 allows comparison of nitrogen levels
1. Carious crudes. The types of nitrogen compounds found in crude oil are
listed in Table 9.
13
-------
TABLE 8. NITROGEN AND SULFUR IN SELECTED CRUDE OILS (REF. 4)
Distribution of
Field
Heidelberg
Hawkins
Rungely
Oregon Baa in
Wilmington
H*
*• Midway-Sunset:
Schuler
Agha Jarl
Santa Maria
Elk Ban In
Wasson
Slaughter
Velma
Kirkuk
Deep River
Yutea
Goldsmith
Loca-
tion
MiBB.
Texas
Colo.
Hyo.
Calif.
Calif.
Ark.
Iran
Calif.
Wyo.
Texas
Texas
Okl a.
Iraq
Mich.
Texan
Texas
Wt. Z
nitrogen
in crude
oils
0.11
NR
m
NR
0.65
0.58
0.06
NR
NR
NR
NU
NR
0.27
MR
0.12
0.1$
NR
Wt. %
sulfur
In crude
oils
3.75
2.41
0.76
3.25
1.39
0.88
1.55
1.36
4.99
1.95
1.85
2,01
1.36
1.93
0.58
2.79
2.17
Residual
sulfur
B0.3
73.8
72.0
68. 2
66.7
66.5
66.4
65.7
58.2
54.9
52.6
48.8
43.9
41.0
28.6
20.5
17.3
R-S-R
(aromatic
sulfides and
thiophenea)
11.7
14.6
20.3
13.5
19.9
26.0
22.7
9.6
35.5
25.1
13.0
22.5
41.5
24.7
3.0
20.1
11.6
sulfur in crude oil, percent of total sulfur
R-S-R
(aliphatic
sulfldea)
7.8
11.1
7.7
15.0
12.7
7.3
9.3
12.8
6.1
1.4
11.6
7.5
12.4
20.9
0.0
9.2
9.6
R-S-H
(thiols)
0.0
0.3
0.0
1.7
0.3
0.2
0.6
8.5
0.2
11.3
15.3
10.8
1.1
7.9
45.9
7.5
10.6
R-S-S-R
(diHulfldea)
0.2
0.3
0.0
1.3
0.5
0.0
1.0
3.4
0.0
7.2
7.4
9.2
0.7
5.5
22.5
6.9
8.4
U2S
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
0.0
1.2
0.0
Ele-
mental
S
0.0
0.0
0.0
0.3
0.0
0.0
0.0
0.0
0.0
0.1
0.1
1.2
0.4
0.0
0.0
34.6
42.5
NR = not reported.
-------
60
50
Ul
40
u
_J
Q_
s
<
03
30
20
10
'.01 .05
r^
r3-
.25
I I ' I I
.15 .25 .35
WEIGHT PERCENT NITROGEN
Figure 2. Frequency distribution of nitrogen content
in crude oils of U.S. giant oil fields (ref. 15)
.45 >.50
-------
TABLE 9. NITROGEN COMPOUNDS IN PETROLEUM (REF. 4)
* Types of nitrogen compounds found
In crude oil
Identified as In
individual Identified as processed
compound class fractions
Carbazoles Pyrroles Anilines
Pyridines Indoles Fhenazines
Quinolines Isoquinolines Nitriles
Tetrahydroquinolines Acridines
Dihydropyridines Porphyrins
Benzoquinolines
OVERVIEW
This discussion on fuel contaminants has dealt with the chemical form of
sulfur and nitrogen in coal, liquid coal product, shale oil, and petroleum
crude oil. The sulfur and nitrogen found in these fuels are, for the most
part, organically bound. Only coal was found to have substantial amounts of
inorganic contaminants, and these were as pyrite (FeS2). The sulfur content
of most fuels is less than 5 percent and occurs as thiols, sulfides, disulfides,
and thiophenes. Nitrogen content is usually reported at less than 2 percent
and occurs as pyridines, pyrroles, indoles, carbazoles, and benzamides. Only
a few of the more volatile of these contaminants could create an air pollution
problem from the raw fuel. The forms and concentrations that these contami-
nants assume during clean fuels processing are addressed in the next section.
16
-------
SECTION 3
EMISSIONS FROM FUEL CONVERSION FACILITIES
GASIFICATION
Coal is a complex material having a molecular weight of around 3,000.
When coal is heated in the absence of oxygen, volatile gases and liquids are
released, leaving a char. This char can be further heated in the presence of
the appropriate amounts of steam and oxygen to form carbon monoxide (CO),
hydrogen (H-), and some methane (CH,). This process is known as coal
gasification.
The objective of coal gasification processes is to convert the solid coal
into a clean, gaseous fuel and, under certain conditions, liquid fuels and
useful byproducts. Gasification plants may be categorized into three classes..
1. Lowi-Btu gasifiers produce industrial and utility boiler fuels
(150-300 Btu/SCF).
2. Intermediate-Btu gasifiers produce synthesis gas (300-450 Btu/SCF)
as feedstock for manufacture of liquid fuels, methanol, ammonia,
and other chemicals.
3. High-Btu gasifiers produce substitute natural gas (SNG) (-1,000 Btu/
SCF) and other chemicals.
Gasification technology is not new, having been used in Europe as early
as the 1840's. Only three gasification facilities are presently in commercial
operation in the United States: one employs Wilputte and two employ Wellman-
Galusha gasifiers. These plants have small capacities, employ early technology,
and produce-(low Btu fuel gas. Other processes are operating commercially
outside this country: Lurgi, Koppers-Totzek, and Winkler. Many additional
gasification schemes are in various stages of development. Twenty-two
processes have been reviewed for the Electric Power Research Institute (ref.
16); these are listed in Table 10. Several reviews (refs. 3,16,22,23) have
described and compared many of these processes and also have reported their
current status (ref. 1). A broad spectrum of operating conditions exists for
17
-------
TABLE 10. COAL GASIFICATION PROCESSES (REF. 16)
Roppers-Totzek
U.S. Bureau of Mines—
Synthane
Lurgi
Consolidation Coal—C02 Acceptor
Bituminous Coal Research—Bi-Gas
IGT—HYGAS
IGT—U-GAS
Winkler
Combustion Engineering
Foster Wheeler
Atomics International—Molten
Salt
M.W. Kellogg-rMolten Salt
U.S. Bureau of Mines—Stirred Bed
Gasifier
U.S. Bureau of Mines—Hydrane
Battelle—Ash Agglomerating Gasifier
Westinghouse—Advanced Gasifier
Brigham Young—Entrained Bed
Texaco—Partial Oxidation Process
Shell—Partial Oxidation Process
Bituminous Coal Research—Fluidized
Bed
Applied Technology Corp.—ATGAS
City College of New York—Squires
the processes under consideration. Table 11 presents a summary of key
operating parameters for eight selected coal gasification processes. The type
of reactor and the gasification temperature and pressure vary considerably
depending on the process and the desired end product.
Most of the first-generation gasification projects slated for intro-
duction in this country are based on the Lurgi process. Construction of five
commercial-sized plants will begin as soon as financial difficulties are
resolved; this may be as early as 1978. This discussion will, therefore,
primarily address the Lurgi process.
After the coal is mined, it is handled and transported to the gasifica-
tion facility, where it is then cleaned, crushed, dried, and either stored or
fed directly via lock hoppers to the gasifier. A generalized flow diagram of
a 250 x 10 CFD high-Btu SNG facility is shown in Figure 3. The Lurgi gasifier
operates as a countercurrent moving-bed reactor at 300-420 psia pressure and
1,100 to 1,700° F and is depicted in Figure 4. The coal is first devolatilized
in the top zone of the gasifier at 1,100 to 1,400° F, The remaining char
passes into the middle or gasification zone where the carbon and steam react to
18
-------
TABLE 11. GASIFIER DESCRIPTIONS AND OPERATING CONDITIONS (REF. 22)
«o
Process
Koppers-Totzek
Syn thane
Lurgi
CO. Acceptor
BI-GAS
HYGAS
U-Gaa
Wlnkler
Type
Ehtrained
slagging
Fluid bed
Counter-current
bed
Fluid bed
Top zone — entrained
Bottom zone — slagging
Fluid bed
4 sections
Fluid bed
Fluid bed
Oxidant
supplied
oxygen
oxygen
oxygen
airb
oxygen
oxygen
air
oxygen
Temperature ,
°F
2,700
Top— 800
Bottom — 1,700
Top— 1,100-1,400
Bottom — "1,700
1,500
Top zone--l,700
Bottom zone — 3,000
Top — 600
2nd sect. — 1,250
3rd sect.— 1,750
Bottom — 1,900
1,900
1,700
Pressure,
psia
15
1,000
420
150
1,200
1,200
350
30
Product
gas
Medium
Btu
High
Btu
High
Btu
High
Btu
High
Btu
High
Btu
Low Btu
Medium
Btu
Values shown in this table depend on the original bases chosen; plant sizes as well as other
differ and direct comparison of the values is difficult.
To Acceptor regenerator.
factors
-------
MAIN GASIFICATION TRAIN
to
O
•Vent Gas «V«nlG»
1 \
CbalFeetL
18.0 *
Coal
Preparation
••.
• Add Ga
A 16.6
Quench and
Scrub
Shirt
Add G«
Removal
MtffhnnMlnn
SNB62
(200 mm SCRDl
TT T
Air Refute Steam 22 Ash 1.0 Gas Liquor, Tar 16.0
4Jt Oxygen 4.7
(or Air)
T
4
Steam 3.0
Water 3.0
AUXILIARY FACILITIES
•Byproduct
"AlrBnfl Recovery 0.1
,Wa»w to Reuse
9-9 Sludg* Treated
Jltrooen Oxyo>n Gat 17.12 Sulfur Cat Alh Mohture (NH3 Phenoh.
6.6* A 4.7 A A0.38 32.8 A Ao.2 2.130 A e,c ,3 ^__
Oxygan
Plant
Sulfur
Plant
Steam and
Generation
Cooling
Tower
.Net OM Water A
fDlicherge f f 42-° !
16.0 II !
Waitewater
Treatment
[ TT TT ~T '
Raw Water
Treatment
Other Unlti
a.g., Byproduct
Recovery and
. Storage
' T
Air 20.2 Add Gal Air Fuel Air Air 6a> Liquor 16.0 Rav» Make-up Water
16.5 1.0 3.0 30.0 2,100
42.04
•Denote! atmospheric erninlom.
NOTE-Flow rates we In 1000'i of TPD unlan specified otherwise.
AUXILIARY FACILITIES
Figure 3. Generalised coal gasification scheme.
-------
GRATE
DRIVE
STEAM +
OXYGEN
GAS
Figure 4, Lurgi gasifier.
21
-------
produce fuel gas rich in CO and !!„.
C + H20 + 31.4 kcal/mole -»• CO 4- H£ .
In the lower zone the remaining char is burned with either air or oxygen to
supply heat to the process. The heating value of the gasifier product gas
will range from 300 to 450 Btu/SCF if oxygen is used, whereas a lower quality
product (150 to 300 Btu/SCF) results from an "air blown" unit. Before under-
going further processing, the gasifier effluent is water-quenched and cooled
to remove particles and tars. Ammonia, phenols, and other highly soluble
compounds are also removed in the water quench.
For high-Btu SNG production, a shift reactor is included to produce
hydrogen via the water shift reaction.
CO + H20 -»• C02 + H2 + 9.8 kcal/mole.
The H^-to-CO ratio must be approximately 3 to 1 for subsequent product up-
grading in the methanation step. After the shift reactor, H2S, formed in the
gasifier, and CO., formed in the shift conversion, are removed in the acid gas
removal section. The several techniques available for acid gas removal in-
clude hot carbonate solutions, amine solutions, and cooled methanol (Rectisol).
It is likely that the. Rectisol process, as Lurgi-licensed technology, will be
employed in the acid gas removal1 module. This process provides a concentrated
H_S and CO. stream to the sulfur recovery module.
The final processing step is methanation where much of the H_ formed in
the shift reactor is catalytically reacted with CO to produce methane and
steam.
CO + 3H2 ^ H20 + CH^ + 48.3 kcal/mole
After methanation, the product gas is dried and compressed to pipeline pressure
for delivery.
In addition to the main gasification unit, other support and peripheral
processes include:
1. A sulfur plant to recover sulfur as a byproduct from the acid
gases,
2. A power boiler and steam generator to supply the gasifier with
steam,
3. A cooling tower,
4. A wastewater treatment facility with po'ssible byproduct recovery,
5. A raw makeup water treatment facility, and
22
-------
6. An oxygen plant to provide the gasifier with oxygen.
The high-Btu gas from gasification processes must meet product specifica-
tions and be of quality similar to natural gas. Anticipated product gas
specifications from eight gasification schemes are summarized in Table 12
along with specifications for three types of natural gas. Not all the
processes produce SNG, as is indicated by comparison of the specified heating
values. The SNG products compare favorably in composition with natural gases
and also possess low contaminant levels. Any major air pollutant emissions
problems therefore must occur between the gasifier and the final product
stage.
In the gasifier much of the sulfur in the original coal is converted to
H S and COS. Nitrogen from the coal is converted primarily to NH_ and HCN.
It is here that many of the coal contaminants discussed in the fuel contam-
inants section enter the gas phase. Typical expected analyses of raw gasifier
gas are presented in Table 13 for eight gasification processes. The litera-
ture reveals few quantitative details on the measured concentration of trace
gaseous species in the raw gasifier gas. Reported analyses of raw gas from
pilot and commercial gasification facilities are presented in Table 14.
Atmospheric emissions sources for a gasification plant are illustrated in
Figure 3. These sources include the following:
1. Coal handling and pretreatment (coal drier vent),
2. Vent gases from startup, shutdown, and routine charging of the
gasifier (lock hopper gases),
3. Acid gas removal (CO- vent),
4. Sulfur recovery (tail gas),
5. Catalyst regeneration,
6. Byproduct recovery and storage,
7. Cooling tower (from possible contamination of cooling water by
^.eaks in heat exchange equipment),
8. Wastewater treatment,
9. Steam boilers (power generation) and process heaters and furnaces,
10. Fugitive emissions (at valves, flanges, seals, pumps, compressors,
and other equipment).
A. summary of the major gasifier and byproduct species of interest is
presented in Table 15. An analytical test plan (ref. 30) has been proposed to
23
-------
TABLE 12. ESTIMATED SYNTHETIC GAS AND MEASURED NATURAL GAS ANALYSES
10
-P-
Volume of
product gas,
Types 106 scfd
Synthetic gas
Koppers-Totzek
Synthane
Lurgi
C02 Acceptor
BI-GAS
HYGAS
U-Gas
Winkler
Natural gas
Texarkana
Cleveland
Oil City, Pa.
290
250
251
263
250
260
784
886
: —
Higher heating
value
(HHV) of Pressure oi
product gas, product gat
Btu/scf psia
303
927
972
952
943
1,000
158
282
967
1,131
1,232
166
1,000
915
1,000
1,075
958
300
~15
~15
~15
~15
i,
CH4
0.1
90.5
95.9
93.0
91.8
93.0
4.9
,2.0
96.0
80.5
67.6
Gas analysis,
C2H6
NSC
NS
NS
NS
NS
NS
NS
NS
NS
18.2
31.3
H2
32.6
3.6
0.8
4.8
5.1
6.6
13.8
42.7
NS
NS
NS
N2
.
1.2
2.1
1.2
*
0.8
1.9
0.2
54.4
1.2
3.2
1.3
1.1
volume %
C02
5.2
3.7
2.0
1.3
1.1
0.1
6.7
15.1
0.8
NS
NS
CO
60.9
0.1
0.1
0.1
0.1
0.1
20.2
38.9
NS
NS
NS
H2S +
COS
0.03
NS
NS
NS
NS
NS
0.015
0.08
NS
NS
NS
values shown in this table depend on the original bases chosen; plant sizes as well as other factors
differ and direct comparison of the values is difficult.
bRef. 22.
CNS = Not specified.
dRef. 24.
-------
TABLE 13. v EXPECTED ANALYSES OF RAW, DRY GAS FROM GASIFIERS (AFTER QUENCHING) (REF. 22)
10
in
Process
Koppers-Totzek
Synthane
Lurgi
CO Acceptor
BI-GAS
HYGAS
U-Gas
Winkler
Volume %
CO
60.1
16.7
19.6
15.2
43.9
28.4
19.2
35.2
H2
32.4
27.9
39.1
71.5
24.5
29.6
13.3
38.6
co2
5.9
29.0
28.9
6.9
14.0
21.2
10.0
21.8
CH4
0.1
24.5
11.1
6.1
15.5
18.7
4.7
1.8
H2S
0.3
0.5
0.3
0.03
1.4
1.6
0.8
1.4
COS
0.03
NR
NR
NR
NR
0.01
0.02
0.2
N2
1.1
0.8
0.3
0.2
0.7
0.07
52.0
1.1
Higher
hydrocarbons
0
0.5
0.7
NRC
NR
0.4
NR
NR
values shown in this table depend on the original bases chosen; plant sizes as well as other
factors differ and direct comparison of the values is difficult.
Does not include gas from acceptor regenerator.
CNR - Not reported.
-------
TABLE 14. REPORTED ANALYSES OF RAW GAS FROM PILOT AND COMMERCIAL GASIFICATION FACILITIES
10
o\
Component
Process
Coal
Major
species.
volume Z
"2
CO
CO2
H2
HjO
C2Uo
C2+
Minor
species,
S02
H2S
COS
cs2
Hethane-
thiol
Thiophene
Methyl
thiophene
Dimethyl
.thiophene
NO
NII3
HCH
Benzene
Toluene
CB
aromatlca
Composition
Syn thane
Illinois
no. 6
(ref.
25)
t
12.0
37.4
35.1
12.8
tt
1.29
HR
10
14.300
140
HR
20
40
10
10
NR
NR
.
<10
390
100
20
Illinois
no. 6
(ref.
25)
t
13.3
35.8
35.7
12.4
tt
1.30
NR
10
14,100
200
HR
20
10
10
10
NR
NR
.
<10
120
30
20
Illinois
no. 6
(ref.
25)
t
12.3
35.3
35.4
13.9
tt
1.56
NR
10
16,200
300
NR
30
40
10
10
HR
•HR
—t
<10 *
220
50
20
Wyoming
Illinois eubbl-
no. 6
(ref.
26)
HR
NR
NR
NR
HR
NR
NR
NR
10
9.800
150
10
60
31
10
10
NR
NR
20
340
94
24
tunlnoua
(ref.
26)
NR
NR
NR
HR
HR
NR
NR
NR
6
2,480
32
NR
0.4
10
HR
HR
NR
NR
2
434
59
27
Western
Kentucky
(ref.
26)
HR
HR
NR
HR
HR
NR
HR
NR
2
2.530
119
NR
33
5
NR
NR
NR
NR
11
100
22
4
North
Dakota
lignite
(ref.
26)
NR
NR
NR
NR
NR
NR
HR
NR
10
1.750
65
HR
10
13
HR
11
HR
NR
3
1,727
167
73
Pitta-
burgh
(ref.
26)
HR
NR
NR
NR
NR
NR
HR
HR
10
860
11
NR
8
42
7
6
NR
NR
NR
1,050
185
27
North
Illinois Dakota
no. 6
(ref.
27)
43.5
10.1
17.9
21.5
5.6
NR
0.7
NR
20
5.140
120
NR
40
70
60
70
NR
NR
NR
770
220
60
lignite
(ref.
27)
32.3
15.4
18.3
28.6
4.7
NR
0.6
NR
10
3,100
140
NR
8
<5
<5
<5
NR
NR
NR
680
70
20
Lurgl-
Flscher-
Tropsch*
Montana
subbl-
tunlnoua
(ref.
27)
38.0
12.2
18.2
26.9
4.1
NR
0.5
NR
10
580
20
NR
10
20
10
10
NR
NR
NR
990
200
60
HR
(ref.
22)
1.59
20.20
28.78
40.05
8.84
HR
NR
0.54
NR
2,870
10
NR
20
NR
HR
HR
NR
NR
NR
NR
HR
NR
Bureau oE
Fixed mines fixed
bed bed
Pitta-
burgh
(ref.
28)
NR
NR
NR
NR
NR
NR
NR
NR
NR
4,500-
4.800
315-
350
NR
NR
NR
NR
NR
NR
529-
1,028
<10
NR
HR
NR
Western
Kentucky
(ref. 28 )
47.61
20.55
5. 88
13.83
2.76
8.42
HR
NR
HR
6.000
1.000
NR
NR
NR
NR
NR
NR
2.500
NR
NR
NR
NR
BI-GAS
Illinois
no. 6
(ref.
29)
47.70
16.74
8.84
11.98
3.14
10.46
NR
NR
HR
4,600
1.000
NH
NR
NR
HR
NR
NR
3,800
NR
HR
NR
NR
Koppers-
Totzec
HR
(ref.
30)
0.62
37.36
7.33
25.17
0.08
29.19
NR
NR
22
2.300
178
NR
NR
NR
HR
NR
7
1.700
288
NR
NR
NR
*Sasolburg, South Africa.
tNltrogen-free analyses.
ttWater-free analyses.
NR - Not reported.
-------
ro
TABLE 15. POTENTIAL POLLUTANTS
Inorganic
M2
°2
H2°
CO
H2
A2
Nllj
Gaaea
Acid Sulfur Organic
/*A ii c /iti
C02 112S CH^
HZS cos c2u4
S0x S0x C2H6
N0x CS2 C3H6
HF CH.SIl C.H0
J Jo
iii**l f ii *:ii f u
1IOJ. U.II..DI1 C . li_
/ 3 4 0
HCM C.H.
C4H10
FROM GASIFICATION OPERATION (REF. 31)
Liquids and solids
Hydrocarbons
C,-C12 Paraffins
Benzene
Toluene
Xylenea
Indene
Polynuclear
aromatica
Naphthalenes
Fyrenes
Fluoranthenes
Fhenanthrenea
Fluorenea
Acenaphchenea
Benzopyrenea
Chryaeneg
Coronene
Phenols Sulfur
Phenol Thlola (mercapcans)
Cresols Thlophenol
Xylcnola Thiocreaol
Naphchola Thiophenea
Benzothlophene
Nitrogen
Pyrldlne
Picollnes
Lutadlnes
Qulnollne
Isoqulnollne
Qulnuldlne
Indole
Curbazole
Acrldine
-------
enable the assessment of the pollution potential of a Lurgi coal gasification
facility. This plan, as shown in Table 16, reflects the anticipated distri-
bution of various major air pollutants among the expected sources in a
gasification facility.
Emissions estimates have been compiled from environmental impact state-
ments for four Lurgi-based processes and are summarized in Table 17. Since
no domestic operational experience is available for the Lurgi process, the
lack of consistency among these results may be attributed to different degrees
of emissions control expected for the four facilities. Recent estimates (ref.
33), shown in Table 18, have categorized the hydrocarbon emissions according
to type. The fugitive emissions were estimated by analogy to petroleum
refinery operations. The nonmethane hydrocarbon (NMHC) emissions estimate of
3,673 Ib/hr falls within the range of NMHC estimates of Table 17. Notice that
28 percent of the estimated hydrocarbon emissions is as NMHC. It should be
noted that over 90 percent of these NMHC emissions are olefinic hydrocarbons
and are highly photochemically reactive in the presence of NO and sunlight.
3£
The major hydrocarbon sources are likely to be vented lock hopper gases
and the tail gas (CO. rich) stream from the sulfur recovery plant. The
potential problem with lock hopper vent gas can be remedied by incineration.
This solution may also be applicable to the tail gas stream from the sulfur
plant.
Emissions of NO could be significant from coal gasification facilities.
* •»
Nitrogen oxides emissions from gasification facilities are indicated in Table
17 to be low. It has been assumed that the economic incentive to recover
another major nitrogen species, ammonia, as a salable byproduct makes it un-
likely that ammonia in waste gases and liquids would be burned, flared, or
otherwise emitted.
The major source of sulfur emissions is likely to be the sulfur recovery
plant. Most of the sulfur in the coal is converted to H_S and COS in the
gasifier. These species, along with CO., are separated from the gasifier off
gas in the Rectisol unit and sent to the sulfur recovery plant. Glaus or
Stratford units will be used individually or in combination in the sulfur
recovery plant depending on the sulfur content of the raw coal. To reduce the
HC and CO levels to 100 ppm and the S0_ levels to 250 ppm, incineration
followed by SO. scrubbing may be required on sulfur plant tail gas. This
28
-------
TABLE 16. ANALYTICAL TEST PLAN FOR GASEOUS EMISSIONS FROM A LURGI
GASIFICATION FACILITY (REF. 32)
Location to be sampled
Product gas (SNG)
Sulfur recovery ab-
sorber and oxidlzer
off gases
Boiler & heater stacks
Incinerator from
sulfur recovery off
gases
Degasser vent gases
Evaporation from cool-
ing towers
Analysis to be performed
Participates
X
X
X
X
S02/S03
X
X
X
X
X
X
N°x
X
CO
X
C02
X
Benzene
X
X
Toluene
X
X
Light HC
X
X
PAH
X
H2S
X
X
X
X
X
X
COS
X
X
X
X
X
X
CH3SH
X
X
X
X
X
X
CS2
X
X
Thlophene
.
X
X
-------
TABLE 17. COMPARISON OF EMISSIONS ESTIMATES FOR 250 X 10 SCFD
LURGI-BASED COAL GASIFICATION PLANTS (REF. 33)
Project
Northern Great Plains Resources Project
(NGPRP) assuming compliance with
applicable National Source
Performance Standards (NSPS)
Western Gasification Company (WESCO)
Wyoming Coal Gas Company (WCGCo)
El Paso Gasification Project
Emissions ,
Steam plant
so2
4,100
927
2,074
40
NO NMHC
2,390 NR
1,510 NR
2,037 NR
67 NR
Ib/hr "
Gasification plant
so2
1,300
130
47
273
N0x
210
105
80
116
NMHC
15,300
2,120
NR
NR
Total
so2
5,400
1,057
2,121
313
NO
X
2,600
1,615
2,117
183
NMHC
15,300
2,120
NR
NR
NR - Not reported.
TABLE 18. SUMMARY OF ESTIMATED HYDROCARBON
EMISSIONS FOR A 250 x 106 SCFD
GASIFICATION PLANT (REF. 33)
Emissions, Ib/hr
Hydrocarbon type
CHA
C2 to C3 paraffins
C,+ paraffins
C-+ aromatics
Olefins
Methanol
Isopropyl ether
TOTAL
Continuous
6,003
—
6.1
0.3
3,634.5
4.9
0.6
9,649.4
Fugitive
5
4
9
1.3
6.8
—
- —
26.1
Total
6,008
4
15.1
1.6
3,641.3
4.9
0.6
9,675.5a
aNMHC =3,673.
30
-------
control technique or equally effective alternates may be required by State or
Federal legislation.
The State of New Mexico has established emissions regulations for coal
gasification plants (ref. 34). The U.S. EPA is preparing to propose regula-
tions for new coal gasification facilities (Sedman, personal communication,
October 1976). These regulations are compared in Table 19.
The types and quantities of gaseous emissions from coal gasification
facilities remain poorly defined. The major sulfur-containing compounds
emitted are expected to be H,S, COS, and S0_. Nitrogen-containing emissions
are expected as NH», HCN, and NO . Hydrocarbon emissions may arise from both
•J j£
continuous and fugitive sources. The identity of the NMHC emissions is poorly
defined: estimates can be made based on examination of engineering process
flow and material balance estimates, pilot plant results, and by analogy to
similar processes such as petroleum refining.
LIQUEFACTION
The objective of coal liquefaction processes is to convert solid coal
into a liquid fuel and under certain conditions into gaseous fuels and useful
byproducts. The liquefaction process involves cracking the coal molecular
structure and either adding hydrogen or removing carbon to form a liquid.
This is usually accomplished at high temperature and pressure. Liquefaction
processes may be categorized into two groups.
1. Pyrolysis-based processes rely on thermal cracking with the
removal of carbon to increase the hydrogen-to-carbon ratio,
yielding liquids, gases, tars, and chars.
2. Dissolution processes involve the addition of hydrogen to free
radical fragments of coal molecules formed in coal solubiliza-
tion, thus increasing the hydrogen to carbon ratio and the
ultimate liquid yield. These processes may or may not employ
catalysts and may or may not be conducted in the presence of
hydrogen.
Liquefaction of coal was used in Germany during World War II to produce
over 15,000 BPD of aviation and motor fuels. The U.S. Bureau of Mines
conducted research directed at gasoline and fuel production from 1944 to 1953.
Although no commercial coal liquefaction facilities exist at present, research
and development efforts in this area are receiving increased support. The
31
-------
TABLE 19. REGULATIONS FOR COAL GASIFICATION PLANTS
N>
State of New Mexico (Ref . 34)
Gas-fired power plant
associated with coal
Pollutant gasification plants
Particulate 0.
Sulfur dioxide 0.
Nitrogen oxides 0.
Nonmethane hydrocarbons
Hydrogen aulfide
Total sulfur
Reduced sulfur
(sum of H«S, COS, and
es2>
Hydrogen cyanide
Hydrogen chloride
Ammonia
03 lb/106 Btu
16 lb/106 Btu
20 lb/106 Btuc
NA
NA
NA
NA
NA
NA
NA
Proposed (Sedroan, personal communication, October
Based on oil-fired plant.
Adopted as gas-burning equipment
NA = Not applicable.
A = Higher heating value of coal
B =» peed rate of coal sulfur to g
regulation.
j*
to gasifier, 10
aaifier, Ib/hr.
Gasification
plant
0.03 gr/SCF
NA
NA
NA
10 ppm
0.008 lb/
106 Btu
100 ppm
10 ppm
5 ppm
25 ppm
1976).
Btu/hr.
EPA
Power
plants
0.10 lb/
106 Btu
0.80 lb/.
106 Btu
0.20 lb/
106 Btuc
NA
NA
NA
NA
NA
NA
NA
Gasification
plant4
NA
500 ppm
NA
0.006 lb/106
Btu, 100 ppm
NA
0.019 (A x B)0'5
Ib/hr
NA
NA
NA
NA
-------
primary emphasis of these efforts is toward the production of environmentally
acceptable substitutes for petroleum-derived liquid boiler fuels, with less
emphasis on transportation fuels, distillate fuels, and chemicals. A major
goal is the demonstration of the necessary liquefaction technology for
commercial application by 1982-1985 (ref. 1).
Many liquefaction schemes are in various stages of development. Nine
processes have been reviewed for the Electric Power Research Institute, (ref.
16) and a new process has been announced recently by Exxon (ref. 21). These
processes are listed in Table 20. Several reviews (refs. 16,21,22,3,23) have
described and compared many of these processes and also have reported their
current status (ref. 1).
A wide range of operating conditions exists for the processes under con-
sideration. Table 21 presents a summary of key operating parameters for four
selected coal liquefaction processes. The type of reactor and the lique-
faction temperature and pressure vary considerably depending on the process
and the desired end products.
TABLE 20. COAL LIQUEFACTION PROCESSES (REF. 16)
Pyrolysis FMC—COED
Garrett—Flash Pyrolysis
Oil Shale Corporation—TOSCOAL
Dissolution
With hydrogen gas
With catalyst Hydrocarbon Research, Inc.—H-COAL
U.S. Bureau of Mines (BOM)—Synthoil
Gulf Research—Gulf Catalytic Coal Liquid
Without catalyst Pittsburgh and Midway Co. (PAMCO) Solvent
< Refined Coal (SRC)
Southern Services, Inc.—Solvent Refined
Coal (SRC)
Without hydrogen gas
4
With or without Consolidation Coal Co.—Consol Synthetic
catalyst Fuel
Exxon—Exxon Donor Solvent (EDS)
33
-------
TABLE 21. DESCRIPTIONS AND OPERATION CONDITIONS FOR FOUR SELECTED
LIQUEFACTION PROCESSES*1
Process
COEDb
SRCb
H-Coalb
EDS°
Type
Fluid bed
pyrolysis
Noncatalytic
hydrogenation
Catalytic
hydrogenation-
ebullating bfeu
Noncatalytic
donor solvent
hydrogenation
Temperature ,
op
Stage 1, 550-600
Stage 2, 850
Stage 3, 1,050
Stage 4, 1,550
840
850
370-480
Pressure,,
psig
8
1,000
2,000
1,500-2,500
Reactor effluent
Char, gas, liquid
Gas, char slurried in
high melting liquid
Gas, ash in liquid
Gas , liquid
Principal
products
Char, Syncrude,
gas
Fuel oil,
nap t ha
Syncrude
Naphtha ,
fuel oil
values shown in this table depend on the original bases chosen; plant sizes as well as other factors
differ and direct comparison of the values is difficult.
bRef. 22.
uRef. 21.
-------
Selection of the candidate processes "most likely to reach commercial
status" is difficult. The processing conditions and the nature of the products
formed in each of.the alternate processes are so diverse that it is also
difficult to select one flow diagram that would be representative of every
process. Figure 5 presents a highly generalized coal liquefaction scheme and
the required auxiliary facilities. The literature should be consulted to
obtain details on the steps involved in any specific process.
Coal is first mined and transported to the liquefaction facility. This
coal is then cleaned, crushed, dried, and either stored or fed directly to the
liquefaction module. The variety of liquefaction processes and operating con-
ditions was noted earlier (see Tables 20 and 21). The raw liquefaction product
stream is separated into solids, liquids, and gases. Gaseous sulfur species
in the raw product gas stream are separated in the acid gas removal module for
subsequent sulfur recovery. The raw liquid product, after solids removal, is
treated with hydrogen to reduce sulfur, nitrogen, and oxygen compounds and to
hydrogenate unsaturated materials. The gas stream from hydrotreating is
separated in the facility into a recyclable fuel stream and a stream rich in
sulfur species for subsequent sulfur recovery. Hydrogen is required in the
hydrotreating unit in many of the liquefaction schemes. Hydrogen production
employs technology similar to that used in gasification processes.
Aside from the coal conversion module itself, many similarities exist
between liquefaction and gasification operations. The types of auxiliary
facilities required by each operation are almost identical. In addition, a
coal gasifier may be included in liquefaction plants to provide makeup hydro-
gen and makeup fuel gas. These support and peripheral processes for lique-
faction include the following:
1. Acid gas removal facilities for treating various acid (sour) gas
streams,
2., A sulfur plant to recover sulfur as a byproduct from acid gas
streams,
3. A power boiler and steam generator to supply the gasifier with
steam, '
4. A cooling tower,
5. A wastewater treatment facility with possible byproduct recovery,
6. A raw makeup water treatment facility, and
35
-------
MAIN LIQUEFACTION TRAIN
U)
Coal Sto
Coal .
Prepare!
Sleim
Cool. Chir. Liquid
or Product Gas Feed
Oxygen
• Oxygen
t ' '""I
'Sour Gas "Sour Gas
II ,
•
rage Coal
,> LlqUBl.r.«lon ^ Product ^ ... • . Liquid _
on
1— »»
1
i Hydrogen
1 Containing
~1 !. i
Hydrooen
Production
1 ;
i Ash
"^ Seiuration w nyoroireating ^
Area separaiion Liquid . Products
T ' '
Char < Char
Hydrogen
t
AUXILIARY FACILITIES
t t t t
t
1
Dotted linei indicate stream* absent in some plants.
•Denotes atmospheric •mission.
1
Oxyqen
Plant
AddGai
Removal
Sulfur
Plant
Steam and
Generation
Cooling
Water
WasMwater
Treatment
.-
Raw Water
Treatment
Other Units
(e.g.. Byproduct
Recovery and
Storrge)
Figure 5. Generalized coal liquefaction scheme (ref. 22)
-------
7. An oxygen plant to provide the gasifier or the liquefaction reactor
with oxygen.
The liquid product from hydrotreating may be suitable for direct use as
fuel or for refining into other products. Table 14 allows a comparison of
sulfur and nitrogen contaminant concentrations in selected synthetic liquid
products with those of the parent coal. Sulfur and nitrogen contaminants are
converted primarily to HjS and NH^ in the liquefaction and subsequent hydro-
treating processes. The contaminant level in the liquid product will depend
on the severity of the hydrotreating process.
Although several sulfur species have been determined in liquid coal
product, few analyses for nitrogen species have been conducted. This was noted
in an earlier section on fuel contaminants in liquid coal product. The sur-
veyed literature reveals only a single determination of trace gaseous species
in gas streams from liquefaction facilities, a gas chromatographic analysis of
raw pyrolysis gas and stack gas from the COED pilot plant (ref. 12). Over
100 components were observed; benzene and toluene were identified as prominent
constituents. Table 22 depicts the concentrations of the quantified trace
species from the above study and allows a comparison with the reported major
gaseous species from the COED (ref. 14) and Synthoil (ref. 35) processes.
Expected atmospheric emissions sources for a liquefaction facility include
the following:
1. Coal handling and pretreatment,
2. Vent gases,
3. Acid gas removal,
4. Sulfur recovery (tail gas),
5. Byproduct recovery and storage,
6. Cooling tower (from possible contamination of cooling water by
leaks in heat exchange equipment),
7. Wastewater treatment,
8. Steam boilers (power generation) and process heaters and
furnaces, and
9. Fugitive emissions (at'valves, flanges, seals, pumps, compressors,
and other equipment).
An analytical test plan (ref. 32) has been proposed to enable the assess-
ment of the pollution potential of a COED coal liquefaction facility. This
37
-------
TABLE 22. GAS ANALYSES FROM LIQUEFACTION PROCESSES
Component
N2
co2
CO
H2
CH4
C2H6
C3H8
V
C2H4
C3H6
Benzene
Toluene
H2S
gos
Thiophene
(CH3S)2
Analysis of major
gaseous species, Vol %
Synthoil reactor gas
0.3
0,1
0.2
94.4
2.8
0:9
0.6
0.4
0.03
0.14
0,04
COED pyrolysis gas°
0.5
20.9
16.8
43.2
15.0
1.1
0.2
0.5
0.4
0.2
1.3
Analysis of trace gaseous
species from Pilot COED process , ppm
Pyrolysis gas
19
5
49
3
5
0.2
Stack gas
9
0.8
9
5
0.3
. 12.
Ref. 35.
"Ref. 14.
-------
plan, as shown in Table 23, reflects the anticipated distribution of various
major air pollutants among the expected sources in a liquefaction facility.
The types and quantities of gaseous emissions from coal liquefaction
facilities are poorly defined. The major sulfur-containing emissions are
expected to be H.S, COS, and SO . Nitrogen-containing emissions are expected
as NHo, HCN, and NO . Hydrocarbon emissions may arise from both continuous
and fugitive sources. The identity of the NMHC emissions is poorly defined:
estimates can be made based on examination of engineering process flow and
material balance estimates, pilot plant results, and by analogy to similar
processes such as coal gasification and petroleum refining.
SHALE OIL PRODUCTION
Oil shale is a type of sedimentary rock that is rich in organics. These
mineralized organics are derived mainly from algae, spores, and pollen. The
insoluble organic matter is known as kerogen and the soluble matter as bitumen.
Considerable quantities of oil are released on subjecting this shale to
destructive distillation at low pressure in a closed retort system. A yield
of 10 gallons of oil per ton of shale is generally considered to be the mini-
mum for commercial recovery by retorting techniques.
A major oil shale formation in the United States occurs along the Green
River of Colorado, Wyoming, and Utah. Estimates of high-grade shale resources
(greater than 20 gallons per ton) equivalent to 600 billion barrels of oil
have been made for the Green River formation (ref. 36). Current shale oil
production projections of 400,000 barrels per day by 1985 indicate that shale
oil will, assume a small share of the total energy requirement, reducing the
quantity of imported oil by less than 1 percent (ref. 7). By the year
2000, however, shale oil could reduce foreign imports by up to 7 percent.
Several steps are involved in converting raw shale to products. The ore
is first mined, and then it must be handled and treated prior to retorting.
The shale*is fed to the retort where the organic vapors are driven off at
temperatures in excess of 450° C. Collected liquid and gaseous organic
products must be upgraded to gaseous fuels, liquid fuels, and solids by
various processes. The upgrading'facilities will be similar to those down-
stream from the atmospheric distillation column in petroleum refineries. The
spent shale solids present an enormous refuse disposal problem.
39
-------
TABLE 23. ANALYTICAL TEST PLAN FOR GASEOUS EMISSIONS FROM A COED
COAL PROCESSING FACILITY (REF. 32)
Location to be sampled
Coal drier vent gaa
Purge gas pyrolysis,
stage 1
Stack gaa from heaters
Superheaters
Transport gas
heaters
Preheater
H« plant heaters
Boiler and heaters
Separated CO, stream
Sulfur plant off gaa
Degasser vent gases
Evaporation from cool-
ing towers
Analysis to be performed
Particulatea
X
X
X
X
X
X
X
X
X
so2/so3
X
X
X
X
X
X
X
X
X
X
X
NO
X
X
X
X
X
X
X
X
X
CO
X
X
X
X
X
X
X
X
co2
X
X
X
X
X
X
X
X
X
Bunzeiie
X
X
Toluene
X
X
Organics
X
X
PAIl
X
H2S
X
X
X
X
X
X
X
X
X
X
X
COS
X
X
X
X
X
X
X
X
X
X
X
cu3sn
X
X
X
X
X
X
X
X
X
X
X
cs2
X
Thtophene
X
X
-------
Several processes have been developed for shale oil production (refs.
36,37,38). Most of these involve the above-ground surface processing of
the raw shale, i.e., TOSCO II, Lurgi-Ruhrgas, Union Oil, Bureau of Mines,-
Development Engineering, Petrosix, and Institute of Gas Technology. Occidental
Petroleum, however, has developed an in situ process involving an underground
retorting technique.
The TOSCO II process is the closest to commercial status and is likely
to be employed in first-generation shale oil production plants (refs. 38,39).
Discussion of air pollutant emissions is therefore limited to this process. In
the TOSCO II process, crushed oil shale is heated to 480° C by direct contact
with heated ceramic balls. The organic material in the shale rapidly decom-
poses to produce organic vapors. Cooling of the vapor yields crude shale oil
and light organic vapors. A flow diagram depicting this process is presented
in Figure 6.
Typical analyses of retort gas from a TOSCO-type process are presented
in Table 24. It is anticipated that the retort gas will undergo
desulfurization before use as a fuel. In addition, hydrotreating processes
will be employed to upgrade the crude shale oil by removing nitrogen and
sulfur with recovery as ammonia and sulfur.
Various types of pollutant emissions may be associated with shale oil
processing: vehicular emissions from mining, construction, and transporting
equipment; particule emissions from shale handling; and gaseous emissions from
retorting and subsequent refining operations. Expected atmospheric emissions
sources for a shale oil facility include the following:
1. Oil shale handling and pretreatment,
2. Oil shale pyrolysis and shale oil recovery,
3. Vent gases from a variety of combustion sources (e.g.,
coking, hydrotreating, and hydrogen production),
4.* Acid gas removal,
5. Spent shale moisturizer and disposal,
6. Sulfur recovery (tail gas),
7. Byproduct recovery and, storage,
8. Cooling tower,
9. Wastewater treatment,
41
-------
RAW SHALE
JS
to
FLUE GAS TO ATMOSPHERE
BALL
ACCUMULATOR!
TROMMEL
GAS TO ACID
AS REMOVAL
3 TREATING
—^NAPHTHA TO
ACID GAS REMOVAL
i AND TREATING
—fr-GASOILTO
HYDRO-
GENATION
•RESIDUAL
TO COKER
HOT
SPENT
SHALE
Jt,
SPENT'
SHALE
COOLER
l_ J
1-
\
SPENT SHALE
TO DISPOSAL
Figure 6. Tosco II process (ref. 40).
-------
TABLE 24. TYPICAL RETORT GAS ANALYSES
Volume %
Methane
Ethane
Propane
Butanes
Pentanes (and higher)
Ethylene
Propylene
Butenes
Pentenes (and higher)
Carbon Monoxide
Carbon Dioxide
Nitrogen
Hydrogen
Hydrogen Sulfide
17. 5a
7.0
3.4
1.7
1.0
2.2
2.6
1.9
2.2
2.0
30.3
2.0
23.9
2.3
15. 2°
10.3
4.0
1.6
c
5.4
3.7
2.7
5.4C
3.6
21.4
—
22.4
4.3
41.
Ref. 40.
CThe 5.4 percent represents the sum of C_ and higher alkanes and
olefins.
10. Steam boilers (power generation) and process heaters and
furnaces, and
11. Fugitive emissions (at valves, flanges, seals, pumps, compressors,
and other equipment).
A generalized flow diagram depicting emissions sources is illustrated in Figure
7. Estimates of broad classes of controlled emissions from a 100,000 BPD TOSCO
II facility are presented in Table 25. The results of Table 25 are compared
in Table 2*6 with estimates from other sources (refs. 42,43). The agreement is
good for the hydrocarbon emissions estimates, while the agreement is poorer
for the estimates of pollutant emissions.
The estimates in Table 25 and 26 consider only continuous emissions. Three
types of emissions may be associated with a shale oil facility: continuous,
fugitive, and intermittent. Recent estimates (ref. 33) based on petroleum
43
-------
MAIN SHALE OIL PRODUCTION TRAIN To Acid G»i
NgpMh* Fiorn Acid
Gai Removal
* Exnloiiver " F'ua ****
MINE
t
• Preheat
4 Flu
eG»
RETORT
(Sea Figure 6)
• To Sulfur I *«
*==; fa,
1 ' 'Retort Gil
Coker Gai,
Naphtha
Add Gai
Removal and
Gai Recovery
Recovery
t
Reildiial
To
• Flua I ^rom ftftl°rt
*Ga, 4 1 '4F|U6GM
COKER
Gai Oi^ HYDRO-
TREATING
Coke
1> Diesel Fuel
(V Fuel Oil
tv Naphtha
I nyoro- i i . i
T Water, '""""8 I II
««« TWater •) T Gal. Naphtha
Shale 'Flue Get Water To Acid Gai
llturijcor A f. .
.... T Removal
Naiihtha 1
^c
- •*>
,/C4
Fuel
Hydrogen
Production
1 V Water '
Water
Water
AUXILIARY FACILITIES
B
t
Siient Shale S|
Moliturizer
t t
wnt Shale Sulfur
Dltpoial Plant
t
Steam and
Power
Generation
~(
t
Cooling
Tower
e
t
Raw Water
Waitewater t|OMBi anr|
Treatment Treatment
p
t
Other Units
[e.g., Byproduct
Recovery and
Storage
•Denotn atmospheric emliiion.
Figure 7. Generalized shale oil production scheme.
-------
TABLE 25. EMISSION RATES FOR 100,000 BPD TOSCO II FACILITY
WITH EMISSIONS CONTROLLED WITH BEST AVAILABLE TECHNOLOGY
(REF. 39)
Unit
Ore Storage
Crusher
Raw Shale Preheat
Delayed Coker
Naphtha Hydro genat ion
Gas Oil Hydrogenation
Feed Heater and Fired
Reboiler
Hydrogen Plant
Spent Shale Moisturizer
Sulfur Plant
Utility Boilers and Steam
Superheaters
TOTAL EMISSIONS, 16 /hr
Emissions, Ib/hr
Particulates
26
190
419
3
—
3
21
44
—
108
814
so2
—
—
2038
90
10
26
642
—
128
190
3124
HC
—
—
600
—
—
—
—
—
—
600
NOX
—
—
2355
150
18
158
1074
—
—
321
4076
TABLE 26. COMPARISON OF EMISSIONS ESTIMATES FOR 100,000
BPD TOSCO II FACILITY3
Reference
39 (Table 25)
42
43
Emissions, Ib/hr
Particulates
814
9
1,482
S02
3,124
1,688
2,660
HC
600
548
632
NOX
4,076
594
2,920
Emissions have been scaled up linearly from estimates for a
50,000 BPD facility.
45
-------
refinery operations have considered all these categories and, in addition, have
categorized the hydrocarbon emissions according to hydrocarbon type. These
results are shown in Table 27.
The total continuous emissions estimates agree with estimates for hydro-
carbons presented in Table 26. Intermittent and fugitive emissions categories
are estimated to contribute substantially (73 percent) to the total hydrocarbon
emissions. Photochemically reactive species are estimated to be emitted in
large quantities. Olefins, for example, account for 30 percent of the total
emissions. Derivatives including the thiols, are estimated to.account for
only 0.1 percent of the emissions.
In addition to the emissions from shale oil processing facilities, gaseous
organics may be released from the large volume of spent shale solids (ref. 36).
Considerable quantities of polycyclic organic matter (POM) may be present on
the spent solids, and the release of both unsaturated and saturated hydrocarbons
up to C has been demonstrated. The POM is probably sorbed from the retort
vapors on the shale solids prior to solids removal from the retort.
Carcinogenic species such as 3-methylcholanthrene, 7,12-dimethyl
benz[a]anthracene, and benzo[a]pyrene, in addition to noncarcinogenic compounds
such as phenanthrene, fluoranthene, pyrene, and perylene, have been identified
in spent shale solids. Volatile alkanes and olefins as well as POM may be
released from spent shale solids by evaporation or auto-oxidation processes.
Emissions data are lacking, which would allow assessment of this source on
local air quality. The carcinogenicity of various POM presents an additional
potential airborne hazard from shale oil facilities.
The types and quantities of emissions from shale oil facilities remain
poorly defined. Although many of the complex sulfur- and nitrogen-containing
compounds may be emitted by shale oil facilities, better definition of process
conditions is needed before extrapolations to commercial facilities can be
made.
PETROLEUM REFINING
Crude oil is a mixture of many hydrocarbons: paraffins, naphthenes, and
aromatics (ref. 44). The chemical composition of the crude is strongly
dependent on the geological formation of origin. The physical appearance of
the crude may range from tar-like to almost clear.
46
-------
TABLE 27. MAXIMUM HYDROCARBON EMISSION ESTIMATES (Ib/hr)
FOR 100,000 BPD TOSCO II FACILITY (REF. 33)
Emission type
Continuous
Fugitive
Intermittent
TOTAL
GI to 63 paraffins
and benzene
226
107.8
324.4
658.2
64 -fparaffins
H5.4
107.8
569.2
792.4 '
GS +aromatics •
(less benzene)
9
15.4
84.8
109.2
01 e fins
252.4
77.0
343.4
672.8
Derivatives
3.0 b
—
—
3.0
Total
Ib/hr
605.8
308.0
1,321.8
2,235.6
Emissions have been scaled up linearly from estimates for a 50,000 BPD facility.
Estimates suggest 0.8 Ib/hr of CH3SH and 1.6 Ib/hr of COS, CS-, and other mercaptans.
"If it is assumed that half -of the C, to C., paraffins and benzene emissions is
methane, then NMHC emissions amount to 1,907 Ib/hr.
-------
The general objective of petroleum refining is to separate the crude oil
into various fractions, which can be subsequently converted, treated, and
blended into finished products. Five broad types of refineries are classified
below according to their specific objectives (ref. 45):
1. Topping,
2. Fuel oil,
3. Gasoline,
4. Lube oil, and
5. Petrochemical.
In 1970, 253 refineries in the United States processed 12.7 million
barrels per day (BPD) of crude oil (ref. 44). This amounts to a mean production
of 50,000 BPD per refinery. Newer facilities, however, have capacities in
excess of 100,000 BPD. Figure 8 represents a generalized flow diagram for a
hypothetical 100,000 BPD petroleum refinery. The refinery product yields,
depicted in this diagram, are representative of 1974 United States production
averaged across all refineries.
In addition to the auxiliary operations, refining operations generally
include the following four major steps (ref. 44):
1. Separation processes, such as atmospheric and vacuum
distillation and acid gas removal;
2. Conversion processes, such as catalytic cracking, reforming,
light hydrocarbon processing, isomerization, coking, hydro-
cracking, and desulfurization;
3. Treatment to remove sulfur and other undesirable components from
selected streams; and
4. Blending and storage.
The auxiliary operations include such processes as crude desalting, hydrogen
generation, sulfur recovery, water cooling, water treatment, and power genera-
tion. Many of the individual processes are depicted in Figure 8. Detailed
descriptions of these operations are beyond the scope of this report. Specific
process information, however, can be found in the literature (refs. 44,45,46)
and the references therein.
All of the above facilities are potential sources of atmospheric emissions.
Considerable quantities of emissions are released by combustion of fuel-rich
gas streams produced by individual process units, regeneration of catalyst from
48
-------
vo
• • ICjtfOt^llfc
*•'** »'/<«r I nnwiuB online ll.tu m'
| tttottt [taar
Figure 8. Generalized flow diagram for a representative
U. 8. petroleum refinery (ref. 46).
-------
the fluid catalytic cracker (FCC), and evaporation and breathing losses from
storage tanks. Miscellaneous or fugitive sources include loading facilities,
sampling, spillage, and leaks.
The EPA has promulgated New Source Performance Standards (NSPS) applicable
to three refinery operations (ref. 47). The regulations are directed at
limiting sulfur dioxide (SCO emissions from fuel gas combustion systems,
particulate matter and CO from FCC catalyst regenerators, and hydrocarbon
emissions from the storage of petroleum liquids. These three regulations are
summarized as follows.
1. Refinery processes produce large quantities of process gas rich
in both organics and hydrogen sulfide (H_S). The NSPS requires
3
that this fuel gas contain no more than 230 mg/m (165 ppm) of
H-S. This effectively limits the SO. concentration in the
combustion products to 15-20 ppm.
2. The quantity of particulate emissions has been limited to 1
kg/1,000 kg of coke burned in FCC catalyst regeneration. In
addition, the plume opacity must be less than 30 percent, the
CO content of the stack gas must be 500 ppm or less.
3. Petroleum liquid storage vessels with capacities of 40,000
gallons or more are required to have certain types of tank
designs or control equipment to reduce hydrocarbon emissions.
The exact type of equipment required depends on the vapor
pressure of the stored liquid.
Emissions estimates for five of the criteria pollutants may be compared for
a gasoline and a fuel oil refinery in Table 28. This listing suggests that
the bulk of particulate, SO , CO, and NO emissions is associated with fuel
Ji Jv
combustion in the heaters and furnaces employed in the various processes.
Hydrocarbons, however, are indicated to arise primarily from miscellaneous
(fugitive) emissions and storage. The miscellaneous emissions estimates given
in Table 28 were assumed to be 0.1 percent of the throughput weight. The
identity of the individual hydrocarbons, however, was not specified.
The literature provides little definition of the individual air contami-
nants from petroleum refineries. This is somewhat surprising considering the
current well-developed state of petroleum-refining technology. The EPA is
planning-an intensive measurement program to identify and quantify emissions
50
-------
TABLE 28. ATMOSPHERIC EMISSIONS FROM PROCESS MODULES IN A GASOLINE REFINERY AND A FUEL OIL
REFINERY (REF. 45)
Process
Crude distillation*"
Hydrogen plant
llydrotreaters
Naphthab
Middle distillate
Gas oilb
Deasphalted oil
Propane deaaphaltlng unit
Fluid catalytic cracker
CO bollerb
Hydrocracker
Hydrocrackate reformer
Heavy Naphtha reformer
Light ends recovery
IIF alkylatlonb
C,/C, Isonerlzatlon
L
Tall gas treating
Storage
Crude
Motor gasoline
Light fuel oil
Heavy fuel oil
Sludge incineration
Miscellaneous6
TOTAL
Atmospheric emissions, Ib/hr
Gasoline refinery (100,000 BPD)
Partlculates
64.2
35.8
0.4
0.9
6.8
0.6
13.0
2.6
10.2
2.7
34.4
34.6
0.2
Heg.
2.2
0.1
—
—
—
—
7.5
—
216.2
S0a
X
133.3
7.2
0.5
1.3
14.6
0.9
18.4
3.7
62.9
3.9
73.8
74.2
0.3
Neg.
4.7
74. 2d
—
—
—
—
12.5
—
486.4
CO
11.1
7.2
0.3
0.8
1.2
0.5
1.0
2.2
5.3
2.3
5.9
6.0
0.2
Neg.
0.4
0.1
—
—
—
—
2.8
—
47.3
IIC
11.1
7.0
0.5
1.4
1.2
0.9
1.7
3.8
3.3
22.4
6.0
6.0
0.3
Neg.
0.4
0.1
157.3
105.2
2.0
Neg.
0.9
1268.8
1600.3
NO,
X
111.1
143.5
4.3
10.8
11.8
7.0
13.7
29.7
132.7
23.1
59.5
59.8
2.6
—
3.8
0.8
—
—
—
—
10.6
—
624.9
Fuel oil refinery (100.000 BPD)
Partlculates
64.2
c
0.4
—
5.8
0.6
9.9
—
—
—
—
40.8
0.1
—
2.5
0.1
—
—
—
—
7.4
—
131.8
S0a
X
133.3
—
0.6
—
11.2
0.9
14.0
—
—
—
—
84.9
0.1
—
5.2
71. Od
—
—
—
—
12.4
—
333.6
CO
11.1
—
0.3
—
1.9
0.5
1.0
—
—
—
—
7.1
Neg.
—
0.4
0.1
—
—
—
—
2.6
—
25.0
IIC
11.1
—
0.6
—
2.7
0.9
1.8
—
—
—
—
7.1
0.1
—
0.4
0.1
157.3
77.7
11.8
Neg.
0.9
1268.8
1541.3
NO
X
111.1
—
4.6
—
22.6
7.1
14.2
—
—
—
—
70.6
0.6
—
4.3
0.8
— •
—
—
10.6
—
246.5
"Crude IB assumed to have a sulfur content of (MalnJy due to emissions of the tall gas Itself
1.5% (wt). (99. 8t sulfur removal efficiency Is assumed).
Emissions primarily from fuel combustion.
cl',ntrles denoted by blanks " " are not
applicable.
Rased on 0.1Z of refinery capacity.
-------
of individual chemical species from petroleum refineries. Some of the
preliminary work includes a recent report which defines sampling and analytical
strategies for quantifying specific hazardous components in petroleum refinery
effluents (ref. 46). According to Dale Denny, EPA, Research Triangle Park,
N.C., actual analytical results should be available by late 1977 or early 1978
(personal communication, 1976). Until this comprehensive measurement program
has been completed, specific emissions estimates must be based on the
scattered analyses of intermediate process streams and final products reported
in the literature.
A characterization of the atmospheric emissions from three refinery
operations was attempted recently using reported process stream analyses. The
three operations include the atmospheric crude still, the fluid catalytic
cracking regenerator, and the sulfur recovery unit. Results from this study
are shown in Table 29 and depict major and minor constituents identified in
process streams from each operation. Species reported as "potentially present"
were not included. Atmospheric emissions from these processes should be of
similar composition as the process streams.
A list has been compiled (ref. 46) of some 475 compounds found in one or
more of 13 selected intermediate petroleum refinery process streams. Table 30
lists the classes of compounds and the corresponding number of individual
species identified or quantified in this survey. For details concerning
streams, species, and concentrations, the referenced report should be consulted.
The composition of process streams intermediate in the production of the
final products was examined above. Analyses of the final products from
petroleum refining should provide insight into the identity and amounts of
miscellaneous and storage emissions from these products. Gasoline, a major
product, is blended, and its composition depends on the season, climate, and
location of the intended market. Analyses of gasoline liquid have been reported
by several workers (refs. 48,49,50). Comprehensive analyses of up to 220
hydrocarbons have been reported for gasoline liquid and vapor (ref. 48).
Alkanes are reported as the dominant class of hydrocarbons in gasoline vapor,
making up to 85 percent of the total. The effects of recent requirements for
52
-------
TABLE 29. REPORTED COMPOSITION OF PRODUCT STREAMS FROM THREE REFINERY OPERATIONS (REF. 46)
Oi
Volume Z
Atmospheric crude still
Light ends
Constituents BP<40* C
Major
°2
H2
CO
en, 0.2
Ctl 1C
f™f. J..J
C3H8 19.6
1C4»10 3l-°
Cj-C- n-alkanes
C.-C.Q paraffins
C,-C,_ cycloparafflns
C,-C,n aroma tic s
Incinerator
Naphtha Distillate Gas oil Topped crude FCC regenerator tail gas from
40-177° C 177-304* C 304-402° C >402° C offgas sulfur recovery
80.2-84.6* 71.1
2.0-5.1* 7.4
0.5
18.7-26.3 18.6
0.0-7.8* 0.1
7.8-13.4* 1.5
16.9-25.7
40.0
40.0
20.0
J AV
C.»-C., paraffins
C..-C,. cycloparaffins
C..-C,. aronatlca
C15'C25
40.0
45.0
15.0
30.0
-------
TABLE 29. REPORTED COMPOSITION OF PRODUCT STREAMS FROM THREE REFINERY OPERATIONS (REF. 46) (con.)
en
Volume %
Atmospheric crude still
Light ends Naphtha Distillate Gas oil Topped crude
Constituents BP<40° C 40-177° C 177-304* C 304-402" C >402° C
C-.-C,- cycloparaffins 50.0
C,,-C._ aroma tics 20.0
>C2, paraffins 20.0
25
>C_, aroma tic s 30.0
Residue 5.0
Minor
so2
COS
cs2
II2S 1.0
Thiols (mercaptans) M).10
Hethanethiol 0.2
Ethanethiol 0.03
2-butnnetlilol 0.02
NO
NO
X
Cyanides (as UCN)
Incinerator
FCC regenerator tail gas from
offgas sulfur recovery
308-2, 190b 0.89
25. 6b
9-190b 0.02
0-2b 0.01
0-12b <.001
60-169b
11-31 Ob
8-394b
67-675b
0.19-0.94b
UC1
0.7
-------
TABLE 29. REPORTED COMPOSITION OF PRODUCT STREAMS FROM THREE REFINERY OPERATIONS (REF. 46) (con.)
Ul
Volume Z
Light ends
Constituents BP<40* C
Aldehydes
Acetic acid
Cyclo-pentane
Cyclo-hexane
Methylcyclohexane
Benzene
Toluene
Xylenes
EthyJ benzene
Isopropyl benzene
1,2,3-trimethyl benzene
1,3,5-trlmetliyl benzene
Atmospheric crude still
Naphtha Distillate Gas oil Topped crude
40-177* C 177-304" C 304-402" C >402° C
0.14-1.3
1.8-10.7
0.35-17.5
0.2-1.2
1.0-7.4
3.5-9.9
0.19-0.93
0.12-0.33
0.56 0.44
0.32-1.34
Incinerator
FCC regenerator tall gas from
offgas sulfur recovery
3-130b
•»d2b
1,2,3,4-tetrahydro-
naphthalene
Naphthalene
Anthracene
Benzanthrncenes
PcrylencB
Ronzo(ghl) perylenes
0.11
0.06
2,070°
15-424°
-------
TABLE 29. REPORTED COMPOSITION OF PRODUCT STREAMS FROM THREE REFINERY OPERATIONS (REF. 46) (con.)
Constituents
Pyrenes
Alkyl pyrenes
Benzo pyrenes
Benzo (a) pyrene
Benzo (e) pyrene
Phenanthrenes
Chryaenes
Bonz fluorenes
Fluoranthenea
Volume %
Atmospheric crude still
Incinerator
Light ends Naphtha Distillate Gas oil Topped crude FCC regenerator tall gaa from
BP<40° C 40-177° C 177-304° C 304-402° C >402° C offgas sulfur recovery
; X*1 40-28,000°
Xd
xd
4-460c
11-3,600°
Xd 400,000°
X4
X*
x<
"Dry basis, volume H.
Units of parts per million by volume.
"Hlnita of micrograma per barrel of charged oil.
Identified but not quantified.
-------
TABLE 30. CLASSES AND NUMBERS OF COMPONENTS IDENTIFIED
IN REFINERY STREAMS (REF. 46)
Acids and anhydrides 47 Hydrocarbons
Amines 2 Aliphatics 94
Olefins 23
Ketones and aldehydes 3 Aromatics 88
Combustion gases 13 phenolg 2Q
Heterocyclics _ . . .. 10
' Polynuclear aromatics 19
Pyridines 25
_ . - Polynuclear aza arenes 34
Pyrroles 1 '
Cyclic sulfides 25 Thiols (mercaptans) 29
Bicyclic sulfides 12 Suifides 24
Thiophenes 14
Cyanides 2
lead-free gasoline have precipitated compositional modifications by petroleum
refiners, which are unclear at this time. In any event, caution should be
observed in using the reported results for estimating hydrocarbon emissions
from miscellaneous sources or gasoline storage.
The types and quantities of gaseous emissions from petroleum refineries
are poorly defined. The surveyed literature indicates the major sulfur-
containing emissions to be S0_, H^S, and thiols, while major nitrogen-
containing emissions include NO and NH_. Although the individual hydro-
2t J
carbons emitted from petroleum refineries have not been reported based on
actual analyses, the major organic emissions are likely to be highly volatile
compounds, Cin and lower. Compositional analyses are available for various
intermediate process streams and final products. This information can be used
in conjunction with vapor pressure data and established emission factors (ref.
4.
51) to estimate atmospheric emissions from various process modules. This
type of theoretical source reconciliation of individual species is difficult
due to the fugitive nature of the majority of hydrocarbon emissions and due
to the limited data base. Comprehensive source and ambient sampling surveys
will be required to verify these estimates.
57
-------
OVERVIEW
Fuel conversion industries include coal gasification, coal liquefaction,
shale oil processing, and petroleum refining. Although the fuel conversion
technology is markedly different in these facilities, many of the same well-
proven operations and processes will be integrated into each fuel production
facility. Table 31 summarizes many of the processes expected to be required
in each fuel production facility. These processes also represent potential
sources of atmospheric emissions from fuel production. Comparison of the
processes in Table 31 suggests that quantification of the emissions from many
petroleum-refining operations can provide a data base for estimation of a
sizable fraction of the atmospheric emissions from other fuel conversion
industries.
Major sources of atmospheric emissions from fuel conversion facilities
are expected to include various combustion operations and miscellaneous (or
fugitive) emissions. Quantitative atmospheric emissions estimates are avail-
able for criteria air pollutants. Table 32 presents a compilation of emissions
estimates from fuel extraction and conversion modules as reported in or cal-
12
culated from the literature. Although a common basis of 10 Btu/day of fuel
output was used, the results are not truly comparable because the final products
are not identical in each case. These results can be summed along with other
related emissions estimates (such as from transportation of raw fuel and ulti-
mate combustion of final products) to assess the total emissions impact on the
atmosphere resulting from utilization of each alternative fuel. Caution should
be exercised in using these first-generation estimates since an appraisal of
their accuracy is currently lacking.
A broad spectrum of sulfur-containing compounds, nitrogen-containing
compounds, and hydrocarbons has been identified from analyses of intermediate
process streams and final products from fuel conversion processes. The
surveyed literature provides a basis for indicating the major anticipated com-
pounds. The same or similar species are expected to be emitted from each fuel
conversion facility. These compounds are listed as follows.
1. Sulfur-containing compounds will include S0_, H-,S, thiols (mercap-
tans), sulfides, and thiophenes.
2. Nitrogen^cpntaining compounds will include NO, N0_, N|U, HCN, and
heterocycles.
58
-------
TABLE 31. POTENTIAL SOURCES OF ATMOSPHERIC EMISSIONS
FROM FUEL CONVERSION FACILITIES
Source Coal
Gasification
Coal Dining and preparation X
Gasifier X
Hydrogen production
(shift reactor) X
Quench and scrubbing unit X
Acid gas removal X
Methanation X
Liquefaction unit
Product separation
Hydro treat ing
Oil shale mining and
preparation
Retort
Coker
Crude desalting
Atmospheric and vacuum
distillation
Catalytic cracking
Catalytic reforming
Light hydrocarbon processing
Isomerization
Rydrocracking
Oxygen plant X
Sulfur plant (tail gas) X
Steam and power generation
(fuel combustion) X
Process heaters (fuel
combustion) X
Cooling towers X
Waste water treatment X
Rain water treatment X
Byproduct recovery X
Blending X
Storage ' X
Vent gas (startup, shutdown,
and upset conditions) X
Miscellaneous (fugitive)
sources X
Spent shale moisturizer
Spent shale disposal
Coal
Liquefaction3
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
"X
X
Shale oil
production
X
X
X
X
X
X
X
X
.
X
X
X
X
X
X
X
X
X
X
X
X
X
Petroleum
refining
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
alt is assumed that a gasification unit is not included with the liquefaction
facility.
59
-------
TABLE 32. ESTIMATED ATMOSPHERIC EMISSIONS FROM FUEL EXTRACTION AND CONVERSION
OPERATIONS ON A BASIS OF 1012 BTU/DAY OUTPUT
Emissions Estimates. Ib/hr
Operation
Extraction
Gas well production
Oil well production
Coal mining, scripd
room and pillar^
Shale mining, surface
room and pillar
Conversion
Petroleum refining*1
Coal gasification*
Shale oil production^
Extraction plus conversion
Gas
Petroleum
Coal (gasification)l
Shale oilB
Particulates
8
47
496 (633)
258 (3.500)
2,717
546
513
mk
1,373
a
560
1,146
1,919
so2
1,871
538
lie (364)
355 (5,208)
70e
2*
1,117
8,892
4,448
1,871
1,655
9.256
4,450
CO
8
345
95* (109)
23 (9,708)
588e
14e
112
NR"
NR"
8
457
221
126
HCa
1,138C
889
18e (24)
7g (1,606)
109e
3«
3,775
28,124
3.406
1,138
4,663
28,148
3,409
N°x
2,625
850
156e (328)
190 (1,788)
963e
23e
1,473
6,516
4,519
2,625
2,323
6,844
4,542
aln each case that allowed a clear distinction, the hydrocarbon emissions estimates are as nonmethane hydro-
carbons (route).
b
Ref 52.
Methane emissions are not included; emissions estimates including methane are 11,375 Ib/hr.
d
Emissions in parentheses include emissions from physical coal cleaning.
Emissions result primarily from vehicular activities In the extraction operation.
Emissions in parentheses include emissions from burning refuse piles.
Methane emissions are not included; emissions estimates including methane are 14.667 (16,292) Ib/hr.
lief. 45; emissions estimates are scaled from a 100,000 BPD gasoline refinery.
Nonhydrocarbon emissions estimates are scaled from the mean of the values reported in Table 17; hydro-
carbon estimates are scaled from the mean of the NMHC values reported In Tables 17 and -18; estimates
are scaled from estimates for a 250 x 106 SCFD facility assuming .- heating value of 1,000 Btu/SCF for
the product SNG.
JNonhydrocarbon emissions estimates are scaled from the mean of the values reported in Table 26;
nonmethane hydrocarbon estimates are scaled from the value reported in Table 27; The assumed heating value
of shale oil is 5.6 x 10° Btu/bbl. ~
wR - not reported.
Coal is assumed to be stripmlned with physical cleaning; although participate and CO emissions were
not reported for gasification facilities, values for petroleum refining have been adopted. :
'Shale is assumed to be mined by room and pillar techniques; although CO emissions were not reported
for shale oil production facilities, values for petroleum refining have been adopted.
60
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3. Organic compounds will include primarily volatile hydrocarbons up
to C-Q. Other organics such as aldehydes, ketones, phenolsj and
POM are expected. The carcinogenicity of various POM presents
an additional airborne hazard.
The extent to which any of these species is released to the atmosphere is
unclear at this time and depends to a large degree on currently undefined
processing details. Comprehensive source and ambient surveys will be required
to identify and quantify gaseous emissions from fuel conversion facilities.
61
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REFERENCES
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is Doing. Chem Engr Prog. June:25-32.
2. McGrath, H. G. 1974. Is Coal Next? Paper presented at Second Conference
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for Oil Shale Development. Environmental Protection Agency Publication
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Coal-Carbonization Products. Bureau of Mines Bulletin No. 606.
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Identification of Distillable Paraffins, Olefins, Aromatic Hydrocarbons,
and Neutral Heterocyclics From Low-Temperature Bituminous Coal Tar.
Bureau of Mines Bulletin No. 637.
62
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12. Shults, W. D. 1976. Preliminary Results: Chemical and Biological
Examination of Coal-Derived Materials. Report No. ORNL/NSF/EATC-18.
13. Swansiger, J. T., F. E. Dickson, and H. T. Best. 1974. Liquid Coal
Compositional Analysis by Mass Spectrometry. Analytical Chemistry,
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14. Hamshar, J. A., H. D. Terzian, and L. J. Scotti. 1974. Clean Fuels
From Coal by the COED Process. Symposium Proceedings: Environmental
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Publication No. EPA 650/2-74-118. p. 147.
15. Magee, E. M., H. J. Hall, and G. M. Varga, Jr. 1973. Potential
Pollutants in Fossil Fuels. Environmental Protection Agency Publication
No. EPA-R2-73-249.
16. Katz, D. L., D. E. Briggs, E. R. Lady, J. E. Powers, M. R. Tek,
B. Williams, and W. E. Lobo. 1974. Evaluation of Coal Conversion
Processes to Provide Clean Fuels. Electric Power Research Institute
Report No. EPRI 206-0-0.
17. Woebcke, H. N. 1973. Hydrogasification of Coal Liquids. Paper
presented at the Clean Fuels From Coals Symposium, September 10-14,
1973. Chicago, Illinois.
18. Johnson, C. A., M. C. Chervenak, E. S. Johanson, H. H. Stotler, 0.
Winter, and R. H. Wolk. 1973. Present Status of the H-Coal Process.
Paper presented at the Clean Fuels From Coal Symposium, September
10-14, 1973. Chicago, Illinois.
19.- Yavorsky, P. M. 1973. Synthoil Process Converts Coal Into Clean
Fuel Oil. Paper presented at the Clean Fuels From Coal Symposium,
September 10-14, 1973. Chicago, Illinois.
20. Perrussec, R. E., W. Hubis, and J. L. Reavis. 1975. Environmental
Aspects of the SRC Process. Paper presented at the EPA Symposium:
Environmental Aspects of Fuel Conversion Technology. December 15-18,
1975. Hollywood, Florida.
21. Furlong, L. E., E. Effron, L. W. Vernon, and E. L. Wilson. 1976.
The Exxon Donor Solvent Process. Chem Engr Prog. August, 1976. p.69.
22. Magee, E. M. 1976. Evaluation of Pollution Control in Fossil Fuel
Conversion Processes. Environmental Protection Agency Publication
No. EPA 600/2-76-101.
i
23. Perry, H. 1974. Coal Conversion Technology. Chem Engr. July 22,
1974. p. 88.
63
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24. Perry, J. H. (ed.). 1963. Chemical Engineers' Handbook, 4th ed.
McGrax*-Hill, New York. pp. 8-9.
25. Forney, A. J., W. P. Haynes, S. J. Gasior, R. M. Kornosky, C. E. Schmidt,
and A. G. Sharkey. 1975. Trace Element and Major Component Balances
Around the Synthane PDU Gasifier. Pittsburgh Energy Research Center,
Report No. PERC/TPR-75/1.
26. Forney, A. J., W. P. Haynes, S. J. Gasior, G. E. Johnson, and J. P.
Strakey, Jr. 1974. Analyses of Tars, Chars, Gases, and Water Found in
Effluents From the Synthane Process. Symposium Proceedings: Environmental
Aspects of Fuel Conversion Technology. Environmental Protection Agency
Publication No. EPA 650/2-74-118. p. 107.
27. Gasior, S. J., A. J. Forney, W. P. Haynes, and R. F. Kenny. 1974.
Fluidized-Bed Gasification of Various Coals With Air-Steam Mixtures
to Produce a Low-Btu Gas. Paper presented at 78th National AIChE
Meeting, Salt Lake City, Utah. August 18-21, 1974.
28. Robson, F. L., and A. J. Giramonti. 1974. The Environmental Impact of
Coal-Based Advanced Power Generating Systems. Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology. Environmental
Protection Agency Publication No. EPA 650/2-74-118. p. 237.
29. Gillmore, D. W., and A. J. Liberatore. 1975. Pressurized, Stirred,
Fixed-Bed Gasification. Paper presented at the EPA Symposium:
Environmental Aspects of Fuel Conversion Technology. December 15-18,
1975. Hollywood,. Florida.
30. Farnsworth, J. F., .D. M. Mitsak, and J. F. Kamody. 1974. Clean
Environment With Koppers-Totzek Process. Symposium Proceedings:
Environmental Aspects of Fuel Conversion Technology. Environmental
Protection Agency Publication No. EPA 650/2-74-118. p. 115.
31. Hamersma, J, W., and S. R. Reynolds. 1975. Review of Process Measure-
ments for Coal Gasification Processes. TRW Document No. 24916-6018-RU-OO.
32. Kalfadelis, C. D., E. M. Magee, G. E. Milliman, and T. D. Searl.
1975. Evaluation of Pollution Control in Fossil Fuel Conversion Processes:
Analytical Test Plan. Environmental Protection Agency Publication No.
EPA 650/2-74-0091. _
•''«•• '*
33. Nordsieck, R., E.. A. Berman, J. Harkins, and G. Hidy. 1976. Impact
of Energy Resource Development on Reactive Air Pollutants in the
Western United States. Environmental Research and Technology, Inc.
Final Report, Environmental Protection Agency Contract No. 68-01-2801.
64
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34. Rubin, E. S., and F. C. McMichael. 1974. Some Implications of
Environmental Regulatory Activities on Coal Conversion Processes.
Symposium Proceedings: Environmental Aspects of Fuel Conversion
Technology. Environmental Protection Agency Publication No.
EPA 650/2-74-118. p. 69.
35. Akhtar, S., S. Friedman, and P. Yavorsky. 1975. Environmental Aspects
of Synthoil Process for Converting Coal to Liquid Fuels. Paper
presented at the EPA Symposium: Environmental Aspects of Fuel
Conversion Technology. December 15-18, 1975.
36. Yen, T. F. (ed.). 1976. Science and Technology of Oil Shale. Ann
Arbor Science, Ann Arbor, Michigan.
37. Shale Oil-Process Choices. Chem Engr. May 13, 1974. p. 66.
38. Shale Oil-Not Long Now. Chem Engr. May 13, 1974. p. 62.
39. Hughes, E. E., P. A. Buder, C. F. Fojo, R. G. Murray, and R. K. White.
1975. Oil Shale Air Pollution Control. Environmental Protection Agency
Publication No. EPA 600/2-75-009.
40. Atwood, M. T. 1974. Colony Oil Shale Development Parachute Creek,
Colorado. Symposium Proceedings: Environmental Aspects of Fuel
Coversion Technology. Environmental Protection Agency Publication
No. EPA 650/2-74-118, p. 181.
41. Nevens, T. D., and R. A. Rohrman. 1966. Gaseous and Particulate
Emissions From Shale Oil Operations. Paper presented at ACS Meeting.
Pittsburgh, Pennsylvania.
42. Hittman Associates. 1974. Environmental Impacts, Efficiency, and
Cost of Energy Supplied by Emerging Technologies Tasks 7 and 8.
43. Engineering-Science. 1974. Air Quality Assessment of the Oil Shale
Development Program in the Piceance Creek Basin.
44. Laster, L. L. 1973. Atmospheric Emissions From the Petroleum Refining
Industry. Environmental Protection Agency Publication No. EPA
650/2-73-017.
45. Cavanaugh, E. C., J. D. Colley, P. S. Dzierlenga, V. M. Felix,
D. C. Jones, and T. P. Nelson. 1975. Environmental Problem Definition
for Petroleum Refineries, Synthetic Natural Gas Plants, and Liquified
Natural Gas Plants. Environmental .Protection Agency Publication No.
EPA 600/2-75-068.
65
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46. Bombaugh, K. J., E. C. Cavanaugh, J. C. Dickerman, S. L. Keil,
T. P. Nelson, M. L. Owen, and D. D. Rosebrook. 1976. Sampling
and Analytical Strategies for Compounds in Petroleum Refinery Streams,
Volume II. Environmental Protection Agency Publication No. EPA
600/2-76-0126.
47. U.S. Environmental Protection Agency. 1974. Background Information
for New Source Performance Standards: Petroleum Refineries.
Environmental Protection Agency Publication No. EPA 450/2-74-003.
48. Mayrsohn, H., and J. H. Crabtree. 1976. Source Reconciliation of
Atmospheric Hydrocarbons. Atmospheric Environment 10. p. 137.
49. Laity, J. L., and J. B. Maynard. 1972. The Reactivities of
Gasoline Vapors in Photochemical Smog. Journal of the Air Pollution
Control Association 22. p. 100.
50. Maynard, J. B., and W. N. Sanders. 1969. Determination of the
Detailed Hydrocarbon Composition and Potential Atmospheric
Reactivity of Full-Range Motor Gasolines. Journal of the Air
Pollution Control Association 19. p. 505.
51. Compilation of Air Pollutant Emission Factors. 1973. Environmental
Protection Agency Publication No. AP-42.
52. Cavanaugh, E. C., G. M. Clancy, J. D. Colley, P. S. Dzierlenga,
V. M. Felix, D. C. Jones, and T. P. Nelson. 1976. Atmospheric
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Publication No. EPA 600/2-76-064.
66
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TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-77-104
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
LITERATURE SURVEY OF EMISSIONS ASSOCIATED WITH
EMERGING ENERGY TECHNOLOGIES
5. REPORT DATE
September 1977
6. PERFORMING ORGANIZATION CODE
7. AUTHOR(S)
J. E. Sickles, II, W.C. Eaton, L.A. Ripperton,
and R.S. Wright
8. PERFORMING ORGANIZATION REPORT NO.
3. PERFORMING ORGANIZATION NAME AND ADDRESS
Research Triangle Institute
Research Triangle Park
North Carolina 27709
10. PROGRAM ELEMENT NO.
1NE625 (FY-76)
11. CONTRACT/GRANT NO.
Contract No. 68-02-2258
12. SPONSORING AGENCY NAME AND ADDRESS
Environmental Sciences Research Laboratory-RTF, NC
Office of Research and Development
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND PERIOD COVERED
Interim
14. SPONSORING AGENCY CODE
EPA/600/09
15. SUPPLEMENTARY NOTES
16. ABSTRACT
A literature survey was conducted to address fuel contaminants and atmospheric
emissions from the following energy-related operations: coal gasification, coal
liquefaction, shale oil production, and petroleum refining.
Sulfur and nitrogen found in coal, coal liquid product, shale oil, and
petroleum crude are, for the most part, organically bound. Only coal was found to
have substantial amounts of inorganic contaminants, and this was as pyrite (FeS-).
The sulfur content of most fuels-is less than 5% and occurs as thiols
(mercaptans), sulfides, disulfides, and thiophenes. Nitrogen is usually reported
at less than 2% and occurs as pyridines, pyrroles, indoles, carbazoles, and
benzamides.
Quantitative estimates of criteria air pollutant emissions from energy-related
operations are tabulated. A broad spectrum of sulfur-containing compounds, nitrogen-
containing compounds, and hydrocarbons has been identified from analyses of inter-
mediate process streams .and final products from fuel conversion processes. The
surveyed literature provides a basis for identifying the major emissions. The same
or similar species are expected to be emitted from each fuel conversion facility.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.IDENTIFIERS/OPEN ENDED TERMS
c. COSATI FkM/Groop
* Air pollution
* Energy
* Sources
* Reviews
13B
05B
18. DISTRIBUTION STATEMENT
RELEASE TO PUBLIC
19. SECURITY CLASS
UNCLASSIFIED
21* IMQ. \Jr*
75
20. SECURITY CLASS (Thispage)
UNCLASSIFIED
22. PRICE
EPA Form 2220-1 (9-73)
67
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